tag:blogger.com,1999:blog-74124792920160089332024-03-13T19:11:57.573-07:00petroleum, crude oilUnknownnoreply@blogger.comBlogger50125tag:blogger.com,1999:blog-7412479292016008933.post-9473963392953074042010-11-18T06:22:00.001-08:002010-11-18T06:22:21.513-08:00Glossary Of Environmental Science<h4><a href="http://rocksfossils.info/air-mass/glossary-of-environmental-science.html"></a></h4> <p> </p> <p>Corporate Social Responsibility integration of social and environmental policies into day-to-day corporate business.</p> <p>covenants formal agreements or contracts, often between government and industry sectors. The national packaging covenant and sustainability covenants are examples of voluntary covenants with a regulatory underpinning. Land covenants protect land for wildlife into the future.</p> <p>crop coefficient (Kc) (water management) a variable used to compute the evapotranspiration of a plant crop based on that of a reference crop.</p> <p>crop evapotranspiration (ETc) (water management) is the crop water use the regular water withdrawal.</p> <p>crop rotation (crop sequencing) the practice of growing a series of dissimilar types of crops in the same space in sequential seasons for various benefits such as to refrain the build up of pathogens and pests that often occurs when one species is continuously cropped.</p> <p>crude oil naturally occurring mixture of hydrocarbons under normal temperature and pressure.</p> <p>cullet the term used to describe crushed glass that is suitable for recycling by glass manufacturers.</p> <p>cultural eutrophication – the process that speeds up natural eutrophication because of human activity.</p> <p>cultural services the non-material benefits of ecosystems including refreshment, spiritual enrichment, knowledge, artistic satisfaction.</p> <p>culture ECM altering existing mass media to criticise itself (e.g. defacing advertisements with an substitute message). Public activism opposing commercialism as tiny more than propaganda for established interests, and the attempt to find substitute expression.</p> <p>culvert drain that passes under a road or pathway, might be a pipe or other conduit.</p> <p>cut and fill removing soil from one place to another, generally mechanically.</p> <p>cyanobacteria (Cyanophyta or blue-green algae) a phylum of bacteria that obtain their energy through photosynthesis.</p> <p>cyclone intense low pressure weather systems; mid-latitude cyclones are atmospheric circulations that rotate clockwise in the Southern Hemisphere and anti-clockwise in the Northern Hemisphere and are generally associated with stronger winds, unsettled conditions, cloudiness and rainfall. Tropical cyclones (which are called hurricanes in the Northern Hemisphere) cause cause storm surges in coastal areas.</p> <p>D</p> <p>DDT – a chlorinated hydrocarbon used as a pesticide that is a continual biological pollutant.</p> <p>debt-for-Nature Swap – a financial transaction in which a portion of a developing nation’s foreign debt is forgiven in exchange for local investments in conservation measures.</p> <p>decomposers consumers, mostly microbial, that change dead biological matter into minerals and heat.</p> <p>deforestation – the conversion of forested areas to non-forest land for agriculture, urban use, development, or wasteland.</p> <p>dematerialisation decreasing the consumption of materials and resources while maintaining calibre of life.</p> <p>desalination producing potable or useful water by removing salts from salty or brackish water. This is done by three methods: distillation/freezing; reverse osmosis using membranes and electrodialysis; ion exchange. At present, all these methods are energy intensive.</p> <p>desert an area that receives an average annual precipitation of less than 250 mm (10 in) or an area in which more water is lost than falls as precipitation.</p> <p>desertification – the degradation of land in arid, semi arid and dry sub-humid areas resulting from various climatic variations, but primarily from human activities.</p> <p>detritivore (detritus feeder) – animals and plants that consume detritus (decomposing biological material), and in doing so contribute to decomposition and the recycling of nutrients.</p> <p>detritus – non-living particulate biological fabric (as opposed to dissolved biological material).</p> <p>developing countries development of a country is measured using a mix of economic factors (income per capita, GDP, degree of contemporary infrastructure (both physical and institutional), degree of industrialisation, proportion of economy devoted to agriculture and natural resource extraction) and social factors (life expectancy, the rate of literacy, poverty). The UN-produced Human Development Index (HDI) is a compound indicator of the above statistics. There is a strong correlation between low income and high population growth, both within and between countries. In developing countries, there is low per capita income, widespread poverty, and low capital formation. In developed countries there is continual economic growth and a relatively high standard of living. The term is rather value-laden and prescriptive as it implies a natural transition from ndeveloped to eveloped. Even though poverty and physical deprivation are clearly undesirable, it does not follow that it is therefore desirable for ndeveloped economies to move towards affluent Western-style eveloped free market economies. We have tended to use the terms ndustrialised and on-industrialised even though these too can be misleading.</p> <p>dfE design for the environment; dfE thinks about ‘cradle to grave’ costs and benefits associated with fabric acquisition, manufacture, use, and disposal.</p> <p>dfM design for manufacturing; designing products in such a way that they are simple to manufacture.</p> <p>dfS design for sustainability; an integrated design approach aiming to achieve both environmental calibre and economic efficiency through the redesign of industrial systems.</p> <p>dfX design for assembly/disassembly, re-use. recycle.</p> <p>dieback (arboriculture) a condition in trees or woody plants in which peripheral parts are killed, either by parasites or due to conditions such as acid rain.</p> <p>dietary energy supply food acquirable for human consumption, generally expressed in kilocalories per mortal per day.</p> <p>dioxin – any one of a number of chemical compounds that are continual biological pollutants and are carcinogenic.</p> <p>distributed water (water management) bought water supplied to a user; this is generally through a reticulated mains system (but also through pipes and open channels, irrigation systems supplied to farms).</p> <p>diversion rate (waste disposal) the proportion of a potentially useful fabric that has been diverted out of the waste disposal stream and therefore not directed to landfill.</p> <p>divertible resource (water management) the proportion of water runoff and recharge that can be accessed for human use.</p> <p>downcycling (waste management) recycling in which the calibre of an item is diminished with apiece recycling.</p> <p>downstream those processes occurring after a specific activity e.g. the transport of a manufactured product from a works to the wholesale or retail outlet cf. upstream.</p> <p>drainage (water management) that part of irrigation or rainfall that runs off an area or is lost to deep percolation.</p> <p>drawdown (water management) drop in water level, generally applied to wells or bores.</p> <p>dredging – (water management) the repositioning of soil from an aquatic environment, using specialized equipment, in order to initiate infrastructural and/or ecological improvements.</p> <p>drift net – a type of fishing net used in oceans, coastal seas and freshwater lakes.</p> <p>drinking water (potable water) water fit for human consumption in accordance with World Health Organisation guidelines.</p> <p>drip irrigation (water management) a drip hose put approach the plant roots so minimising deep percolation and evaporation.</p> <p>driver (ecology) any natural or human-induced bourgeois that directly or indirectly causes a change in an ecosystem. A direct driver is one that unequivocally influences ecosystem processes and that can be measured.</p> <p>drop-off centre (waste management) a location where discarded materials can be left for recycling.</p> <p>drought an acute water shortage relative to availability, supply and demand in a specific region. An extended period of months or years when a region notes a deficiency in its water supply. Generally, this occurs when a region receives consistently below average precipitation.</p> <p>dryland salinity – (water management) accumulation of salts in soils, soil water and ground water; might be natural or induced by land clearing</p> <p>E</p> <p>eco- – a prefix now added to many words indicating a general consideration for the environment e.g. ecohousing, ecolabel, ecomaterial.</p> <p>eco-asset a biological calibre that provides financial value to private land owners when they are maintained in or restored to their natural state.</p> <p>ecolabel – seal or logo indicating a product has met a certain environmental or social standards.</p> <p>ecological deficit – of a country or region measures the amount by which its Ecological Footprint exceeds the ecological capacity of that region.</p> <p>Ecological Footprint (Eco-footprint, Footprint) a degree of the area of biologically productive land and water needed to produce the resources and absorb the wastes of a population using the prevailing technology and resource management schemes; a degree of the consumption of renewable natural resources by a human population, be it that of a country, a region or the whole world given as the total area of productive land or sea required to produce all the crops, meat, seafood, wood and fibre it consumes, to sustain its energy consumption and to give space for its infrastructure.</p> <p>ecological niche – the surroundings of a species or population within its ecosystem.</p> <p>ecological succession – the more-or-less predictable and orderly changes in the composition or structure of an ecological community with time.</p> <p>ecological sustainability – the capacity of ecosystems to preserve their fundamental processes and operate and to retain their biological diversity without impoverishment.</p> <p>ecologically sustainable development – using, conserving and enhancing the human community’s resources so that ecological processes, on which all life depends, can be maintained and enriched into the future.</p> <p>ecology – the scientific study of living organisms and their relationships to one another and their environment; the scientific study of the processes regulating the distribution and abundance of organisms; the study of the design of ecosystem structure and function.</p> <p>economic externalities costs or benefits that are not borne by the producer or supplier of a good or service. In many environmental situations environmental deterioration might be caused by a few while the cost is borne by the community; examples would include overfishing, pollution (e.g. production of greenhouse emissions that are not compensated for in any way by taxes etc.), the environmental cost of land-clearing etc.</p> <p>ecoregion – (bioregion) the next smallest ecologically and geographically defined area beneath “realm” or “ecozone”.</p> <p>ecosystem boundary the spatial delimitation of an ecosystem generally based on discontinuities of organisms and the physical environment.</p> <p>ecosystem services – the role played by organisms, without charge, in creating a healthy environment for human beings, from production of oxygen to soil formation, maintenance of water calibre and much more. These services are now generally divided into four groups, supporting, provisioning, regulating and cultural.</p> <p>ecosystem – a dynamic complex of plant, animal and microorganism communities and their non-living environment all interacting as a functional unit.</p> <p>e-cycling recycling electronic waste.</p> <p>effective rainfall the volume of rainfall passing into the soil; that part of rainfall acquirable for plant use after runoff, leaching, evaporation and foliage interception.</p> <p>energy efficiency – using less energy to supply the same level of energy service.</p> <p>effluent – a discharge or emission of liquid, gas or other waste product.</p> <p>El Nio – a warm water current which periodically flows southwards along the coast of Ecuador and Peru in South America, replacing the generally cold northwards flowing current; occurs once each five to seven years, generally during the Christmas season (the study refers to the Christ child); the opposite phase of an El Nio is called a La Nia.</p> <p>embodied energy – the energy expended over the entire life cycle of a good or service cf. emergy.</p> <p>emergent property a property that is not evident in the individual components of an thing or system.</p> <p>emergy nergy memory all the acquirable energy that was used in the work of making a product directly and indirectly, expressed in units of one type of acquirable energy (work previously done to supply a product or service); the energy of one type required to make energy of another.</p> <p>emission standard – a level of emissions that, under law, might not be exceeded.</p> <p>emissions intensity emissions expressed as quantity per monetary unit.</p> <p>emissions trading see carbon trading.</p> <p>emissions – substances such as gases or particles discharged into the region as a result of natural processes of human activities, including those from chimneys, elevated point sources, and tailpipes of motor vehicles.</p> <p>endangered species a species which is at risk of fitting extinct because it is either few in number, or threatened by changing environmental or predation parameters.</p> <p>energetics the study of how energy flows within an ecosystem: the routes it takes, rates of flow, where it is stored and how it is used.</p> <p>energy – a property of all systems which can be turned into heat and measured in heat units.</p> <p>* acquirable energy energy with the potential to do work (exergy);</p> <p>* delivered energy energy delivered to and used by a household, generally gas and electricity;</p> <p>* direct energy – the energy being currently used, used mostly at domestic (delivered energy) and for fuels used mainly for transport;</p> <p>* embodied energy – t the energy expended over the entire life cycle of a good or service OR the energy involved in the extraction of basic materials, processing/manufacture, transport and disposal of a product OR the energy required to supply a good or service;</p> <p>* geothermal energy heat emitted from within the Earth crust as hot water or steam and used to generate electricity after transformation;</p> <p>* hydro energy potential and kinetic energy of water used to generate electricity;</p> <p>* indirect energy the energy generated in, and accounted for, by the wider economy as a consequence of an agent actions or demands;</p> <p>* kinetic energy – the energy possessed by a body because of its motion;</p> <p>* nuclear energy – energy released by reactions within atomic nuclei, as in nuclear fission or fusion (also called atomic energy);</p> <p>* operational energy the energy used in carrying out a specific operation;</p> <p>* potential energy the energy possessed by a body as a result of its position or condition e.g. coiled springs and charged batteries have potential energy;</p> <p>* primary energy forms of energy obtained directly from nature, the energy in raw fuels(electricity from the grid is not primary energy), used mostly in energy statistics when compiling energy balances;</p> <p>* solar energy solar irradiation used for hot water production and electricity generation (does not include passive solar energy to heat and cool buildings etc.);</p> <p>* secondary energy primary energies are transformed in energy conversion processes to more convenient secondary forms such as electrical energy and cleaner fuels;</p> <p>* stationary energy that energy that is other than transport fuels and fugitive emissions, used mostly for production of electricity but also for manufacturing and processing and in agriculture, fisheries etc.;</p> <p>* tidal/ocean/wave energy mechanical energy from water movement used to generate electricity;</p> <p>* useful energy acquirable energy used to increase system production and efficiency;</p> <p>* wind energy kinetic energy of wind used for electricity generation using turbines</p> <p>energy bookkeeping measuring value by the energy input required for a good or service. A form of bookkeeping that builds in a degree of our affect on nature (rather than being restricted to human-based items).</p> <p>energy audit – a systematic gathering and analysis of energy use information that can be used to determine energy efficiency improvements. The Australian and New Sjaelland Standard AS/NZS 3598:2000 Energy Audits defines three levels of audit.</p> <p>Energy Footprint – the area required to supply or absorb the waste from coal, oil, gas, fuelwood, nuclear energy and hydropower: the Fossil Fuel Footprint is the area required to sequester the emitted CO2 taking into statement CO2 absorption by the sea etc.</p> <p>energy management – A program of well-planned actions aimed at reducing energy use, recurrent energy costs, and detrimental greenhouse gas emissions.</p> <p>energy recovery the productive extraction of energy, generally electricity or heat, from waste or materials that would otherwise have gone to landfill.</p> <p>energy-for-land ratio – the amount of energy that can be produced per hectare of ecologically productive land. The units used are gigajoules per hectare and year, or GJ/ha/yr. For fossil fuel (calculated as CO2 assimilation) the ratio is 100 GJ/ha/yr.</p> <p>enhanced greenhouse effect – the increase in the natural greenhouse effect resulting from increases in atmospheric concentrations of greenhouse gases due to emissions from human activities.</p> <p>ENSO (El Nioouthern Oscillation) a suite of events that occur at the time of an El Nio; at one extreme of the cycle, when the central Pacific Ocean is warm and the atmospheric pressure over Australia is relatively high, the ENSO causes drought conditions over orient Australia cf. El Nio, Southern Oscillation.</p> <p>environment – the external conditions, resources, stimuli etc. with which an organism interacts.</p> <p>environmental flows – river or creek water flows that are allocated for the maintenance of the waterway ecosystems.</p> <p>environmental indicator – physical, chemical, biological or socio-economic degree that can be used to assess natural resources and environmental quality.</p> <p>environmental movement (environmentalism) – a term that sometimes includes the conservation and green movements; a diverse scientific, social, and political movement. In general terms, environmentalists suggest the sustainable management of resources and stewardship of the natural environment through changes in public policy and individual behavior. In its recognition of humanity as a participant in ecosystems, the movement is centered around ecology, health, and human rights.</p> <p>environmental science – the study of interactions among physical, chemical, and biological components of the environment.</p> <p>epidemiology – the study of factors affecting the health and illness of populations, and serves as the foundation and logic of interventions prefabricated in the interest of public health and preventive medicine.</p> <p>erosion – displacement of solids (sediment, soil, rock and other particles) generally by the agents of currents such as, wind, water, or cover by downward or down-slope movement in response to gravity or by living organisms.</p> <p>Escherichia coli (E. coli) a bacterium used as an indicator of soiled contamination and potential disease organisms in water.</p> <p>estuary – a semi-enclosed coastal body of water with one or more rivers or streams flowing into it, and with a free connection to the open sea.</p> <p>ethical consumerism – buying things that are prefabricated ethically i.e. without harm to or exploitation of humans, animals or the natural environment. This generally entails favoring products and businesses that take statement of the greater good in their operations.</p> <p>ethical living adopting lifestyles, consumption and shopping habits that minimise our negative impact, and maximise our positive affect on people, the environment and the economy cf. consumer democracy, sustainable living.</p> <p>eutrophication – the enrichment of waterbodies with nutrients, primarily nitrogen and phosphorus, which stimulates the growth of aquatic organisms.</p> <p>eutrophication – an increase in chemical nutrients, typically compounds containing nitrogen or phosphorus, in an ecosystem.</p> <p>euxenic – with extremely low oxygen cf. anoxic.</p> <p>evaporation water converted to water vapour.</p> <p>evapotranspiration (ET) the water evaporating from the soil and transpired by plants.</p> <p>e-waste – electronic waste, particularly mobile phones, TVs and individualized computers.</p> <p>extended producer responsibility (EPR) (product take-back) – a stipulation (often in law) that producers take back and accept responsibility for the responsible disposal of their products; this encourages the design of products that can be easily repaired, recycled, reused or upgraded.</p> <p>external water footprint the embodied water of imported goods cf. internal water footprint.</p> <p>externality (environmental economics) by-products of activities that affect the well-being of people or alteration the environment, where those impacts are not reflected in market prices. The costs (or benefits) associated with externalities do not enter standard cost bookkeeping schemes. The environment is often cited as a negatively affected externality of the economy (see economic externality).</p> <p>extinction event – (mass extinction, extinction-level event, ELE) – a sharp decrease in the number of species in a relatively short period of time.</p> <p>extinction – the cessation of existence of a species or group of taxa, reducing biodiversity.</p> <p>F</p> <p>feedback flow from the products of an action back to interact with the action.</p> <p>feedlot (feedyard) – a type of Confined Animal Feeding Operation (CAFO) (also known as “factory farming”) which is used for finishing livestock, notably beef cattle, prior to slaughter.</p> <p>fertigate apply fertiliser through an irrigation system.</p> <p>fertility rate – number of live births per 1,000 women aged 15 to 44 years cf. birth rate, mortality rate.</p> <p>fertilizers (also spelled fertilisers) – compounds given to plants to promote growth; they are generally applied either through the soil, for uptake by plant roots, or by foliar feeding, for uptake through leaves.</p> <p>flyway – the flight paths used in bird migration. Flyways generally span over continents and often oceans.</p> <p>food chain (food webs, food networks and/or trophic networks) – describe the feeding relationships between species within an ecosystem.</p> <p>food miles – the emissions produced and resources needed to transport food and drink around the globe.</p> <p>food security – global food security refers to food produced in adequate quantity to meet the full stipulations of all people i.e. total global food supply equals the total global demand. For households it is the capability to purchase or produce the food they need for a healthy and active life (disposable income is a crucial issue). Women are typically gatekeepers of household food security. For national food security, the focus is on adequate food for all people in a nation and it entails a combination of national production, imports and exports. Food security always has components of production, access and utilisation.</p> <p>Footprint (Ecological Footprint) in a very general environmental sense a “footprint” is a degree of environmental impact. However, this is generally expressed as an area of productive land (the footprint) needed to counteract the impact.</p> <p>forage – the plant fabric (mainly plant leaves) ingested by grazing animals.</p> <p>forest land with a canopy cover greater than 30%.</p> <p>fossil fuel – any hydrocarbon deposit that can be burned for heat or power, such as coal, oil and natural gas (produces carbon dioxide when burnt); fuels formed from once-living organisms that have become fossilized over geological time.</p> <p>fossil water groundwater that has remained in an aquifer for thousands or millions of years; when geologic changes seal the aquifer preventing further replenishment, the water becomes trapped inside and is then referred to as fossil water. Fossil water is a limited resource and can only be used once.</p> <p>freegan – a mortal using substitute strategies for living based on limited participation in the conventional economy and minimal consumption of resources. Freegans embrace community, generosity, social concern, freedom, cooperation, and sharing – in opposition to materialism, moral apathy, competition, conformity, and greed. The most notorious freegan strategy is “urban foraging” or “dumpster diving”. This technique involves rummaging through the nonsense of retailers, residences, offices, and other facilities for useful goods. The word freegan is compounded from “free” and “vegan”. cf. affluenza, froogle.</p> <p>freon – DuPont’s trade study for its odourless, colorless, nonflammable, and noncorrosive chlorofluorocarbon and hydrochlorofluorocarbon refrigerants, which are used in air conditioning and refrigeration systems Fair trade – a guarantee that a clean price is paid to producers of goods or services; it includes a range of other social and environmental standards including country standards and the right to form unions.</p> <p>freshwater – water containing no meaningful amounts of salt; potable water suitable for all normal uses cf. potable water.</p> <p>front (weather) the boundary between warm (high pressure) and cold (low pressure) <a href="http://airmasses.net">air masses</a>.</p> <p>froogle – a play on the word frugal, referring to people who lead low-consumption life-styles: a mortal who is part of a new movement towards self-sufficiency and waste-reduction reached by bartering goods and services particularly through the internet, making their own products, soap, clothes, and breeding chickens and goats, growing their own food, baking their own bread, harvesting their own water and energy, and helping to develop a sense of community. Sometimes referring to people who have prefabricated a resolution to only purchase essentials for a specific period of time cf. freegan, affluenza.</p> <p>fugitive emissions – in the context of the National Greenhouse Gas Inventory, these are greenhouse gases emitted from fuel production itself including, processing, transmission, storage and distribution processes, and including emissions from oil and natural gas exploration, venting, and flaring, as well as the mining of black coal.</p> <p>full-cost pricing – the pricing of commercial goodsuch as electric powerhat includes not only the private costs of inputs, but also the costs of the externalities required by their production and use cf. externality.</p> <p>G</p> <p>G8 – The Group of Eight is an international forum for the world’s major industrialised democracies that emerged following the 1973 oil crisis and subsequent global recession. It includes Canada, France, Germany, Italy, Japan, Russia, the UK and the US which represents about 65% of the world economy.</p> <p>Gaia speculation – an ecological speculation that proposes that living and nonliving parts of the soil are a complex interacting system that can be thought of as a single organism.</p> <p>gene pool – the total set of one-of-a-kind alleles in a species or population.</p> <p>generalist species – those healthy to thrive in a wide variety of environmental conditions and can make use of a variety of different resources.</p> <p>gene – a locatable region of genomic sequence, corresponding to a unit of inheritance, which is associated with regulatory regions, recorded regions and/or other functional sequence regions.</p> <p>genetic diversity – one of the three levels of biodiversity that refers to the total number of genetic characteristics.</p> <p>greenhouse effect – the process in which the emission of infrared irradiation by the region warms a planet’s surface.</p> <p>greenhouse gas – components of the region that contribute to the greenhouse effect.</p> <p>green manure – a type of cover crop grown primarily to add nutrients and biological matter to the soil.</p> <p>Green Revolution – the ongoing transformation of agriculture that led in some places to meaningful increases in agricultural production between the 1940s and 1960s.</p> <p>groundwater – water located beneath the ground surface in soil pore spaces and in the fractures of lithologic formation.</p> <p>garden organics – organics derived from garden sources e.g. prunings, grass clippings.</p> <p>genetic engineering – general term covering the use of various experimental techniques to produce molecules of DNA containing new genes or novel combinations of genes, generally for insertion into a host cell for cloning; the technology of preparing recombinant DNA in vitro by slicing up DNA molecules and splicing together fragments from more than one organism; the modification of genetic fabric by man that would otherwise be subject to the forces of nature only.</p> <p>genome the total genetic composition of an organism</p> <p>geosphere – the solid part of planet Earth, the main divisions being the crust, mantle, and liquid core. The lithosphere is the part of the geosphere that consists of the crust and upper mantle.</p> <p>geothermal energy – energy derived from the natural heat of the soil contained in hot rocks, hot water, hot brine or steam.</p> <p>global acres see global hectares.</p> <p>global dimming a reduction in the amount of direct solar irradiation reaching the surface of the soil due to light diffusion as a result of air pollution and increasing levels of cloud. A phenomenon of the final 3050 years.</p> <p>economic globalization – the emerging international economy characterized by free trade in goods and services, unrestricted capital flows and more limited national powers to control domestic economies.</p> <p>global hectares – acres/hectares that have been adjusted according to world average biomass productivity so that they can be compared meaningfully crossways regions; 1 global hectare is 1 hectare of biologically productive space with world average productivity.</p> <p>global warming potential – a system of multipliers devised to enable warming effects of different gases to be compared.</p> <p>global warming the observable increase in global temperatures considered mainly caused by the human induced enhanced greenhouse effect trapping the Sun heat in the Earth atmosphere.</p> <p>globalisation the expansion of interactions to a global or worldwide scale; the increasing interdependence, integration and interaction among people and organisations from around the world. A general term, used since the mid 1940s, referring to a mix of economic, social, technological, cultural and political interrelationships.</p> <p>glyphosate the active ingredient in the herbicide RoundupTM.</p> <p>governance refers to the decision-making procedure – who makes decisions, how they are made, and with what information: the structures and processes for collective decision-making involving governmental and non-governmental actors.</p> <p>green structure – building design that moves towards self-sufficiency sustainability by adopting circular metabolism.</p> <p>green design – environmentally sustainable design.</p> <p>green power – Electricity generated from clean, renewable energy sources (such as solar, wind, biomass and hydro power) and supplied through the grid.</p> <p>green products and services – products or services that have a lesser or reduced effect on human health and the environment when compared with competing products or services that serve the same purpose. Green products or services might include, but are not limited to, those which contain recycled content, reduce waste, conserve energy or water, use less packaging, and reduce the amount of toxics disposed or consumed.</p> <p>green purchasing – purchasing goods and services that minimise impacts on the environment and that are socially just.</p> <p>Green Star a voluntary building rating for green design covering 9 affect categories up to 6 stars which equals world leader.</p> <p>green waste (green biological fabric or green organics, sometimes referred to as reen wealth) – plant fabric discarded as non-putrescable waste – includess tree and shrub cuttings and prunings, grass clippings, leaves, natural (untreated) timber waste and weeds (noxious or otherwise).</p> <p>green (sustainability) like co – a word frequently used to indicate consideration for the environment e.g. green plumbers, green purchasing etc., sometimes used as a noun e.g. the Greens.</p> <p>greenhouse effect – the insulating effect of atmospheric greenhouse gases (e.g., water vapor, carbon dioxide, methane, etc.) that keeps the Earth’s temperature about 60 F (16 C) warmer than it would be otherwise cf. enhanced greenhouse effect .</p> <p>greenhouse gases – any gas that contributes to the greenhouse effect; gaseous constituents of the atmosphere, both natural and from human activity, that absorb and re-emit infrared radiation. Water vapor (H2O) is the most abundant greenhouse gas. Greenhouse gases are a natural part of the region and include carbon dioxide (CO2), methane (CH4, uninterrupted 9-15 yrs with a greenhouse warming potential (GWP) 22 times that of CO2), nitrous oxide (N2O persists 120 years and has a GWP of 310), ozone (O3),hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride.</p> <p>greenlash dramatic changes in the structure and dynamic activity of ecosystems.</p> <p>greenwashing – a derogatory term used to describe companies that portray themselves as environmentally friendly when their commerce practices do not back this up. Generally applies to excessive use of green marketing and packaging when this does not take statement of the total ecological footprint.</p> <p>greenwater water replenishing soil moisture, evaporating from soil, plant and other surfaces, and transpired by plants. In nature the global average amount of rainfall fitting green water is about 60%. Of the green water about 55% falls on forests, 25% on grasslands and about 20% on crops. We can increase green water productivity by rainwater harvesting, increased infiltration and runoff collection. Green water can't be piped or drunk (cannot be sold) and is therefore generally ignored by water management authorities but it is crucial to plants in both nature and agriculture and needs careful management as an important part of the global water cycle.</p> <p>greywater household waste water that has not come into contact with toilet waste; includes water from baths, showers, bathrooms, washing machines, laundry and kitchen sinks.</p> <p>gross primary productivity – total carbon assimilation.</p> <p>groundwater water found below the surface generally in porous rocks, or soil, or in underground aquifers.</p> <p>growth increase in size, weight, power etc.</p> <p>H</p> <p>habitat – an ecological or environmental area that is inhabited by a specific species.</p> <p>hard waste – household nonsense which is not generally accepted into nonsense bins by local councils, e.g. old stoves, mattresses.</p> <p>heat energy derived from the motion of molecules; a form of energy into which all other forms of energy might be degraded .</p> <p>herbicide a chemical the kills or inhibits growth of a plant.</p> <p>herbivory – predation in which an organism known as an herbivore, consumes principally autotrophs such as plants, algae and photosynthesizing bacteria.</p> <p>heterotroph (chemoorganotrophy) – an organism that requires biological substrates to obtain its carbon for growth and development.</p> <p>hierarchy an organisation of parts in which control from the top (generally with few parts), proceeds through a series of levels (ranks) to the bottom (generally of many parts) cf. heterarchy.</p> <p>high density polyethylene (HDPE) – A member of the polyethylene family of plastics and is used to make products such as milk bottles, pipes and shopping bags. HDPE might be coloured or opaque.</p> <p>homoclime a region with the same climate as the one under investigation.</p> <p>horsepower (hp) = 745.7 watts.</p> <p>homeostasis – the property of either an open system or a shut system, particularly a living organism, that regulates its internal environment so as to preserve a stable, fixed condition.</p> <p>Horton overland flow – the tendency of water to flow horizontally crossways land surfaces when rainfall has exceeded infiltration capacity and depression storage capacity.</p> <p>house energy rating – an assessment of the energy efficiency of residential home or unit designs using a 5 star scale.</p> <p>household metabolism – the passage of food, energy, water, goods, and waste through the household unit in a similar way to the metabolic activity of an organism cf. industrial metabolism.</p> <p>humus – biological fabric in soil lending it a bark brown or black colouration.</p> <p>human equivalent (He) – the approximate human regular energy stipulation of 12,500 kJ or its approximate energy generating capacity at basal metabolic rate which is equivalent to about 80 watts (3.47222kWh/day). A 100 watt light bulb therefore runs at 1.25 He.</p> <p>humus semi-persistent biological matter in the soil that can no longer be recognised as tissue.</p> <p>hydrocarbons – chemicals prefabricated up of carbon and hydrogen that are found in raw materials such as petroleum, coal and natural gas, and derived products such as plastics.</p> <p>hydroelectric power – the electrical power generated using the power of falling water.</p> <p>hydrological cycle (water cycle) – the natural cycle of water from evaporation, transpiration in the atmosphere, condensation (rain and snow), and flows back to the ocean (e.g. rivers).</p> <p>hydrosphere – all the Earth’s water; this would include water found in the sea, streams, lakes and other waterbodies, the soil, groundwater, and in the air.</p> <p>I</p> <p>incineration – combustion (by chemical oxidation) of waste fabric to treat or dispose of that waste material.</p> <p>indicator species – any biological species that defines a trait or characteristic of the environment.</p> <p>industrial agriculture – a form of contemporary farming that refers to the industrialized production of livestock, poultry, fish, and crops.</p> <p>Industrial Revolution – a period in the late 18th and primeval 19th centuries when major changes in agriculture, manufacturing, and transportation had a profound effect on socioeconomic and cultural conditions.</p> <p>infiltration movement of water below topsoil to the plant roots and below.</p> <p>infiltration – the process by which water on the ground surface enters the soil.</p> <p>indicators decimal markers for monitoring progress towards desired goals.</p> <p>industrial ecology (term int. Harry Zvi Evan 1973) – the attending that nature produces no waste and therefore provides an example of sustainable waste management. Natural Capitalism espouses industrial ecology as one of its four pillars together with energy conservation, fabric conservation , and redefinition of commodity markets and product stewardship in terms of a service economy. Publications:</p> <p>insecticide – a pesticide used to control insects in all developmental forms.</p> <p>Integrated Pest Management (IPM) – a pest control strategy that uses an array of complementary methods: natural predators and parasites, pest-resistant varieties, cultural practices, biological controls, various physical techniques, and the strategic use of pesticides.</p> <p>intercropping – the agricultural practice of cultivating two or more crops in the same space at the same time.</p> <p>in-stream use – the use of freshwater where it occurs, generally within a river or stream: it includes hydroelectricity, recreation, tourism, scientific and cultural uses, ecosystem maintenance, and dilution of waste.</p> <p>integrated pest management (IPM) pest management that attempts to minimise chemical use by using several pest control options in combination. The goal of IPM is not to eliminate all pests but to reduce pest populations to acceptable levels; an ecologically based pest control strategy that relies heavily on natural mortality factors and seeks out control tactics that disrupt these factors as tiny as possible.</p> <p>integrated product life-cycle management – management of all phases of goods and services to be environmentally friendly and sustainable.</p> <p>inter-generational fairness the intention to leave the world in the ideal doable condition for future generations.</p> <p>Intergovernmental Panel on Climate Change (IPCC) – the IPCC was established in 1988 by the World Meteorological Organization and the UN Environment Programme to supply the scientific and technical foundation for the United Nations Framework Convention on Climate Change (UNFCCC), primarily through the publication of periodic assessment reports.</p> <p>internal water footprint the water embodied in goods produced within a country (although these might be subsequently exported) cf. external water footprint.</p> <p>intrinsic value the value of something that is independent of its utility.</p> <p>irrigation index an efficiency indicator showing degree of match between applied and used water. Best rating = 1, an Ii of 1.5 means an oversupply of water by 50%.</p> <p>irrigation scheduling watering plants according to their needs.</p> <p>irrigation watering of plants, no matter what system is used.</p> <p>ISO 14001- The international standard for companies seeking to certify their environmental management system. International Organisation for Strandardisation (ISO) 14001 standard was first published in 1996 specifying the stipulations for an environmental management system in organization (companies and institutions) with the goal of minimizing harmful effects on the environment and the goal of continual improvement of environmental performance.</p> <p>J</p> <p>joule (J) the basic unit of energy; the equivalent of 1 watt of power radiated or dissipated for 1 second. Natural gas consumption is generally measured in megajoules (MJ), where 1 MJ = 1, 000,000 J. On massive accounts it might be measured in gigajoules (GJ), where 1 GJ = 1 000,000,000 J.</p> <p>K</p> <p>kerbside collection – collection of household useful materials (separated or co-mingled) that are left at the kerbside for collection by local council services .</p> <p>keystone species – a species that has a disproportionate effect on its environment relative to its abundance, affecting many other organisms in an ecosystem and help in determine the types and numbers of various others species in a community.</p> <p>Kyoto Protocol – an international agreement adopted in December 1997 in Kyoto, Japan. The Protocol sets binding emission targets for developed countries that would reduce their emissions on average 5.2 percent below 1990 levels.</p> <p>L</p> <p>land use, Land-use change and forestry (LULUCF) – land uses and land-use changes can act either as sinks or as emission sources. It is estimated that approximately one-fifth of global emissions result from LULUCF activities. The Kyoto Protocol grants celebrations to get emissions credit for certain LULUCF activities that reduce net emissions.</p> <p>landfill- solid waste disposal in which refuse is buried between layers of soil, a method often used to reclaim low-lying ground; the word is sometimes used as a noun to refer to the waste itself.</p> Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-55120814508154498172010-11-15T01:22:00.001-08:002010-11-15T20:44:34.446-08:00GUNUNG BADAK, CIKEPUH-CITISUK, DAN CITIREM, KOMPLEKS PETROTEKTONIK JALUR SUBDUKSI KAPUR JAWA BARAT<span class="sbmLink"> <table cellspacing="1" cellpadding="1"><tbody> <tr> <td class="sbmText">Share this post : </td> <td><a title="Post it to Social!" href="http://social.microsoft.com/en-us/action/create/s/E/?url=http://petroleumcrudeoils.blogspot.com&ttl=Petrotectonic" target="_blank"><img border="0" src="http://www.dotnetscraps.com/dotnetscraps/samples/sbmtool/social.png" /></a></td> <td><a title="Post it to 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href="http://myweb.yahoo.com/myresults/bookmarklet?u=http://petroleumcrudeoils.blogspot.com&t=Petrotectonic" target="_blank"><img border="0" src="http://blogs.msdn.com/blogfiles/rahulso/WindowsLiveWriter/IconsfordifferentSocialBookmarkingSites_B387/yahoo9.png" /></a></td> </tr> </tbody></table> </span> <p> <br /> <br />SARI <br />Kompleks Gunung Badak, Kompleks Cikepuh-Citisuk, dan Kompleks Citirem berada di <br />Teluk Ciletuh, merupakan lokasi dari kumpulan batuan Pra-Tersier. Daerah Teluk <br />Ciletuh berada di Kabupaten Sukabumi, Provinsi Jawa Barat. Batuan Pra-Tersier di <br />Ciletuh dikenal luas sebagai tektonik melange yang terbentuk dari penujaman lempeng <br />Indo-Australia terhadap Eurasia selama kala Kapur- Paleosen. <br />Ini merupakan studi menyeluruh dari kumpulan petrotektonik melalui perangkuman dan <br />analisis penelitian terdahulu (peta geologi dan studi laporan tidak terbit). Data diperoleh <br />melalui pemetaan geologi detil skala 1: 100.000, pengamatan lapangan, analisis <br />petrografi, analisis geokimia (dengan peralatan JEOL superprobe 733), analisis kimia <br />mineral dan pengukuran tekanan dan temperatur. <br />Kompleks Gunung Badak terdiri dari ofiolit (peridotit, gabro dan lava basal), batuan <br />metamorfik (serpentinit, kuarsit, filit, dan sekis), Kompleks Cikepuh-Citisuk disusun <br />batuan beku basa, ultrabasa, dan metamorfik sebagai lava basal, gabro, peridotit, dan <br />sekis, Kompleks Citirem disusun oleh lava basal (struktur bantal dan vesikuler). <br />Ke arah selatan (Gunung Badak menuju Citirem), kompleks ini disusun oleh kerak <br />samudera bagian atas; sebaliknya ke utara Kompleks Ciletuh disusun oleh kerak <br />samudera bagian dalam. Tersingkapnya batuan-batuan Pra-Tersier akibat adanya <br />pengurangan kecepatan penekukan pada masa Eosen-Oligosen Bawah, diimbangi <br />terbentuknya akresi, sehingga hadirnya kompleks melange yang mengandung blokblok <br />batuan ultramafik dan terdiri dari lempeng-lempeng serpentinit dan lava bantal. Di <br />saat bersamaan terjadi obduksi yang menyebabkan proses metamorfisme; pada kala <br />Oligosen Atas, adanya penambahan penekukan yang menyebabkan batuan metamorf <br />mengalami retrograde metamorfism, ditunjukkan dengan hadirnya mineral klorit yang <br />menggantikan aktinolit, albit dan kelompok epidot menggantikan plagioklas pada <br />batuan epidot amfibolit. <br />Kata kunci : Petrotektonik, Ciletuh, Melange, Penunjaman, Gunung Badak. <br /></p> <p>ABSTRACT <br />Gunung Badak, Cikepuh-Citusuk and Citirem Complex is situated in Ciletuh Bay. This <br />location consist of Pre-Tertiary rocks assemblages. Ciletuh Bay region located in <br />Sukabumi Regency, in West Java Province. The Pre-Tertiary rocks at Ciletuh have <br />been widely considered as tectonic mélange, which occured by subduction of Indo- <br />Australian and Eurasian plate during Cretaceous - Paleocene time. <br />This is a comprehensive study of petrotectonic assemblages by the results of <br />summary and analysis of previous research (geological map and unpublished reports). <br />Primary data are obtained from detailed geological mapping on 1: 100000 scale, field <br />observations and petrographic analysis, geochemical analysis (with JEOL superprobe <br />733), mineral chemical analysis, and temperature and stress measurement. <br />Gunung Badak Complex consists of ophiolite (peridotite, gabbro, and pillowed basalt), <br />metamorphic (serpentinite, quartzite, phyllite, and schist), and sedimentary rocks <br />(greywackes, nummulites limestone, black shale, red clay, and polymic breccias). <br />Cikepuh-Citisuk Complex consists of basic, ultrabasic and metamorphic rocks as <br />basaltic lava, gabbro, peridotite, and schist. Citirem Complex consists of thoelitic <br />basaltic lava (pillowed and vesiculars). <br />In southernward (Gunung Badak to Citirem), this complex consists of upper part <br />Oceanic Crust, inversely northward the Ciletuh Area consist inner part Oceanic Crust. <br />Uplifting of pre-Tertiary rocks is due to less of speed in underside Eosen-Oligosen <br />times, in balance by created of accretion, during the present of melange complex that <br />implied blocks of ultramafic rocks and consists of sepernitite plates basaltic lava. In the <br />same time obduction that made metamorphic process, at Upper Oligosen period, the <br />increase of subduction which cause metamorf rocks to go through metamorphism <br />retrogrades, showing by attended of klorite mineral that replaced aktinolit, albit and <br />epidot groups replaced amfibolit epidot rocks. <br />Keywords: Petrotectonic, Ciletuh, Melange, Subduction, Gunung Badak.</p> <p> </p> <p>By</p> Yoal Dianto dan1 Yudih Saamena1 <br />1Fakultas Teknik Geologi, Universitas Padjadjaran, <br />Jl. Raya Bandung Sumedang KM.21 Jatinangor 45363 Telp./Fax (022) 7796545. <br />Email : yoal.dianto@yahoo.co.uk, yudih.saamena@yahoo.com Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-9415837534502649782010-11-11T14:26:00.001-08:002010-11-11T14:26:09.461-08:00Privacy Policy<h3> </h3> <p><ins><ins></ins></ins></p> <p><strong>Your Privacy</strong> <br />Your privacy is important to us. To superior protect your privacy we supply this notice explaining our online information practices and the choices you can make about the way your information is collected and used. To make this notice simple to find, we make it acquirable on our homepage and at each point where personally classifiable information might be requested. </p> <p><strong>Google Adsense and the DoubleClick DART Cookie</strong> <br />Google, as a third celebration advertisement vendor, uses cookies to serve ads on this site. The use of DART cookies by Google enables them to serve adverts to visitors that are based on their visits to this website as well as other sites on the internet.</p> <p>To opt out of the DART cookies you might visit the Google ad and content network privacy policy at the following url http://www.google.com/privacy_ads.html Tracking of users through the DART cookie mechanisms are subject to Google’s own privacy policies.</p> <p>Other Third Celebration ad servers or ad networks might also use cookies to track users activities on this website to degree advertisement effectiveness and other reasons that will be if in their own privacy policies, This site has no access or control over these cookies that might be used by third celebration advertisers. </p> <p><ins><ins></ins></ins></p> <p><strong>Collection of Personal Information</strong> <br />When visiting this site, the IP address used to access the site will be logged along with the dates and times of access. 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You should be aware that the privacy policies of these sites might differ from our own. </p> <p><strong>Changes to this Privacy Statement</strong> <br />The contents of this statement might be modified at any time, at our discretion. </p> <p>If you have any questions regarding the privacy policy of this site then you might contact us at  charifin2@gmail.com</p> Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-38729310342023174392010-11-10T02:37:00.000-08:002010-11-10T02:37:00.559-08:00Error /problems in determining a palaeoenvironmentError in determining a palaeoenvironment can be made due to the following factors:<strong> </strong><div class="entry"> <p><strong>1. Transport</strong></p> <p>This will cause a mixing of faunas from different environment</p> <p>- Reworking of older sediments</p> <p>- Contemporaneous transport</p> <p>- As suspended load.The empty shells of dead foraminifera can be transported hundreds of miles offshore. Result:shallow water forms in deep water deposit</p> <p>- By currents. This may be reflected in species or size sorted assemblages.</p> <p>- By turbidity currents or slides.</p> <p>- Vegetation. Attached living species may be transported over vast distances, when the vegetation is uprooted</p> <p>- Wind. Empty shells of dead foraminifera may be blow land inwards</p> <p><strong>2. Bioturbation</strong></p> <p>The effect of bioturbation is rather minimal. Burrowing organisms may cause the mixing of different assemblages.<strong></strong></p> <p><strong>3. Diagenesis</strong></p> <p>Solution of calcareous test or the calcareous cement of arenaceous species can result in the complete absence of a fossil</p> <p><strong>4. Caving and contamination</strong></p> <p>Different preservation, colour or the degree of abrasion can be clue in determining transported or reworked faunas.</p><p>for more information please see <a href="http://regionalgeology.info/category/foraminifera">foraminifera</a> in http://regionalgeology.info<br /></p> </div>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-58838310528017006212009-02-03T22:16:00.001-08:002009-02-03T22:16:39.012-08:00Introduction geology<h5>From Wikipedia, the free encyclopedia</h5> <p><b>Geology</b> (from Greek: γη, <i>gê</i>, "earth"; and λόγος, <i>logos</i>, "speech" lit. to talk about the earth) is the science and study of the solid matter that constitutes the Earth. Encompassing such things as rocks, soil, and gemstones, geology studies the composition, structure, physical properties, history, and the processes that shape Earth's components. It is one of the Earth sciences. Geologists have established the age of the Earth at about 4.6 billion (4.6x10<sup>9</sup>) years, and have determined that the Earth's lithosphere, which includes the crust, is fragmented into tectonic plates that move over a rheic upper mantle (asthenosphere) via processes that are collectively referred to as plate tectonics. Geologists help locate and manage the Earth's natural resources, such as petroleum and coal, as well as metals such as iron, copper, and uranium. Additional economic interests include gemstones and many minerals such as asbestos, perlite, mica, phosphates, zeolites, clay, pumice, quartz, and silica, as well as elements such as sulfur, chlorine, and helium. Geology is also of great importance in the applied fields of civil engineering, soil mechanics, hydrology, environmental engineering and geohazards.</p> <p>Planetary geology (sometimes known as Astrogeology) refers to the application of geologic principles to other bodies of the solar system. Specialised terms such as <i>selenology</i> (studies of the moon), <i>areology</i> (of Mars), etc., are also in use. Colloquially, <i>geology</i> is most often used with another noun when indicating extra-Earth bodies (e.g. "the geology of Mars").</p> <p>The word "geology" was first used by Jean-André Deluc in the year 1778 and introduced as a fixed term by Horace-Bénédict de Saussure in the year 1779. The science was not included in <i>Encyclopædia Britannica</i><i>'s</i> third edition completed in 1797, but had a lengthy entry in the fourth edition completed by 1809.An older meaning of the word was first used by Richard de Bury to distinguish between earthly and theological jurisprudence.</p> Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-46990820459800984932008-11-28T01:39:00.001-08:002008-11-28T01:39:40.630-08:00FROM NON-ECONOMIC INTO PRODUCING FIELD, A CASE STUDY IN KETALING BARAT FIELD, INDONESIA<p>Convention Bandung 2004 (CB2004) <br />The 33rd Annual Convention & Exhibition 2004 </p> <p>Indonesian Association of Geologist <br />Horizon Hotel, 29-30 Nov, 1 Oct 2004, Bandung </p> <p>FROM NON-ECONOMIC INTO PRODUCING FIELD, <br />A CASE STUDY IN KETALING BARAT FIELD, <br />INDONESIA </p> <p>Bob W.H. Adibrata(1), Y. Hirosiadi(2), E. Septama(3), A. Rachmanto(4) </p> <p>1bobwikan@pertamina.com, 2yosihiro@pertamina.com, Geology Section, Technology Support Division, <br />Pertamina Upstream, Kwarnas Bld 15th Fl, Jl. Medan Merdeka Timur No. 6, Jakarta 10110 INDONESIA <br />3erlangga@pertamina-sumbagteng.com, Exploitation Section, Pertamina DOH Sumbagteng, Bajubang, Jambi <br />36611, INDONESIA <br />4ambar@pertamina-dohsbs.com, Recent address: Exploitation Section, Pertamina DOH Sumbagsel, Prabumulih, <br />Sumatera Selatan, INDONESIA </p> <p>Abstract </p> <p>Focus of this study is re-activity of a non-economic field into production by combining <br />old vintage 2D seismic data with current 3D seismic data, supporting with archival, <br />conventional log data and limited sidewall core and thin section analysis. The <br />reservoir consists of bioclastic wackestone overlying by coral bindstone in the Upper <br />Miocene Equivalent of Baturaja Formation, at Ketaling Barat field, Jambi, Indonesia. <br />The objective of this study is to evaluate and test a multiple attribute analysis <br />whereby carbonate facies can be determined and to characterize the distribution of <br />potential carbonate reservoir. </p> <p>Introduction </p> <p>Ketaling Barat field is located 5 km East of Jambi, Jambi Province, Indonesia (Figure <br />1). Activities in this field started in 1959 by Dutch’s NIAM N.V., by drilling 3 wells, <br />Ketaling 1, 2 and 3, which mainly based on geological field work in the surrounding <br />area. From those three wells, only Ketaling-2 gave respond with gross of 220 bbl fluid <br />per day (95% water). With the unsatisfactory result, this field was then abandoned as <br />a non-economic field for about 40 years. The first 2D seismic data acquisition taken <br />in 1982, and the vintage set was then re-processed in 2000 and re-interpretation was <br />held during the same year, with the result of Ketaling Barat (KTB)-04 that has been <br />drilled in 2001. The appraisal well of KTB-04 gave a significant result of 3600 BOPD, <br />with no water. Lithology variation between KTB-04 and previous wells, confer the <br />idea that there are two different stages in carbonate development in this area, <br />defined as Phase-1 and Phase-2. Phase-1 is platform carbonate where oil produced <br />from KTB-04, and Phase-2 is reefal carbonate, where oil from Ketaling-2 came from. <br />Four other wells has been drilled during 2001-2002 period, KTB-05 (Phase-1 <br />reservoir, 1.5 MMSCF), KTB-06 (Phase-2 reservoir, 420 BOPD, 70 % water, 0.5 <br />MMSCF), KTB-07 (Dry hole), KTB-08 (Phase-1 reservoir, Oil show, Technical <br />problem, P&A). Highly variation in result which represents reservoir heterogeneity, <br />lead to a mini pilot project (2 x 4 sq. km) of 3D seismic acquisition and processing <br />that was conducted in 2003 to enhance reservoir characterization. </p> <p>Improved interpretation has achieved using 3D data volume. The Equivalent of <br />Baturaja Formation can be determined more clearly into two different stages. The two <br />stages, Phase-1 and Phase-2 has been mapped respectively. Phase-1 developed as <br />an isolated platform directly on top of basement, controlled by normal fault, spread out throughout the area with average thickness of 35 meter. Phase-2 developed as <br />reefal build-up facies, distributed mostly in the center of Ketaling Barat field, with <br />average thickness of 45 meter. Paleomorphology also worked as the main control on <br />carbonate development and distribution in the area. </p> Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-82173938001401298962008-11-20T23:19:00.001-08:002008-11-20T23:19:10.995-08:00Dipmeter Surveys (Reef Interpretation )<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Reef Interpretation <br /></span></h2></p><p><span style='font-family:Times'><strong>Introduction<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Buried topography may significantly influence the thickness, sedimentation, and dip attitude of beds overlying topographic features. One of the first stratigraphic applications of dipmeter data was to determine the positions of wells drilled on buried topographic features. The factor contributing to the interpretation of these situations is the drape of beds over the underlying buried topography. Although this chapter deals primarily with reef interpretation, many of its basic principles apply to buried ridges, knobs, and depressions covered in the next chapter. The differences between them lie in the application of the interpretation.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The dip of reef surfaces is interpreted from the drape of sediments over the reef, particularly where the reef underwent considerable vertical growth. Dipmeter data obtained very near the reef or on the reef slope exhibit dip anomalies that help to describe the reef slope. The magnitude of the dip at any point above a reef varies depending on the following:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the slope of the reef surface<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the height of the reef above the surrounding platform<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the distance of the point above the reef surface<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the type of rock above the reef<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the total historical overburden<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the position over the reef at which the measurements were taken (crest, flank, or toe)<br /></span></p><p><a href='javascript:figurewin('../../asp/graphic.asp?code=516&order=0','0')'><br /> </a></p><p><span style='font-size:10pt'><span style='color:blue; text-decoration:underline'>Figure 1</span> shows the cross section of a barrier reef complex.<br /></span></p><p><span style='font-size:10pt'>Dipmeter interpretation will be described for wells drilled<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>in pinnacle reefs overlain by shale<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>in pinnacle reefs overlain by low-compactibility formations<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>on the forereef slope<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>on the crest of the barrier complex<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The dip patterns may be somewhat different in each of these cases because of the relief of the feature as well as the lithology of the enclosing formations.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Well-correlation and dip data have shown that the slopes on reef flanks can vary from 2° or 3° to as high as 45°. As evidenced by current reefs, higher slopes are possible, but are not generally observed in the subsurface. It is possible that erosion of steep and irregular slopes prior to burial produced reef flanks of reduced dip angle. Large accumulations of reef talus material near some reefs may support this premise.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Of the factors influencing the dip above a reef, the most important are reef topography and the compactibility of overlying beds. If all dip patterns above reefs conformed to the same model, interpretation would be straightforward. Unfortunately, identical dip patterns may imply quite different reef slopes in different environments.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=516&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> is a photograph of a pinnacle reef in a Cambrian zone in West Texas. Some significant features show in the enclosing beds. Note the drape of the overlying beds in the flank position with the direction of dip sharply away from the reef mass.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>It is useful to note that subsidence of the mass into the underlying platform has caused dip below the reef to be toward the reef mass itself.<br /></span></p><p><span style='font-size:10pt'>Finally, within the reef there is generally a lack of distinct stratification.<br /></span></p><p><span style='font-family:Times'><strong>Comments on Reef Interpretation<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The tectonic and geological history of an area generally determines a maximum height of buried topography above a reference datum. This is particularly true of reefs, because the controlling conditions for vertical accumulation may prevail over a large portion of a basin.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Further, unfavorable conditions cause cessation of growth over large areas, and the limited vertical height becomes common to many reefs simultaneously. Therefore, a maximum expected height of reef crest above a datum may be well established.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Reef falls, or pinnacles that for whatever environmental reason ceased growth early, may have any thickness less than maximum. The length (and shape) of the slope pattern in wells drilled on the flank position may be interpreted qualitatively as a guide to the vertical size of the reef. "Typical" dipmeter patterns for the area are very useful in this respect.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The accuracy of interpretations discussed in this chapter depend largely upon knowledge of sediment compaction around reefs and other buried topography. The relatively simple procedures employed to estimate compaction may not apply directly to all areas.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Extrapolation of dip assuming a linear slope may be used best where experience with seismic and well-to-well correlations support this approach. Extrapolating updip beyond the elevation geologically possible or likely for a particular feature could be misleading and expensive. The basic concept should prevail, however, and persons employing these basics in their analyses are advised to consider all available data and experience.<br /></span></p><p><strong>Techniques<br /></strong></p><p><span style='font-family:Times; font-size:13pt'><strong>Reef Interpretation</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p><span style='font-size:10pt'>The pattern of drape over a reef may be determined by a number of factors, including</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-size:10pt'>compaction <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>compaction with deposition</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>solution of surrounding salts</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>solution with deposition of overlying sediments</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>gypsum to anhydrite conversion</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>combinations of the above</span><br /> </p><p><span style='font-family:Times'><strong>Compaction</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In most circumstances, compaction plays the key role in causing drape over buried topography. It is useful therefore to refer to a model to understand and interpret the dip patterns.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The simplest model, and one with good independent support from well correlation, is illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=517&order=0','0')'>Figure 1</a> , which shows a simple reef mass of constant slope of 30° surrounded by shale.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>If we know the compaction factor of the shale, and we assume that all shale compaction occurred after deposition and that the reef is rigid, then we can accurately calculate the present attitude of the shale bedding plane.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>For this model it is assumed that present shale thickness is 50% of the original precompaction thickness; therefore, the resulting compaction factor is 0.5.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>From these assumptions we can conclude that the dip of the shale bedding plane is the angle of the tangent, which is 50% of the tangent of the reef angle.</span><br /> </p><p><span style='font-size:10pt'>The equation is</span><br /> </p><p style='margin-left: 36pt'>tan<sup>-1</sup>(0.5 tan 30°) = shale dip = 16.1°<br /></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The general equation is</span><br /> </span></p><p style='margin-left: 36pt'>shale dip = tan<sup>-1</sup> [(1 - C) tan reef dip]<br /></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where:</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>,</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>and</span><br /> </span></p><p style='margin-left: 36pt'>1 - C = compaction<br /></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Solving for the reef dip, which cannot be directly measured, we have</span><br /> </span></p><p style='margin-left: 36pt'>reef dip = tan<sup>-1</sup><span style='font-size:10pt'> </span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>reef dip = tan<sup>-1</sup> </span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>In this example, with a measured shale dip of 16.1°, we can calculate the reef dip to be 30°. Considering the range of local changes in compaction due to lithological changes, locally changing reef slope, or the fact that compaction may not be totally postdepositional, a simple solution is to divide the shale dip by an estimate of compaction.</span><br /> </span></p><p style='margin-left: 36pt'>reef dip<span style='font-size:10pt'> = = 32°</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>As shale-dip values increase, as in the case of very steep-sided reefs, the simplified solution becomes less accurate and the general equation should be used; however, slumping, fracturing, and sliding may render interpretation more difficult and the precision of reef slope less significant.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>In the previous simplistic model where all compaction was assumed to occur after deposition, the theoretical dip pattern would be a constant 16.1°. Where beds are now essentially parallel, they may be considered to have been paralleled during deposition and therefore equally compacted. This model is applicable in these cases.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In general, however, the drape of beds over a reef produces a red pattern on the dipmeter plot if the well is drilled in the flank position. The existence of the red dip patterns implies that compaction cannot be assumed to be postdepositional except over limited intervals where the dip magnitude is relatively constant. In this case, the compaction may only be invisible over short intervals because of the low rate of change of dip with depth. Provided other factors remain constant, reefs with large relief tend to produce long red patterns above; those with low relief produce shorter patterns. In any case, it is the analysis of the red pattern that allows us to calculate the reef slope.</span><br /> </p><p><span style='font-family:Times'><strong>Estimating Height of Nearby Reefs</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Two basic dip patterns have been observed in shale-enclosed reefs. The first is a long, slowly increasing red pattern. The dip of the shale above the reef is some fraction of the reef dip, and the reef dip is estimated using the earlier derived equation. The interval from 1315 to 1365 m shows little dip change, which indicates that it was deposited prior to most of the compaction process. This zone is therefore a candidate for the simple model approach.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The second dip pattern observed in shale-enclosed reefs is characteristic of steep-sided, probably curved surfaces of high-relief pinnacles ( <a href='javascript:figurewin('../../asp/graphic.asp?code=517&order=1','1')'>Figure 2</a> ).</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Statistically, this pattern has two sections. The lower section is characterized by a sharp slope pattern immediately above the reef. The upper section is a long and slowly decreasing slope pattern. Where the sharp slope pattern and the slowly decreasing dip pattern join is the approximate height of the nearby reef.</span><br /> </p><p><span style='font-family:Times'><strong>Estimating the Reef Slope</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The reef slope should be estimated using two methods. First, applying your knowledge of compaction to the upper dip section, calculate the dip. Second, extrapolate the lower red dip pattern to the reef surface. This dip is a good estimate of the reef dip at the contact, but it may not persist over long horizontal distances. If the two dips agree within a few degrees, confidence in the answer is high. If the two dips do not agree within a few degrees, they at least establish a range of possible dip. Knowledge of the seismically defined size and shape should be integrated into the final solution.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Where overlying beds are of low compaction, the overlying dip also is less. For example, a formation with compaction of 20% and a dip over the reef of 4° would imply a reef dip of approximately 20°. In this case the red pattern would not be nearly as striking as in the previous examples.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Some interpreters may be tempted to find the exact depth of the contact, and they may seek a particular tadpole to define the dip of the surface. This approach can give quite erroneous results, because of the local irregularities existing on any weathered surface. These irregularities may be of a size on the order of the borehole diameter.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In this case the dip at the contact would be entirely misleading, and the general dip trend is better defined from dips sufficiently above the surface, because the small features would have been compensated by sedimentation and compaction.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>As a general rule, dip patterns should be extrapolated horizontally in the same order as the vertical length of the pattern. This implies that any single-dip tadpole should not be extrapolated beyond the borehole.</span><br /> </p><p><span style='font-family:Times'><strong>Reef Detrital Material</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Dip within a reef is not generally very well ordered. There is one exception, however: reef detrital material.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Reef detrital material is often found in accumulations near the base of the reef, and dip patterns within this material may have the appearance of foreset bedding.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>This bedding may have dips greater than the reef dip, but the direction should be generally downslope. This information is particularly useful where it supports draping dip in overlying beds and in situations of low reef dip or low compaction.</span><br /> </p><p><span style='font-size:10pt'>The only indication of this detrital material may be from the dip-meter plot, as there is little mineralogical distinction between detritus and the main reef mass. This information may be significant when estimating the depth of the reef top, particularly where the detrital section is quite thin.</span><br /> </p><p><span style='font-family:Times'><strong>Reefs Surrounded by Salt</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Reefs surrounded by salt are not likely to exhibit strong dips in the overlying sediments. If salt solution occurs simultaneously with or subsequent to deposition of these sediments, a dip pattern is produced. This pattern is determined by the rate and timing of the removal of salt. If salt removal commenced after deposition of some of the overlying beds, then these beds would have collapsed to more or less conform to the reef surface. Their dip would then be equal to the reef dip, and a pattern of essentially constant magnitude would be formed. This is illustrated in interval A in <a href='javascript:figurewin('../../asp/graphic.asp?code=517&order=2','2')'>Figure 3</a> .</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>If the beds of interval B were being deposited during the removal of salt, a red pattern over that interval would be produced on the dipmeter plot. Interval B could be expected to thicken in the downdip direction.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The dip pattern in the figure would be further modified by compaction during and after deposition, but the basic pattern would be recognizable. Reef dip in this case would be approximately equal to or slightly greater than the constant dip value of interval A.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>If salt removal occurred contemporaneous with the deposition of some of the overlying beds, most of the interval above the reef would exhibit a red pattern, as illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=517&order=3','3')'>Figure 4</a> . The dip of the reef would approximately equal the trend of the red pattern extrapolated to the reef contact. Extrapolation of red patterns of drape over reef or weathered surfaces is necessary, because dips near the surfaces may be difficult to ascertain due to bedding destruction by fractures, slump, or sliding and local irregularities of the surface.</span><br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>Dipmeter Interpretation</strong></span><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=517&order=4','4')'><span style='font-size:10pt'>Figure 5</span></a><span style='font-size:10pt'> illustrates the dipmeter pattern of a well drilled in the flank position of a reef where salt removal around the reef played a significant role in the final dips of the overlying beds. The pattern may be analyzed as follows:</span><br /> </p><p><br /> </p><p><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Interval A</strong> contains a section of relatively constant dip with an average value of 15° to 18° east. This interval was probably deposited prior to salt removal, and it represents the minimum dip of the reef.</span><br /> </p><p><span style='font-size:10pt'><strong>Interval B</strong> contains a red pattern that indicates the period of salt removal.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Interval C</strong> contains a long, gentle red pattern that finally disappears well above the top of the figure. This pattern is probably a reflection of compaction during deposition, and it would be superimposed on the patterns of intervals A and B.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Because regional dip in this area is less than 1° to the southwest, the consistent east dip above 3900 ft is interpreted as part of the overall drape on the reef. The long drape feature, over 1000 ft in length, suggests that the reef feature is not small.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Based on the seismic interpretation and the dip data, it was decided to whipstock the well to contact the reef 300 ft to the west. The result was to gain 90 ft of elevation on the reef. A straightline correlation between the two contacts implies a reef dip of 16-1/2°, approximately the mean value of the tadpoles in interval A.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Exercise 1.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=1611&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> shows a Devonian reef which has a long, linear slope in this area. Regional dip is 1° SW.<br /></span></p><p><span style='font-size:10pt'>Compaction is 40 to 50%.<br /></span></p><p><span style='font-size:10pt'>What is the reef dip?<br /></span></p><p><span style='font-size:10pt'>What is the direction of dip?<br /></span></p><p><span style='font-size:10pt'>How far and in what direction must an offset be drilled to gain maximum reef?<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Solution 1:<br /></span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The long red dip pattern terminates at 6° just above the reef talus interval and would extrapolate to the reef surface at about that angle.</span><br /> </span></p><p><span style='font-size:10pt'>If compaction = 50%,</span><br /> </p><p><span style='font-size:10pt'>reef dip </span><br /> </p><p><span style='font-size:10pt'>If compaction = 40%,</span><br /> </p><p><span style='font-size:10pt'>reef dip </span><br /> </p><p><span style='font-size:10pt'>Direction of dip = NE.</span><br /> </p><p><span style='font-size:10pt'>Additional reef available is 190 ft.</span><br /> </p><p><span style='font-size:10pt'>If dip = 12°, go 890 ft.</span><br /> </p><p><span style='font-size:10pt'>If dip = 15°, go 710 ft.</span><br /> </p><p><span style='font-size:10pt'>Calculated from offset = </span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>As shown in the accompanying figure, the actual offset well gained 160 ft in 700 ft offset from a reef dip of 13°. Compaction of the shale calculates to be 40% from the data in these wells.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><br /> </span> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-9671298753795542242008-11-20T23:18:00.005-08:002008-11-20T23:18:52.786-08:00Dipmeter Surveys (Fault Interpretation)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Fault Interpretation <br /></span></h2></p><p><span style='font-family:Times; font-size:13pt'><strong>Introduction<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Faulting occurs when beds are in tension or under compression. Such forces produce normal faults and <em>reverse</em> or <em>thrust faults</em>. In areas that have undergone mainly tension (such as the northern Gulf of Mexico), almost all of the faulting is normal. In areas that have undergone both earlier tension and later compression, both normal and reverse/thrust faults may be present in the same well. For dipmeter interpretation, input of the local geology is required to define the actual model.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In order for a fault to be detected by the dipmeter, either some sort of distortion must be present near the fault plane or one fault block must be tilted more than the other. When tilting is present, the location of the fault is indicated by a sudden change in dip magnitude and/or direction.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Typical forms of distortion near both tensional and compressional faults are shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=508&order=0','0')'>Figure 1</a> . Each of these is covered in this section. Normal faulting (beds in tension) is discussed first and reverse/thrust faulting (beds under compression) last.<br /></span></p><p><br /> </p><p><span style='font-family:Times'><strong>Growth Faults<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Faults that were active during the time of deposition are called <em>growth </em>faults. The downward-moving block provided a low area that acted as a sediment sink and accumulated thicker layers of sediments than the equivalent upthrown zone. Tension-created slumping into the downthrown side of the fault also aided the downthrown thickening processes. Downthrown thickening, which begins some distance from the fault, increases toward the fault plane, with the maximum amount of thickening found immediately downthrown. This thickening into the fault, plus sinking of the increasingly heavier downthrown side of the fault, produces a rotation effect that also increases the dip of the beds into the fault.<br /></span></p><p><span style='font-family:Times'><strong>Rollover<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The cumulative effect of downthrown thickening, slumping, and rotation, which is called rollover, produces a trend of downward-increasing dips that dip toward the upthrown fault block ( <a href='javascript:figurewin('../../asp/graphic.asp?code=509&order=0','0')'>Figure 1</a> ). This trend terminates at, or shallower than, the fault plane. It is this dip trend that allows growth faults to be located, and their attributes identified, by the dip-meter tool. The downward-increasing dip trend produces a red dip pattern whose azimuth is toward the upthrown fault block and normal to the strike of the fault. Although not routinely found associated with growth faults, strike slip rotates the azimuth in a opposite to that of block movement. The vertical extent of the red pattern can be used as an indicator of the minimum displacement of the fault. Displacement is usually greater than the vertical extent of the fault; it is rarely less.<br /></span></p><p><br /> </p><p><span style='font-family:Times'><strong>Subsidence Effect<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>When the rate of deposition is greater than the rate of subsidence, a system of progressively younger faults in a seaward direction is created. When the rate of deposition equals the rate of subsidence, a fault with a very large displacement is produced, assuming of course that the system is stable for a considerable period of time. When the rate of deposition is less than the rate of subsidence, progressively younger faults are created in a landward direction.<br /></span></p><p><span style='font-family:Times'><strong>Bed Thickness<br /></strong></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=509&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> is a cross section illustrating the effect of a growth fault on bed thickness. Wells 1-3 penetrated the upthrown block of a down-to-the-east growth fault. Both sands A and B are the same thickness in both wells. Part of sand A is faulted out in Well 4, while sand B, which is still located upthrown, remains the same thickness. Well 5 penetrated sand A in a downthrown position in the rollover zone, so the sand is much thicker than its upthrown equivalent. Sand B was faulted out of Well 5. Well 6 penetrated both sands in a downthrown position within the rollover zone, so they are thicker than their upthrown equivalents. The downthrown thickening continues to decrease to the east until Well 9 is reached. This well is located beyond the eastern limit of the rollover zone, so both sands are the same thickness as their upthrown equivalents.<br /></span></p><p> <br /> </p><p><span style='font-family:Times'><strong>Growth Fault Examples<br /></strong></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=509&order=2','2')'><span style='font-size:10pt'>Figure 3</span></a><span style='font-size:10pt'> is an example of a large growth fault which cuts the Vicksburg formation of a South Texas well. The fault, which cuts the well at a depth of 14,890 ft, is downthrown, or dips, to the southwest. Therefore the rollover zone, which dips toward the upthrown block, dips to the northeast. The rollover zone (the zone that creates a downward-increasing dip trend) extends upward to 13,750 ft; the minimum displacement of the fault is approximately 1000 ft.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=509&order=3','3')'><span style='font-size:10pt'>Figure 4</span></a><span style='font-size:10pt'> is an example of an offshore Louisiana fault whose displacement is smaller than that of the fault in <a href='javascript:figurewin('../../asp/graphic.asp?code=509&order=2','2')'>Figure 3</a> . This offshore Louisiana Miocene example illustrates the rollover created by a small growth fault. The fault, which by correlation has a displacement of only 120 ft, is located at 12,638 ft and is downthrown, or dips, to the south-southeast and strikes normal to the pattern dip direction, or east-northeast west-southwest. Because of shattering of sediments near the fault plane, only a scattering of dips were recorded immediately downthrown.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Some fault examples show even more extensive shattering and washing out of the hole on the downthrown (most active) side of the fault plane. The dip trend which begins at the base of the blank zone is recorded from the upthrown block, so the fault cut is no deeper than the bottom of the blank zone. Usually it is picked at the base of the blank zone.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>One of the "eyeball" indicators of a possible missing section, which is present in these examples, is a borehole dogleg. Any time the bit crosses a formation compaction change it reacts by creating a change in the amount and/or direction of well drift. Since compaction changes are almost always present across a fault or unconformity, a change in well drift azimuth and/or magnitude can (but does not always) indicate the presence of a fault or unconformity.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>As long as a fault continues to grow, downthrown thickening is produced. This in turn produces an increasing-with-depth red dip pattern. During periods of relative nongrowth resulting from changes in depositional processes, the beds are rotated at a constant rate. This in turn produces constant dip zones within rollover-created red dip patterns. <a href='javascript:figurewin('../../asp/graphic.asp?code=509&order=4','4')'>Figure 5</a> is an example of such a fault. The increasing-with-depth rollover zone begins at about 8700 ft. From 9100 to 9250 ft the dip trend remains constant. From 9250 down to 9350 ft the dip again increases downward, indicating a period of renewed growth.<br /></span></p><p><span style='font-family:Times'><strong>Structural Dip Imprint<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The dips from a zone of distortion are changed when structural dip is imprinted on them, so it may be necessary to remove structural dip before determining the attributes of a fault, just as it is necessary when making stratigraphic interpretations.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=509&order=5','5')'><span style='font-size:10pt'>Figure 6</span></a><span style='font-size:10pt'> is a theoretical example of the appearance of a dip-meter plot when structural dip is imprinted over dips created by rollover. (A) shows a west-dipping red dip pattern created by rollover into a down-to-the-east growth fault. (B) shows that a moderate amount of east structural dip was added to the west dipping red pattern of (A). The resultant dip pattern, moving down the hole, is a decreasing dip trend or blue pattern. The dip decreases to zero, then increases in the opposite direction until a maximum is reached at the fault. A typical red pattern is formed below the zero crossing point. Below the fault cut, only east structural dip is seen.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>(C) illustrates an even stronger east structural dip imprinted over the west-dipping red pattern. At the point where the west-dipping structural dip and the strong east structural dip start to oppose each other, a decreasing dip trend, or blue pattern, begins. In this case, the trend decreases down to the fault cut but never quite reaches zero dip. As soon as the fault is crossed, only strong east structural dip is recorded.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=509&order=6','6')'><span style='font-size:10pt'>Figure 7</span></a><span style='font-size:10pt'> is a dipmeter example of the first type of imprint, where a strong red pattern opposes moderate or low structural dip in the opposite direction. Structural dip is about 10° south-southeast. This opposes the northwesterly dipping red pattern dipping into a down-to-the-southeast growth fault. The resulting dip patterns are ones of decreasing dips (blue pattern) from 13,700 ft down to the zero crossing point at 13,790 ft, then ones of increasing dips (red pattern) in the opposite direction down to the fault cut at the base of the blank zone at 13,880 ft.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Deviated Wells<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Deviated wells are sometimes drilled parallel to fault planes. As a well periodically gets closer to the fault and, in some instances actually bumps the fault, the dips increase and then decrease. Some dip scatter is created by formation shattering and hole conditions near the fault.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Platform wells may be deviated in a direction and an angle such that they cross normal faults from the upthrown to the downthrown sides instead of in the usual manner.<br /></span></p><p><span style='font-family:Times'><strong>Postdepositional Precompacted Faults (No Distortion)<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Normal faults that occur after deposition but before formation compaction usually exhibit no distortion near the fault plane. Such faults can be recognized on the dipmeter plot only if a change in structural dip occurs across the fault. Because there is a change in the degree of formation compaction, the borehole doglegs even though there is no distortion of the beds near such a fault.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The sudden downward decrease of structural dip is one of the "eyeball" indicators used to differentiate between faults and unconformities. Most of the time, in areas that have not undergone strong tectonic deformation, the downward decrease indicates faulting. In order to have lower dip below an unconformity, two different centers of uplift are required.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Instead of downthrown rotation, some faulted areas have undergone rotation of the upthrown fault block. This creates a sudden structural dip increase in a downward direction. This is the same dip pattern created by the presence of an angular unconformity or a rapid, postdepositional structural uplift. Therefore, other information is needed to determine which of the three features is present when a sudden downward increase in structural dip is noted on the dipmeter plot.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A lack of distortion near a fault plane can occur with both tensional and compressional faults. Therefore, unless there is a structural dip change at the fault cut, faults of this class cannot be seen on dipmeter plots.<br /></span></p><p><span style='font-family:Times'><strong>Postcompaction Faulting (Drag)<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Normal faulting that takes place after some degree of deformation has occurred usually develops <em>drag, </em>or beds dipping in the same direction as the fault, near the fault plane. In some areas, drag is found only on the downthrown side of the fault; in others, drag may be found in beds on both the downthrown and upthrown sides.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Since the relative motion of the upthrown and downthrown fault blocks creates a drag zone whose dip is in the same direction as that of the fault plane, the maximum dip of the resulting red dip pattern may be used as a minimum dip of the fault plane. Local experience is used to determine whether or not the maximum dip of a drag-generated red pattern is in fact a reasonable value for the dip of a fault plane. <a href='javascript:figurewin('../../asp/graphic.asp?code=511&order=0','0')'>Figure 1</a> is a theoretical example of a normal fault with drag only on the downthrown side. The red pattern, which was generated by the downthrown drag zone, dips in the same direction as the fault and normal to the strike of the fault. The maximum dip of the pattern may be used as the minimum dip of the fault plane. As happens with a growth fault, the hole doglegs within a hundred feet or so of the depth at which the fault cuts the well. Since drag is present only on the downthrown side, structural dip is recorded on the upthrown side of the fault.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=511&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> illustrates a normal fault with drag in both the upthrown and downthrown beds adjacent to the fault plane. The dip in the downthrown block created a dip pattern similar to the one in the previous example. However, drag, which is also present in the upthrown beds, creates a pattern of downward decreasing dips or a blue pattern. The fault cuts the well at the junction of the two patterns. Once again, the maximum dip of the red pattern may be used as a minimum dip of the fault plane.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The amount of rollover present on the downthrown side of a nonburied growth fault decreases upward. It disappears at a point corresponding to the time at which the fault ceased to be active. The amount of drag created by any period of movement remains relatively constant over the entire interval. The termination point may be a point corresponding to the end of the active faulting period, or, if buried, to an unconformity.<br /></span></p><p><span style='font-family:Times'><strong>Faults with Hybrid Dip Patterns near the Fault Plane<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Some faults begin as growth faults with downthrown rollover zones. Either continued movement along the fault plane or movement that began after compaction occurred then created a downthrown drag zone. Since rollover and drag-generated dips oppose each other, dip patterns like those illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=512&order=0','0')'>Figure 1</a> are created by continuing or later fault movement. A red, or downward-increasing, dip pattern begins at the point at which the hole penetrated the rollover zone. The dips increase down to the point at which the drag-zone dips begin to oppose the rollover dips. The trend then decreases downward to the zero crossing point. Below that point, another red pattern dipping in the same direction is formed. The dips continue to increase in magnitude down to the fault cut. On the upthrown side of the fault the dips may return immediately to a structural trend, or indicate an upthrown drag zone.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Buried Faults<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Growth faults die out gradually in an upward direction. Postdepositional faults may extend to the surface, where they create cliff-like scarps, or they may end abruptly at an erosional surface. Such faults are called <em>buried faults.<br /></em></span></p><p style='text-align: justify'><span style='font-size:10pt'>In addition to ending abruptly at an unconformity, disconformity, or <em>diastem, </em>buried faults may change displacement across deeper unconformities. The buried-fault creation process is illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=513&order=0','0')'>Figure 1</a> . First, a fault extending to the surface is formed. Later, erosion removes the elevated portion of the upthrown block; the land surface is once again level across the fault zone.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The original amount of uplift is labeled a. Still later, deposition begins again, and horizontal sediment layers are deposited above the erosional surface. Subsequently, movement again occurs along the fault plane. This movement creates a displacement labeled <em>b</em>. The displacement of the beds below the unconformity is now <em>a + b</em>.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Erosion has removed the beds that were originally displaced by amount <em>a</em>. Therefore, only displacement b extends across the unconformity on the upthrown side. If erosion occurs again, the beds that were uplifted above the surrounding land surface will be eroded to <em>a</em> flat surface.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The displacement below the shallowest unconformity is equal to <em>b. </em>The displacement below the deepest or oldest unconformity equals <em>a + b</em>. This cycle may be repeated.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=513&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> illustrates a buried fault example from eastern Venezuela. A down-to-the northwest growth fault is located at 3842 ft. The fault terminates at a depth of 3760 ft, which is the unconformity separating the Paleozoic from the Lower Cretaceous.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>This growth fault was originally active in Paleozoic time. Any scarp that existed was eroded before Lower Cretaceous sediments were deposited above the unconformity. No subsequent movement occurred along the fault plane.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Since both types of distortion (rollover and drag) commonly found near normal faults create similar dip patterns, some local knowledge is useful in determining which type to use when making an interpretation. In any given area one type of distortion is found near most of the area faults. For example, in the northern Gulf of Mexico and in Nigeria, rollover is the dominant distortion type. In Mississippi and North Louisiana, drag is most often found on the downthrown side of normal faults.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Here are some rules of thumb for determining the type of distortion present near a normal fault:<br /></span></p><p style='text-align: justify; margin-left: 81pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>If the vertical extent of the downthrown mega-red dip pattern is more than 200 ft, rollover is assumed. Normal fault drag rarely extends vertically more than 200 ft.<br /></span></p><p style='text-align: justify; margin-left: 81pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>When the vertical extent of the mega-red dip pattern is less than 50 ft, drag is assumed. In areas where rollover dominates, this assumption can lead to incorrect interpretation about 30% of the time, since many small growth faults do exist. When the vertical extent of the mega-red pattern is between 50 and 200 ft, use the dominant type of distortion known to exist in the area.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Deviated wells may cause the extent of the dip pattern to be expanded by 50% or more. Hole deviation must be taken into account when using the vertical extent of a mega-red pattern as input into one of the rules of thumb.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Semicontemporaneous antithetic fault systems that help accommodate rotation are often found associated with growth fault systems. These faults usually exhibit downthrown drag that creates red dip patterns dipping toward their downthrown blocks. The dipmeter example in <a href='javascript:figurewin('../../asp/graphic.asp?code=513&order=2','2')'>Figure 3</a> shows three such faults. These faults are down-to-the-northwest so the northwest dipping red dip patterns found on their downthrown sides are the result of drag rather than rollover. These antithetic faults are dipping into a large down-to-the-southeast growth fault which is below the total depth of this well.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Compressional Faults<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Faults that result from compressional forces may, depending on the fault angle, be called reverse or thrust faults. The fault angle of reverse faulting is 45° or more, while thrust fault angles are less than 45°<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The main form of distortion found near a reverse or thrust fault is drag on both sides of the fault. Drag, which is the result of movement of compacted beds, may be additionally modified by horizontal movement, or strike slip.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The compressional fault attributes that may be available from dip-meter plots are <em>depth, strike, direction of overthrust, and fault angle. <a href='javascript:figurewin('../../asp/graphic.asp?code=514&order=0','0')'/></em>Figure 1 illustrates the expected dip patterns near compressional faults. Such faults commonly show up very well on dipmeter plots. A mega-red dip pattern is usually found in the overthrust block. Its azimuth is in the direction of overthrust, assuming, of course, that no strike-slip has occurred. The downthrown pattern is one of downward-decreasing dips, or a blue pattern. These dips also point in the direction of overthrust. Both dip patterns are the result of drag on both sides of the fault. The fault is located at the junction of the red and blue patterns.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=514&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> is a dipmeter example from western Venezuela showing a reverse fault. Structural dip above 7800 ft is 12° southeast. From 7800 to 8450 ft westerly dipping beds in the overthrust drag zone oppose the southeast structural dip. This produces a decreasing-with-depth pattern down to the zero crossing point at 8030 ft; the pattern then increases downward to the fault cut. The dip azimuth reverses across the zero crossing point.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The maximum dip of this example is recorded at the fault. The blue pattern generated by the downthrown drag zone decreases rapidly. The dip patterns near major compressional faults are rarely symmetrical. The overthrust pattern usually has the greatest vertical extent. If the displacement is small (i.e., less than 100 ft), the red and blue dip patterns tend to be more nearly symmetrical.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The dip direction on both sides of the fault is the same as the direction of overthrust, which is to the west in this example. The strike of the fault, north-south, is normal to the direction of dip patterns.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In this example, the direction of structural dip in the overthrust block and the direction of overthrust are opposite, so the dip trend decreases to the zero crossing point and then increases in the opposite direction. Had the direction of structural dip and of overthrust been the same, the dip trend would have continued to increase in the overthrust drag zone. Horizontal movement of one block relative to the other <em>(strike-slip) </em>may also occur. The drag-created dip patterns, which dip in the direction of over-thrust, would be modified by any horizontal movement. When such movement occurs, the drag dip patterns are rotated in the trailing direction, which is opposite to the direction of movement, and so no longer indicate the direction of overthrust.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Both compressional faults and overturned folds create repeat sections on logs. If the repeat is right side up, it is the result of faulting. If one repeat is upside down or a mirror-image of the other, it is the result of folding.<br /></span></p><p style='text-align: justify'><strong>Thrust Fault<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION … !<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Exercise 1.<br /></span></p><p><span style='font-size:10pt'>See <a href='javascript:figurewin('../../asp/graphic.asp?code=1610&order=0','0')'>Figure 1</a> .<br /></span></p><p><br /> </p><p><span style='font-size:10pt'>There is a missing section in this well between 14,000 and 14,100 ft.<br /></span></p><p><span style='font-size:10pt'>Where is the dip change that indicates the location of the fault?<br /></span></p><p><span style='font-size:10pt'>Where is the top of the rollover zone or top of the mega-red dip pattern?<br /></span></p><p><span style='font-size:10pt'>What indicator suggests the presence of rollover rather than drag?<br /></span></p><p><span style='font-size:10pt'>What is the minimum displacement of this growth fault?<br /></span></p><p><span style='font-size:10pt'>In what direction is the fault downthrown?<br /></span></p><p><span style='font-size:10pt'>What is the strike?<br /></span></p><p><span style='font-size:10pt'>Is a dogleg present?<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Solution 1:<br /></span></p><p><span style='font-size:10pt'>The dip change corresponding to the base of the rollover zone is at 14,049 ft.<br /></span></p><p><span style='font-size:10pt'>The top of the mega-red dip pattern, which corresponds to the top of the rollover zone, is at 13,680 ft.<br /></span></p><p><span style='font-size:10pt'>The vertical extent of the red pattern is more than 200 ft; therefore, rollover rather than drag is present.<br /></span></p><p><span style='font-size:10pt'>The minimum displacement of the fault, which is equal to the extent of the red pattern, is 370 ft.<br /></span></p><p><span style='font-size:10pt'>The rollover zone dips into the fault; therefore, the fault is downthrown to the south and strike is EW.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>There is a dogleg. The hole is vertical at 13,000 ft and drifts to the SE a maximum of 3-1/2° at 14,000 ft. The hole then begins to straighten.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><br /> </span> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-22416855323357182622008-11-20T23:18:00.003-08:002008-11-20T23:18:38.743-08:00Dipmeter Surveys (Structural Dip Interpretation )<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Structural Dip Interpretation <br /></span></h2></p><p><span style='font-family:Times'><strong>Structural Dip Interpretation<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Structural dip changes (and the lack of such changes) are good indicators of the type of structure present ( <a href='javascript:figurewin('../../asp/graphic.asp?code=504&order=0','0')'>Figure 1</a> ). The following are guidelines for interpreting structure based on structural dip changes.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Structural dip decreases upward in structures uplifted contemporaneously with deposition. Constant dip over an interval indicates postdepositional structural uplift. Structural trends that decrease to zero dip and reverse magnitude and azimuth indicate structures with tilted axes. Deviated holes create the same effect by penetrating different parts of the structure being explored.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Structural dip changes over short intervals indicate numerous faults. The beds between two faults only a few hundred feet apart commonly exhibit different dips from beds above and below the two bounding faults as a result of tilting.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>If structural dip is changing rapidly in the horizontal direction, it is dangerous to extend the structural trends very far horizon-tally. Only the geologist can decide how far the trend may be extended. When the dip of a structure is changing, the feature interpreted as structural dip is the dip of a plane tangent to the mapping horizon.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Salt Domes<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Intrusive masses of salt form domelike features by penetrating overlying normally bedded sediments. <a href='javascript:figurewin('../../asp/graphic.asp?code=505&order=0','0')'>Figure 1</a> is a sketch of a typical salt dome. A number of faults are present, most of which dip toward salt. Unconformities and pinchouts are common, as are steep dips near the flanks of the salt dome. If the top of the dome is shallow enough, it may be overlain by caprock.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Not all domes resemble the one shown. Other features that lend themselves to dipmeter interpretation may be present; these are presented on the following pages.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Overhangs <a href='javascript:figurewin('../../asp/graphic.asp?code=505&order=1','1')'/></em>Figure 2 illustrates a well that penetrated salt far below an overhang. Note the following:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Dips are generally highest closest to salt.<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Dips increase as an overhang is approached from above.<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Dips, then, decrease below the overhang.<br /></span></p><p><br /> </p><p><br /> </p><p><span style='font-size:10pt'>There is another downward increase as the well approaches the main salt stock.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>One of the uses of the dipmeter on wells drilled near a salt dome is to indicate the presence of overhangs, which warrant further investigation by an ULSEL survey.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The ULSEL device is an electrical logging system with long electrode spacings allowing formation investigation up to 2000 ft from the wellbore. ULSEL measurements combined with induction log and dipmeter data provide the information necessary to compute the distance, direction, and profile of the nearest salt dome.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Vertical and Overturned Beds </em>Vertical, near-vertical, and overturned beds are found near salt domes and in areas of over-thrusting. Straight holes are rarely drilled through vertical beds. The apparent dip has a computed value of less than 90°. The dips become vertical only after correction for sonde tilt.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The steepest dips near a salt dome are generally found under an overhang, and some beds may be overturned indicating a horizontal and vertical component to salt movement ( <a href='javascript:figurewin('../../asp/graphic.asp?code=505&order=2','2')'>Figure 3</a> ). The illustrated well was sidetracked under the overhang, and it penetrated increasing easterly dipping vertical beds, overturned beds, and, finally, high easterly dips again.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Pre-Salt Uplift Growth Faults </em>Another cause of dip into salt is the presence of a large pre-salt uplift growth fault. The dip into the downthrown side of the growth fault can override any uplift-created dip away from salt. This feature occurs on the south flank of the dome illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=505&order=3','3')'>Figure 4</a> .<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Gouge Zones </em>Some salt domes are covered by a thin gouge zone, usually less than 100 ft thick. These gouge zones contain a mixture of the various sediments the dome has penetrated. When the resistivities of the normally pressured, bedded shales around a dome are approximately 1 ohm-m, the gouge resistivity averages approximately 1.2 ohm-m. Gouge is a mixture of sands and shales, and it has a "hashy" appearance on the SP and short-spaced resistivity curves.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A blanket of diapiric clay is sometimes found draped around one flank of a salt dome. This is a high-pressure, low-resistivity clay. Resistivities within Gulf Coast diapiric clay domes are commonly less than 0.5 ohm-m. Dips within gouge zones and diapiric clays tend to be random or nonexistent.<br /></span></p><p style='text-align: justify'><span style='font-family:Times'><strong>Clay Domes<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Clay domes are formed in the same manner as salt domes. Source beds are masses of low-density shales. The density of these shales can be less than the density of salt: 2 g/cc versus 2.16 g/cc. These low-density shales floated upward through zones of weakness to form clay domes. The penetration of younger overlying beds created dips away from the clay dome.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In the northern Gulf of Mexico the top of a clay dome is indicated by a downward decrease in resistivity. The half-ohm shale point was used as an indicator of the top of the clay dome in the Eugene Island Block 198 field.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Resistivities within domes may be as low as 0.2 ohm-m in the U.S. Gulf Coast region. In Nigeria, a 1 ohm-m value is more common.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>It is currently more difficult to identify clay domes than it was in the 1960s. At that time, a constant dip trend matching the dip of the domal surface was recorded within the dome. As the dome was approached from above, the dip trend increased in magnitude, just as if the flank of a salt dome were being approached. After the clay dome was penetrated, a constant dip trend was usually recorded. This is illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=505&order=4','4')'>Figure 5</a> .<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Since the late 1960s clay dome dips have become more elusive. Instead of constant dip trends within the dome, only blank zones are found on dip plots. One explanation for this change has been advanced by a major company geologist. He suggests that the current lack of dip data within the clay dome results from formation damage caused by increased mud weights. Dips detected within clay domes were probably derived from cleavages or compaction surfaces, not from bedding planes.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Dips are still found within high-pressure, low-resistivity shales in their normal stratigraphic position. After shales have been uplifted, they may be more susceptible to mud-weight induced damage.<br /></span></p><p><span style='font-family:Times; font-size:13pt'><strong>Structural Dip Deletion<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Formation dip results from the original depositional dip, compaction and postdepositional deformation, and structural uplift or subsidence. The magnitude and direction of structural dip are removed before making fault or stratigraphic interpretations.<br /></span></p><p style='text-align: justify; margin-left: 81pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>If the dip in the zone of interest is less than the structural dip, structural dip should be deleted from each of the dips on the tadpole plot.<br /></span></p><p style='text-align: justify; margin-left: 81pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>If the dip in the zone of interest is equal to or greater than structural dip, but with a different azimuth, structural dip should be deleted.<br /></span></p><p><span style='font-family:Times'><strong>Results of Dip Deletion<br /></strong></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=506&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> is an actual dipmeter plot that illustrates the results of structural dip deletion. The dips opposite the pay zone are less than structural dip, so structural dip should be deleted before attempting a stratigraphic interpretation. After deleting the 22° of north-northwest structural dip, the dips in the zone of interest form a south-southeast dipping red pattern. If structural dip is not deleted prior to stratigraphic interpretation, the interpretation will be in error. <br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Instead of being a fan deposited by a north-northwesterly flowing current, the sand was deposited as fill within an east-northeast, west-southwest striking channel, with the axis lying to the south-southeast.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Benefits of Dip Deletion<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Structural dip deletion serves as an indicator that the correct structural trend was identified and deleted. The structural dip on <a href='javascript:figurewin('../../asp/graphic.asp?code=506&order=1','1')'>Figure 2</a> was selected as 35° at an azimuth of 90° down to 7150 ft. Below 7150 ft, the structural dip was selected as 35° with an azimuth of 117°.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>After a structural dip of 35° at 117° was deleted over the entire interval, an apparent northeast structural dip trend remained above 7150 ft. Almost all apparent structural trends disappeared below 7150 ft. This indicates that 35° at 117° was the correct structural dip below 7150 ft but incorrect for the interval above. Another deletion pass was made over the entire interval to delete 35° at an azimuth of 90°. The apparent trend above 7150 ft disappeared, indicating that the correct structural dip was deleted. The incorrect structural dip deletion below 7150 ft produced an apparent southwest structural trend.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Another benefit of structural dip deletion is the identification of dips resulting from erroneous correlations. These dips tend to be higher than structural dip, and they typically remain unreasonably high after deletion.<br /></span></p><p><span style='font-family:Times'><strong>The Process of Dip Deletion<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>If the magnetic recording tape is available, structural dip deletion is a relatively easy process, and a tadpole plot with structural dip removed can be quickly generated. If the answer tape is not available, the processing must be recomputed, or a "stereo net" or hand calculation must be performed. Programs are available for the HP-25, HP-41C, HP-75, and the TI-59 calculators. For logs with more than a few points requiring structural deletion, log recomputation is strongly recommended .<br /></span></p><p><span style='font-family:Times'><strong>Deleting Uplift Effects Gulf<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Coast salt domes may have undergone several periods of uplift, both contemporaneous and postdepositional. Dips have reversed as the salt being uplifted at one location masked the dip from a nearby salt spine that had been uplifted earlier. Prior dips in directions different from those of current dips indicate the existence of fossil structures in the area. These structures may still be productive.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>To determine structural dip at any specific time, the effect of structure must be removed a single uplift at a time. The shallowest structural dip should be removed first. The remaining dips indicate the attitude of beds prior to the youngest uplift ( <a href='javascript:figurewin('../../asp/graphic.asp?code=506&order=2','2')'>Figure 3</a> ). After selecting a new structural trend for the shallowest remaining interval, delete the trend. The remaining dips indicate the attitude of the beds at the time of the second-youngest uplift. This process is continued until the end of the dipmeter log is reached.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><br /> </span> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-90322760865193426822008-11-20T23:18:00.001-08:002008-11-20T23:18:25.521-08:00Dipmeter Surveys (Dip Patterns)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Dip Patterns<br /></span></h2></p><p style='text-align: justify'><strong>Basic Types<br /></strong></p><p><span style='font-family:Times'><strong>Introduction<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>There are several graphical methods of plotting dip computations. This chapter covers interpretation rules based on the common "tadpole" plot. The head of the tadpole indicates dip magnitude and is plotted on a dip scale ranging from 0° to 90° versus depth. The tail of the tadpole, which points in the downdip direction, is plotted on a compass rose (north, up; east to the right; south, down; and west to the left).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The two or more tadpoles forming a group are derived from the internal structure of sediment layers deposited in a single depositional environment. All dips on a tadpole plot can be assigned to one of four basic groups. These groups are the building blocks used to create megapatterns. Mega-patterns, lithology, and knowledge of the depositional environment are used to make interpretations.<br /></span></p><p><span style='font-family:Times'><strong>Dip Groups<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The four dip groups are the red (slope), blue (current), green (constant), and random. These basic groups are the building blocks of megapatterns, which are used to identify missing or repeat sections and to interpret stratigraphy. The red, blue, and green patterns are illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=496&order=0','0')'>Figure 1</a> , which shows the borehole, formation-imaging, and dipmeter tadpole plots for each.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Red (Slope) Groups<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Red dip groups are composed of two or more adjacent tadpoles with constant azimuths and downward increasing magnitudes. These groups are generated from sediments deposited on a sloping surface or from sediments with dips that have been altered by postdepositional movement.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Most red groups result from downdip thickening. Beds deposited on a sloping surface thicken and become wedge-shaped in the downdip direction; therefore, the dip direction of red groups indicates the direction of thickening.<br /></span></p><p><span style='font-family:Times'><strong>Blue (Current) Groups<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Blue dip groups are composed of two or more adjacent tadpoles with constant azimuths and downward-decreasing magnitudes. These groups are generated mainly from sediment layers deposited as foreset beds. The dip directions of the foreset-generated blue groups indicate the directions of current flow during deposition. Some blue groups are generated by weathering beneath erosional surfaces; this process creates downward-flattening features.<br /></span></p><p><span style='font-family:Times'><strong>Green (Constant) Groups<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Green dip groups are composed of two or more adjacent tadpoles with constant magnitudes and azimuths. These groups are derived from parallel crossbeds or from sediments that were deposited flat and have subsequently undergone structural uplifting. Green groups are the only dip groups indicating structural dip today and are the groups sought within zones of least scatter.<br /></span></p><p><span style='font-family:Times'><strong>Random Groups<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Random dip groups are composed of adjacent tadpoles with random magnitudes and azimuths. These groups are derived from sediment layers deposited in high-energy environments, such as shallow water less than 50 ft deep; from layers that have undergone reworking by bioturbation; and from layers that have undergone postdepositional movement.<br /></span></p><p><span style='font-family:Times; font-size:13pt'><strong>Megapatterns<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>These dip groups are used as building blocks in identifying megapatterns. Megapatterns, lithology, and depositional environment information are used for determining the location of attributes of faults, unconformities, and stratigraphic features.<br /></span></p><p><span style='font-family:Times'><strong>Mega-Red Dip Patterns<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The mega-red dip pattern is a family of the basic dip groups characterized by an increasing downward magnitude trend and a constant or gradually rotating general azimuth ( <a href='javascript:figurewin('../../asp/graphic.asp?code=496&order=1','1')'>Figure 2</a> ). Individual basic dip groups may exhibit dips that do not match the general trend. The features in the subsurface that create mega red patterns on the dip plot include distortions near a fault plane, sand bars, beach ridges, reefs, and channels of all types.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Normal Faults </em>Two distortion types, <em>rollover </em>and <em>drag, </em>may be present near a normal fault. Rollover, with dip into the fault, results from sediments slumping into the downthrown side of a fault that was active at the seafloor during the time of deposition.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Drag zones contain beds dipping in the same direction as the fault plane. The mega-red dip pattern results from friction between the active downthrown block and the passive upthrown block. Most of the distortion occurs in the active or down-thrown fault block; however, upthrown drag is occasionally noted.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Mega-red dip patterns are not always found near the fault plane. Some faults have no downthrown or upthrown distortion; in these situations there is no dipmeter indication unless there has been tilting of one of the fault blocks.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Reverse Faults </em>Reverse thrust fault usually exhibit drag on both sides of the fault. The drag zone in the overthrust block creates a mega-red pattern dipping in the direction of overthrust. The downthrown dip pattern, if one exists, is a mega-blue pattern. If drag is present on only one side of the fault, it occurs on the more active, overthrust side.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>If a missing or repeat section is at or near the base of a mega-red pattern, the pattern probably results from some type of distortion near the fault plane. If there is no indication of a nearby missing or repeat section, then the mega-red pattern probably has a stratigraphic origin.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Additional information from other logs about the depositional environment and lithology is necessary to determine the stratigraphic feature generating a mega-red pattern.<br /></span></p><p><span style='font-family:Times'><strong>Mega-Blue Dip Patterns<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Mega-blue dip patterns are formed when the dip magnitudes of families of basic groups decrease downward but their azimuths remain the same or rotate slowly ( <a href='javascript:figurewin('../../asp/graphic.asp?code=496&order=2','2')'>Figure 3</a> ). As is true of mega-red patterns, a few individual basic dip groups may exhibit random azimuths. Also, local data about depositional environment and lithology obtained from other logs are required to make a stratigraphic interpretation.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Mega-blue patterns result from foreset deposition, weathering under erosional surfaces, and compaction caused by the sinking of a relatively dense mass, such as a sand or coral reef, into softer underlying beds. Dip direction of foreset beds indicates the direction of sediment transport or current flow. The dips created by compaction indicate the direction to the thickest portion of the overlying mass. Fore-set deposition occurs in delta-dominated environments, tide/ wave-dominated environments, longshore current sand waves, submarine fans, tidal flats, and at or near the axes of any type of channel.<br /></span></p><p><br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>Identifying Megapatterns<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Basic dip groups that do not form megapatterns terminate at or near a vertical or slightly inclined line ( <a href='javascript:figurewin('../../asp/graphic.asp?code=496&order=3','3')'>Figure 4</a> ). Basic dip groups that form megapatterns terminate at successively higher magnitudes-e.g., higher downward for a red, higher upward for a blue--for the length of the pattern. If the deepest dip group of a megapattern has an azimuth different from the azimuth of the general pattern, the azimuth of the pattern, not the basal group, should be used.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Theoretical Dip Patterns</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>A series of theoretical dip-versus-lithology patterns can easily be created for any specific environment. Since the same dip patterns can be created by different stratigraphic features, the theoretical sketches are grouped by depositional environments (nonmarine, deltaic, interdeltaic, and deepwater) . A missing and repeat dip response is also included.</span><br /> </p><p><span style='font-size:10pt'>The interpretation process can be carried out step by step in the following sequence:</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>Determine structural dip. <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>Delete structural dip if necessary.</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Identify and describe the attributes of missing and repeat sections.</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Make stratigraphic interpretations using lithology and knowledge of the depositional environment.</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>If independent knowledge of the depositional environment is unavailable, local "rules of thumb," using such parameters as bound water resistivity, shale resistivity, and dip scatter, can be used as environmental indicators.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Structural Dip </em>In order to represent structural dip today, any bedding plane or sediment layer must have been deposited flat and have undergone only structural uplift since the time of deposition. Structural dip trends are selected from zones of least dip scatter, since such zones are most likely to have been deposited in a low-energy environment and thus are most likely to represent structural dip today. A good rule of thumb is to assume that structural dip trends picked from the dipmeter display extend horizontally no farther than they do vertically. Dip trends that extend 1000 ft or more can usually be extended as far horizontally as the closest offset well. However, if numerous faults and unconformities are present, it may be impossible to find a dip trend that extends 1000 ft vertically.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Structural dip should be deleted before fault and stratigraphic interpretations are made if the dip magnitude in the zone of interest is less than that of structural dip, or if the dip azimuth in the zone of interest is different from that of structural dip.</span><br /> </p><p><span style='font-family:Times'><strong>Missing or Repeat Sections<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>After determining and (if necessary) deleting structural dip, the next step is interpreting missing and repeat sections. Missing sections result when normal faults, angular unconformities, disconformities, or diastems are present. Repeat sections result from compressional faulting and folding.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Since stratigraphic features and faults can generate identical dip patterns, an independent input as to locations of probable missing sections is desirable before making missing-section interpretations. Normal faults may generate red dip patterns that dip either toward or away from the fault plane. Dip patterns on the downthrown side of growth faults, which result from rollover into the fault, dip toward the fault plane. The vertical extent of such patterns can be used as a minimum fault displacement indicator. Nongrowth normal faults that occurred after some formation compaction had taken place create red dip patterns that dip in the same direction as the fault plane. These result from a drag zone immediately downthrown to the fault.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Reverse and thrust faults, which generate "right-side-up" repeats on the logs, create red-over-blue dip patterns. The patterns dip in the direction of overthrust, and the fault plane is located at their junction. Overturned folds also create log repeat sections, but one repeat is a mirror image of the other.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>From the bottom up on <a href='javascript:figurewin('../../asp/graphic.asp?code=498&order=0','0')'>Figure 1</a> , the first missing and repeat section is a diastem or disconformity. Since the angular difference across such features is less than one-half of a degree, they are not easily recognized on dipmeter plots. The small blue pattern shown beneath the missing section is the result of some type of weathering.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The next repeat section results from an overturned fold. The log response of the repeat section produces a mirror image with the repeat section upside down with respect to the first log response. In this example, there is a dip reversal across the fold; this is not always the case.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A reverse or thrust fault also produces a repeat log response, with the repeat right side up with respect to the first log response. Both the red pattern in the upper, or overthrust, block and the blue pattern in the downthrown block are the result of drag. The dip direction of the overthrust red pattern is the same as the direction of over-thrust (to the east in this example).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The next upward dip decrease is the result of a period of postdepositional uplift that created a portion of the underlying 25° northeast structural trend. There was no erosion of the uplifted beds. Deposition, which continued without a break, then produced onlapping beds. The overlying 20° east structural trend was produced by a later period of uplift. Such features are common in sediments deposited in deepwater environments.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The next upward dip increase, from 20° east to 10° east, occurs across an angular unconformity. The blue dip pattern drawn below the unconformity results from some type of weathering and occurs most of the time. Since this small blue pattern is identical to patterns produced by stratigraphic events, it should not be considered a diagnostic unconformity indicator.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>There is independent input that a fault exists within the section of 10° east structural dip. Since there are no associated red or blue patterns, this is a middle-aged normal fault that has no distortion near the fault plane. However, a sudden structural dip change occurs when one fault block has been tilted.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>There is also independent input that another fault is located just uphole. A red dip pattern, which terminates at the probable fault location, is present in this example. If the vertical extent of the red pattern is more than 200 ft, the pattern is almost certainly the result of dip into the downthrown side of a growth fault The dip direction is toward the upthrown block (example: upthrown to the northeast). If the vertical extent of the red pattern is less than 200 ft, the red pattern may result from either rollover into a growth fault or drag on the downthrown side of a later fault. When the pattern results from drag, the dip direction is toward the downthrown side and normal to the fault strike.<br /></span></p><p><span style='font-family:Times'><strong>Continental Environment<br /></strong></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=499&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> illustrates some continental environment depositional features and their associated dip patterns. From bottom up, the group of tadpoles indicating east structural dip is derived from sediments deposited essentially flat in an upper delta plain environment. Sands deposited in such an environment may contain secondary porosity because some plant-produced acids are capable of dissolving sand grains.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Flood-plain sediments produce a "bag-of-nails" dip scatter. Few (if any) dips reflecting structural dip are found within such sediments.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Next is an eolian sand. The illustrated dip patterns have constant (angle of repose) dip trends underlain by blue patterns. This is a typical dip response from transverse and barchan dunes. The dip direction indicates the prevailing wind direction at the time of deposition (from west to east in this example).<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Longitudinal dunes produce red or blue patterns whose dip directions are normal to the prevailing wind direction. Dome and parabolic dunes produce mainly red patterns dipping in the prevailing wind direction.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Swamp or marsh deposits generally produce blank zones because bedding planes have been destroyed by rooting and bioturbation.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Stream channels filled with clay plugs produce red dip patterns within shale sections. The patterns dip toward the channel thalweg.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>When stream channels are filled with sand instead of clay, possibly during a marine transgression, a red dip pattern found at the base of the sand dips toward the thalweg and normal to the strike of the channel (example: thalweg to the northeast, and northwest-southeast strike). This dip pattern is overlain by a blue pattern whose dip is 90° from that of the underlying red pattern. This dip direction indicates the current flow direction within the channel (example: direction of flow to the southeast).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Point-bar sands exhibit a number of internal blue dip patterns whose dips are in the direction of current flow. A red pattern that dips toward the thalweg may also be present just above the point bar. If the beds that produce the blue dip patterns are thicker than 3 ft, the blue patterns probably result from accretion depositions that dip toward the thalweg rather than from trough crossbeds that dip down-current.<br /></span></p><p><span style='font-family:Times'><strong>Continental Shelf, Delta-Dominated Environment<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>In the example in <a href='javascript:figurewin('../../asp/graphic.asp?code=500&order=0','0')'>Figure 1</a> , <em>delta-dominated </em>means that some, if not all, of the stratigraphic features deposited in a deltaic environment were preserved in their original forms rather than in reworked forms. The bottom sand is channel-like and was formed by the compaction of underlying muds. All dips of the red dip pattern (faulting has been eliminated) found within the sand dip toward the axis and normal to the strike of the sand. Because of compaction of the sediments below the sand, a blue dip pattern dipping toward the channel axis is usually found beneath the sand in the underlying shales. Other logs exhibit gradients (downward-decreasing resistivity, increasing interval transit time) in the underlying shales. Sands formed by compaction may be more than 2000 ft thick.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Crevasse splays generate blue dip patterns pointing in the direction of current flow (example: direction of flow to the southeast). A sand deposited as a distributary mouth-bar and topped by a scour channel exhibits a red-over-blue dip pattern that dips in the same direction. The blue pattern dips in the direction of current flow (example: direction of flow to the east-southeast) and the red pattern dips toward the scour channel axis (example: axis to the east-southeast), which usually has a very limited areal extent. In general, when adjacent red-over-blue patterns dip in the same direction, the red pattern can be ignored.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Whenever a distributary mouth-bar sand undergoes shallow-water reworking, a bag-of-nails dip scatter is produced. Such sands tend to be clean with good porosities and permeabilities.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>When all the original depositional features of a distributary channel are preserved, they produce a red dip pattern at the base of the sand, overlain by a blue pattern. The pattern azimuths are 90° apart. The red pattern dips toward the channel axis and normal to the channel strike (example: axis to east and north-south strike) The blue pattern dip indicates flow down the channel (example: flow from north to south). A distributary mouth-bar produces a blue dip pattern whose direction is that of current flow (example: flow from northwest to southeast) .<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>When the blue pattern magnitude variation is 10° or more, the distributary mouth-bar tends to be elongated in the direction of dip (inertia-dominated environment). When the dip variation is less than 10°, the distributary mouth-bar tends to be fan or crescent shaped (friction-dominated environment). Distributary mouth-bars and crevasse splays look the same on dipmeter plots.<br /></span></p><p><span style='font-family:Times'><strong>Continental Shelf, Tide- or Wave-Dominated Environment<br /></strong></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=501&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> illustrates some of the stratigraphic features and associated dip patterns that are found in a continental shelf, tide- or wave-dominated environment. Many of these features are the result of reworking of previously deposited deltaic sediments.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>At the bottom of the figure, parallel seaward-dipping cross-beds are produced by beach rock that forms in a carbonate environment at the saltwater-freshwater interface along shorelines.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>An oolitic bar is identified by a red pattern immediately above the bar (assuming, of course, that it was not penetrated on the crest). The red pattern dips toward the pinch-out and normal to the strike of the bar (example: pinchout to the northeast, and northwest-southeast strike) . Dips within the oolitic bar are immaterial.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A reef also exhibits a red pattern above its top and a blue pattern in the underlying beds. Few, if any, meaningful dips are found within reefs. The overlying red pattern dips toward the pinchout and normal to the strike of the reef. The blue pattern, which results from compaction, dips toward the thicker part of the reef (example: pinchout is to the east-northeast and the reef strikes north-northwest, south-southeast) .<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A buried beach ridge exhibits a red dip pattern immediately above the top of the ridge and numerous dips within the beach-ridge sand. The red pattern dips toward the shaleout and normal to the strike of the beach ridge (example: shaleout to northeast, and northwest-southeast strike) .<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A sand bar that formed at the wave breakpoint also exhibits a red dip pattern above the sand but few dips within the sand (reworking increases the electrical homogeneity) . The red pattern dips toward the shaleout and normal to the strike of the bar (example: shaleout to the northeast, and northwest-southeast strike) .<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In <a href='javascript:figurewin('../../asp/graphic.asp?code=501&order=1','1')'>Figure 2</a> the bottom sand was deposited as a slip-face sand on the landward side of a beach. The internal blue dip pattern dips landward and normal to the beach strike (example: land to west, and north-south beach strike).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The next sand was deposited as beach dunes and contains varying dips resulting from festoon crossbedding. Formations on the berm crest of a beach can be deposited flat and would later indicate structural dip.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Runnel sands may exhibit blue patterns derived from mega-ripples whose dip azimuths approximate the beach strike. Small-scale ripples may produce either blank zones or random dips. The example beach strike is north-south, indicated by south-dipping blue patterns derived from megaripples.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A beach-face sand contains seaward-dipping parallel cross-beds (example: parallel crossbeds dipping 5° east indicate that seaward was to the east during deposition).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Upper shore face sands contain a few parallel seaward-dipping crossbeds (example: 1° and 2° east dips indicate that seaward was to the east during deposition). Lower shore face sands contain mainly blank zones and random dips that result from high-energy environments and extensive bioturbation.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Longshore current sand waves exhibit blue dip patterns dipping in the direction of transport and parallel to the nearby fossil shoreline (example: dips to south indicate transport from north to south along a north-south striking shoreline).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A tidal flood delta, or washover, fan generates landwarddipping blue dip patterns (example: west-dipping blue patterns indicate that land was to the west during deposition).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Ebb deltas produce seaward-dipping blue patterns (example: east dip indicates that seaward was to the east at the time of deposition).<br /></span></p><p><span style='font-family:Times'><strong>Deepwater Depositional Environment<br /></strong></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=502&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> illustrates the sedimentary features found in deepwater (continental slope and deeper) sediments. Often, postdepositional movement occurs within sediments deposited on the continental slope. This produces a bag-of-nails dip appearance. Structural dip is extremely difficult to determine from such intervals.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Deposition at the distal end of submarine fans produces alternating sand-shale layers that later can become low-resistivity pay zones. Dips recorded in this environment indicate structural dip. The midfan portion of a submarine fan produces blue patterns that indicate sediment transport directions (example: transport direction was north to south) .<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Debris flows produce blank zones or zones of random dips. A submarine channel penetrated near the edge exhibits a red pattern that dips toward the channel axis and normal to its strike (example: axis to the east, and north-south strike) . A near-the-axis location within a feeder channel produces only blue patterns, which indicates flow down the channel (example: south-southwest dipping blue patterns indicate flow from north-northeast to south-southwest) .<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A feeder channel penetration between the axis and channel edge produces the "blue-over-red with axis 90° apart" dip pattern combination. The red pattern dips toward the channel axis and normal to the channel strike (example: axis to the east and north-south strike). The blue pattern dip direction indicates the flow direction down the channel (example: flow direction was from north-northeast to south-southwest) .<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>These theoretical patterns show all of the original dip patterns intact. In practice, portions of the original patterns may have been destroyed by reworking. Also, random dips that behave like noise are scattered throughout the patterns.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Exercise 1.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The upper 3 m of the log in <a href='javascript:figurewin('../../asp/graphic.asp?code=1607&order=0','0')'>Figure 1</a> are in interbedded shales and silts. The lower 4 m are mostly sand in a fluvial environment.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>This exercise requires the student to study the dip curves closely, from a standpoint of similarity between adjacent side-by-side electrodes and similarity from pad to pad.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Also study the dip results from each of the three systems: CSB, MSD, LOCDIP.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Study the comparison of 5-inch correlation CSB, LOCAL DIP, and 1-foot correlation MSD. What are the bedding characteristics for each of the four intervals?<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Solution 1:<br /></span></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>Interval 1</em></span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Curve pairs vary from similar to unlike, and the CSB results reflect this fact. Pad-to-pad similarity is quite poor, causing the MSD dip scatter. Bedding is probably irregular and of very short lateral extension. There is some stratification, however, as indicated by the similarity of side-by-side curves.</span><br /> </p><p><span style='font-size:10pt'><em>Interval 2</em></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The lower 2 m of this section are well-bedded with small curve contrast. Agreement between systems is fair, implying some consistency in direction. At the arrow, note that LOCDIP and MSD point north at 9°, whereas CSB shows SW crossbedding over that section. This is an excellent example of a dominant anomaly (see correlations) influencing the dips over the complete 1-ft correlation interval on the MSD, and the similar LOCDIP response.</span><br /> </p><p><span style='font-size:10pt'><em>Interval 3</em></span><br /> </p><p><span style='font-size:10pt'>Well-bedded, with good basic agreement among systems.</span><br /> </p><p><span style='font-size:10pt'><em>Interval 4</em></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Poor bedding, with noncorrelational conductive anomalies. These are pyrite blebs, very small but very conductive.</span><br /> </p><p style='text-align: justify'><br /> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-53432525025315471002008-11-20T23:17:00.001-08:002008-11-20T23:17:38.203-08:00Dipmeter Surveys (Computation)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Computation <br /></span></h2></p><p style='text-align: justify'><strong>Methods and Parameter Selection<br /></strong></p><p><span style='font-family:Times'><strong>Computation Methods<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>One method used to obtain dip information from the raw data involves correlating intervals of the dip curves. To a mathematician, a correlation coefficient is a measure of agreement between any two curves. Numerically, coefficients may run from zero (representing two completely dissimilar curves) to one (representing two identical curves).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The computer calculates the similarity between a section of one curve and an equal section of a second curve. The length of the interval on the first curve is the correlation length or interval. The computer then moves the first curve by some small, preset increment and recomputes the coefficient. This process is repeated many times.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>When plotted with respect to depth, the resultant series of coefficients forms a function called the <em>correlogram. </em>This correlogram shows a peak value where the curves have the best fit with each other ( <a href='javascript:figurewin('../../asp/graphic.asp?code=492&order=0','0')'>Figure 1</a> ). The position of this peak with respect to the center of the interval chosen on the first curve is the shift, or displacement, between curves.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The process is repeated for all curve pair combinations at that depth; the result is the relative position of correlated points around the borehole, which (when combined with the other measurements such as tool orientation, drift, and caliper data) are used to calculate the dip answer for that depth. A new interval is then chosen on the first curve at a distance equal to the step distance from the previous round of correlations just described, and the process is repeated to produce another dip answer displaced in depth from the previous one by an amount equal to the step distance. This step distance is normally chosen to be some fraction (usually 25 to 50%) of the correlation interval.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>During the curve-to-curve comparison it is essential to prescribe for the computer the distance up and down the second curve to which the first curve is to be compared. This distance is fixed by the choice of the input parameter called <em>search angle.<br /></em></span></p><p style='text-align: justify'><span style='font-size:10pt'>Search angle is chosen according to the dip environment. For low structural dip areas, a 45° search is common, as most stratigraphic dips fall within that range.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In tectonically disturbed areas, higher search angles may be required. The choice in such circumstances must be guided by both local knowledge and close inspection of the dip curves. Large displacements may be visually evident and an approximate dip range may be estimated.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The user of the computed data should be aware of a particular characteristic of the interval correlation system. In order to prevent some data from not being used in the computation, the step distance is normally (as mentioned above) less than the correlation interval. This may allow a dominant anomaly (a large sharp peak or trough) to influence the dip answer for each step in which it is included in the correlation interval. This can cause two or more adjacent dips to be essentially identical, giving the user the impression that several parallel beds exist when in fact there may be only one. For example, a 25% step may produce four similar dips from one anomaly, a 33% step may produce three similar dips, and a 50% step may produce two similar dips.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>If the user is aware of the parameters used for the computation he will recognize the duplications and interpret the dips correctly. However, if the effect is not desirable, a method called <em>pooling </em>may be used to present the results. In pooled plots, adjacent dips within a very small solid angle (2° to 3°) are presented as one dip answer. Dips that do not pool are still presented, so that no data is discarded.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=492&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> shows another interval with both the unpooled and pooled results side by side. Note the groups of four dips on the unpooled data set that appear as single dips on the pooled result. Also evident is the marked decrease in dip density in the pooled data for the upper half of the log. This can be a desirable presentation, particularly when plotting data on reduced scales, such as 1:600 or 1:1200, for structural dip analysis.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Computation Parameter Selection<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>There are three basic types of interpretation problems that users of dipmeter data may wish to solve:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>structural interpretation<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>large-scale stratigraphic features<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>maximum detail, very fine stratigraphic features, as observed on detailed core inspection.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>It is often desirable to interpret a combination of the above from a single dipmeter log. As a result, a variety of systems have evolved to handle widely different requirements.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The most commonly used and generally applicable approach is the correlation interval system described earlier. For analysis of structure and large-scale sedimentary features, a 4-ft correlation interval and a 1-ft or 2-ft step is usually the first approach to analysis. For special applications or difficult logging conditions, other values of these parameters may be more useful. In fact, if the user of the data is specifically interested in one of the three interpretations mentioned above, parameters must be chosen to optimize that result.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Therefore, it is important to understand how the tadpole plot is affected by the choice of these parameters. For each step, a single dip answer is produced, and all the data within that correlation interval are used to obtain that single dip. A 4-ft interval may contain from 0 to more than 100 correlations, due to bedding contrasts, but only a single dip is calculated, based on the best fit of the correlation curves. Large correlation intervals tend to smooth the dip results. Short correlation intervals allow the system to find more detailed results.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=492&order=2','2')'><span style='font-size:10pt'>Figure 3</span></a><span style='font-size:10pt'> contains a 4-m section of dipmeter computed in a sand section using several correlation intervals. Note that although the dip direction trend is similar in each, the implied cross-sectional view of the formation is significantly different.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Plot A clearly shows detailed internal sedimentary structures with a much better suggestion of environment than do B and C. Plot B retains most of the characteristics of Plot A, but with some apparent averaging and smoothing at dip magnitude boundaries. Plot C suggests large-scale, almost parallel crossbedding. This plot fails to indicate the more complex internal sedimentary structures evident on the A plot.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>It is apparent from comparing these three computations that the choice of the computation parameters should be influenced by the type of information required to support exploration and production programs. Although the basic principles described in the foregoing apply to all correlation interval techniques, algorithms differ significantly for different tool types, allowing the best adaptation to the data obtained by the tool.<br /></span></p><p><span style='font-family:Times'><strong>Dip Computations with the 4-Curve Dipmeter Tool</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>For the 4-curve tool, two correlation techniques are available to determine the magnitude of the dip and the azimuth of its direction: interval correlation (CLUSTER* Program), as described above; and feature correlation (GEODIP* Program), where individual peaks and troughs are first classified by size, shape, and other characteristics, and these features are matched from curve to curve, taking into account certain constraints. The objective of the latter method is to adapt the program to variations in bedding frequency and thickness, with the result that dip computations are made at points on the dip curves rather than over preselected intervals. This system then frees the computation from a fixed interval constraint, and allows computation of dips of individual bed boundaries.</span><br /> </p><p><span style='font-size:10pt'>Note: Throughout this document an asterisk (*) indicates a mark of Schlumberger.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The overlapping correlation sequences of CLUSTER processing are an improvement over previous programs, but it still has the disadvantage of a fixed, rigid correlation "window," unresponsive to variations in the density of geologic data in the curves.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A close study of dipmeter curves shows that many curve features or elements are identifiable from curve to curve. As shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=493&order=0','0')'>Figure 1</a> , these features have various thicknesses (from 1 in. to several feet), amplitudes, and shapes. Each feature may be considered to be the signature of a geological event in the depositional sequence of the formation. Moreover, the dip of the bed boundaries is not necessarily constant, and sometimes varies rapidly.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the GEODIP program, each of the four dip curves to be correlated is mathematically decomposed into a depth-ordered sequence of ranked elements.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In feature extraction, which is the first phase of the program, elements such as peaks, troughs, spikes, and steps are identified in the curves. Each feature has one or two boundaries and a set of parameters that describe its shape.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the second phase, the GEODIP program attempts to match elements of one curve with similar elements of the others according to the following logic:</span><br /> </p><p style='text-align: justify; margin-left: 81pt'><span style='font-size:10pt'>· By a built-in order of precedence (e.g., first large troughs, then large peaks, then medium troughs, and so on), the program first evaluates higher-order features, then when necessary also evaluates lower-order ones. This is done during multiple passes through the four sets of elements.</span><br /> </p><p style='text-align: justify; margin-left: 81pt'><span style='font-size:10pt'>· Because geologic strata are deposited in succession, their boundaries do not cross. So, if event A appears above event B on one curve, it cannot appear below event B on another. This is the rule of noncrossing correlations.<br /></span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>If no correlation can be found within the specified search angle among all four curves, the program lowers its standards and looks for 3-curve correlations instead. Planarity is monitored continuously, and if it fails to meet preset standards, the program makes no attempt at 4-curve dips, but computes the four different 3-curve dips and displays them all.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Because the program works from identifiable features on the curve, each one corresponds to a geologic event and the density of the output data depends on the density of geologic information at that level. This makes GEODIP processing particularly successful in fine-structured sedimentary sections and for definition of lithological changes, such as scour surfaces.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The calculation of dip angle at each depth is from displacements measured on boundaries rather than on feature centers. These boundaries are shown on the correlation curves of a GEODIP log. They are themselves useful features for interpreting lithology, as <a href='javascript:figurewin('../../asp/graphic.asp?code=493&order=1','1')'>Figure 2</a> suggests.</span><br /> </p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Determining Data Quality</strong></span><br /> </p><p><span style='font-size:10pt'>The geologic validity of each dip determination may be tested in several ways.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Closure </em>If displacements are determined between each adjacent pair of curves, taken cylindrically (1-2, 2-3, 3-4, 4-1) they should have an algebraic sum of zero. (Moving from one electrode to the next, you should return to where you began after making a traverse of all four electrodes.) This condition is called <em>perfect closure. </em>Small closure errors may be due to inaccuracies in the computed displacements; large closure errors indicate that one or more of the correlations are in error.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Planarity </em>Another test is for <em>planarity, </em>the condition that the four points should define a plane. After four displacements have been calculated, the lines joining diametrically opposed electrodes may fail to intersect, if there is an anomaly in the calculation or in the bedding.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>For the 4-curve tool, the geometry of the pad linkage ensures that distances between opposing adjacent pairs remain equal. Displacements computed from opposite pairs of curves (h 1-2 and h 3-4 for example) must therefore be equal but opposite if the bedding surface is planar. (The line segment connecting Pads 1 and 2 on the dipping plane parallels and equals in length-but is oppositely directed to-the line segment connecting Pads 3 and 4, for example.) For perfect planarity, h<sub>1-2</sub>+h<sub>3-4 </sub>= 0 and h<sub>2-3</sub> + h<sub>4-1</sub> = 0.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Likeness </em>A third test is for <em>likeness, a </em>quality derived from the correlogram, to compare the similarity of the curves. The highest correlation coefficient computed over the search interval is the likeness of the two curves, and the trial displacement of that maximum is the displacement retained for that interval of the curves. Since more than one cross correlation is required to compute a dip, the credibility of the dip answer is roughly proportional to the lowest likeness of all the correlations used.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Despite these tests, the results sometimes show excessive scatter that is not of geologic origin, particularly when shorter correlation lengths are selected to improve resolution. The CLUSTER program reduces the scatter in the output by statistically reducing the data. It is assumed that random noise does not repeat itself through small changes of the correlation environment. Thus, at a given level the redundancy inherent in having four correlation curves allows the curves to be grouped in various combinations in a search for consistency. In addition, coherence between consecutive overlapping levels above and below each point in the hole is checked.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The program computes correlations between five of six possible pairings of the four curves, taken two at a time. To define a plane, any two of these pairs must have one curve in common. The CLUSTER program, working with this output, considers eight such solutions. Each of the eight yields a solution for the true dip plane, and generally each is slightly different. Calculations from an adjacent level yield another set of eight solutions. Since the correlation interval is greater than the step distance, neighboring correlation intervals overlap. Comparison of dips from several overlapping levels (eight solutions from each level) shows statistical scatter among the different solutions, but there should be a tendency for many of them to "cluster" near some numerical value. When several solutions (not all from one level) fall within an acceptable range of values, the program quotes the value for the group, rejecting those that scatter outside. As a result, legitimate dip trends can be sorted from noise.</span><br /> </p><p><span style='font-family:Times'><strong>Computing Dip with 8-Curve Data</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>This section discusses the methods developed specifically for processing 8-curve data using the principles of interval and feature correlation, the presentation of the results, and the presentations available at the wellsite and at the computing centers.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The determination of formation dip measurements using the 4-curve dipmeter tool depends on the bedding plane being detected by at least three of the four measure electrodes. This, in turn, implies that the formation is well-bedded or laminated. Unfortunately this is not always the case, and for many formations pad-to-pad correlations are impossible to establish, making sedimentary studies difficult or impossible. Also, pad-to-pad correlations may be difficult in highly dipping formations or in highly deviated holes.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The 8-curve tool was designed specifically to overcome this limitation by providing two microresistivity curves, 3 cm apart, on each of the four pads. The density of the results is an order of magnitude higher than with previous 4-pad hardware and processing. In addition, the improved sonde velocity correction, using accelerometer data to compute instantaneous sonde speed and length of travel along the borehole, greatly increases the coherence of the results and helps salvage data affected by severe hole conditions.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The processing methods discussed here have been developed to take advantage of the tool improvements. They provide three independent computations of formation dip and allow adaptation of the interpretation of the results to the specific problem of interest (e.g., structural, sedimentary, geometry of the sand body).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Programs for computing dip from 8-curve measurements include the basic interval correlation program, called <em>mean square dip </em>(MSD), which uses all 28 possible cross correlations to compute 28 displacements (if all are successful). Since only two adjacent displacements are needed to define a plane, considerable redundancy has been built into the measurement system. The program thus tries to find a "best fit" plane that satisfies most of the displacements.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A second interval correlation method called <em>continuous side-by-side </em>(CSB) is also used. It only considers displacements computed from the side-by-side buttons on the pad. These four computed displacements represent the apparent angle of the set of bedding planes that cut across the borehole.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Finally, feature correlation is provided by the LOCDIP* computation. These pad-to-pad correlations are made over short intervals centered on bed boundaries, as defined by the major inflection points on the microresistivity curves. This method is used to identify and then correlate major individual curve features. The correlation lines are displayed with the actual microresistivity curves in a way similar to the GEODIP computation and presentation.</span><br /> </p><p><span style='font-family:Times'><strong>Mean Square Dip (MSD) Processing</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>At any one depth level, there are 28 possible cross correlations for the 8-electrode measurements, as compared to six for the 4-curve recording. As in 4-curve processing, the correlation method for the eight curves requires defining an interval length, a step, and a search angle; however, there is a significant difference in the way the cross correlation is made. In the standard interval correlation program, a specific interval of a reference curve is defined and then slid along the interval of the matched curve. For the 8-curve dipmeter tool, the MSD method considers the same depth interval on each curve and uses only the data within that interval to make correlations. In the case of low apparent dip, nearly all the data points within the interval are considered when the correlation is made. As the apparent dip increases, fewer and fewer points enter into the correlation. A limit is imposed when the search angle is increased until only half the points in the intervals are being used. This corresponds to an apparent dip of about 72° in an 8-in. borehole with a 4-ft correlation interval.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In areas where high dips (or high apparent dips due to deviated hole conditions) are expected, this limitation can be overcome by displacing the curves by a known amount before cross-correlations are attempted. The amount of the curve displacement or shift would be that corresponding to the displacement one would expect if the actual dip plane were the same as the assumed or "focusing" plane. Hence, the net displacement used in the dip computation is the interval shift plus the displacement computed between the curves after the shift. The focusing plane can be chosen as either</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>a fixed plane defined by the analyst (default is a horizontal plane), or <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>a plane defined by a previously computed dip</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>For moderate structural dip computations, experience has shown that the following input parameters are usually satisfactory:</span><br /> </span></p><ul style='margin-left: 81pt'><li><div><span style='font-family:Arial Unicode MS; font-size:10pt'>interval length, typically 4 ft. <br /></span></div><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>step distance, expressed as a percent (usually 50%) of interval length-(e.g., for a 4-ft interval, step distance would be 2 ft)</span><br /> </p></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>search angle; 45° usually find most dips relative to a horizontal plane</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The MSD program, then, is primarily used to determine structural dip by finding strong planar events crossing the borehole. The button-button displacements are computed and the best-fit plane through these displacements is found.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>This initial best-fit can then be refined by an iterative process in which points beyond <em>k</em> (which varies from 2.5 to 1.4) standard deviations from this initial best-fit plane are rejected, and a best-fit plane through the remaining points is calculated. An empirical quality factor is assigned to the final best-fit plane. This factor, ranging from 0 to 20, is a function of the number of iterations made and the final number of displacements retained.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>There is no vertical continuity logic or clustering routine in the MSD computation; each level is autonomously processed. The redundancy available (28 possible displacements, when two are enough to define a dip) reduces the possibility of producing mathematical dips or noise correlations.</span><br /> </p><p><span style='font-family:Times'><strong>Continuous Side-by-Side (CSB) Processing</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Continuous side-by-side</em> (CSB) processing is a unique feature of the 8-curve measurement and takes advantage of the fact that there is great similarity between the two microresistivity curves recorded by each pad since the two measure electrodes are separated by a horizontal spacing of only 3 cm. With side-by-side correlations, CSB processing is able to define formation dip that may not be apparent on pad-to-pad correlation. Even more important, the CSB program is responsive to the fine bedding structure of the formation, making it particularly effective for defining stratigraphic features. This is illustrated in</span><em><br /> <a href='javascript:figurewin('../../asp/graphic.asp?code=494&order=0','0')'/></em><span style='font-size:10pt'>Figure 1 , where the curves recorded by Pads 2 and 3 are shown for 12 ft of hole. Side-by-side correlations are shown as thin lines, and, for reference, the pad-to-pad correlations found for the same interval are shown as thick lines. From this example, we see that the number of side-by-side correlations is approximately an order of magnitude greater than the pad-to-pad correlations, and that the resolution is on the order of a few inches.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Another important feature, due to the proximity of the buttons on the pad, is that the displacements found by side-by-side correlations are much smaller than pad-to-pad displacements. This allows the measurement of very high dips that are not detected by pad-to-pad correlation. For such cases, once credible dips are found by CSB processing, they can be used as input to the focusing option for the MSD program.</span><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=494&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> shows a conventional pad-to-pad MSD correlation for a case of high apparent dip. The well is deviated about 35° to the southwest, in the same direction as the regional structural trend (30° to 40°). Thus, a given bedding surface would cut the borehole high on the northeast side and low on the southwest side. Obviously, getting a good correlation is difficult, although the quality of the dip curves and the borehole condition is excellent. <a href='javascript:figurewin('../../asp/graphic.asp?code=494&order=2','2')'>Figure 3</a> shows the results obtained with side-by-side CSB processing. In this case, the 3-cm spacing of the buttons allows an unambiguous correlation to be made.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the standard CSB computation, each pair of microresistivity curves (e.g., buttons 1-lA) is cross-correlated using short correlation intervals of 12 in. or less, and under favorable conditions even 4 in. or 3 in. The step distance can be taken equal to half or three-quarters of the correlation interval. This gives a vector parallel to the dip plane. Under ideal conditions (planar beds) another vector is found at the same depth by cross-correlating the microresistivity curves of an adjacent pad (e.g., buttons 2-2A). These two vectors are then used to define a dip plane.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>With only four side-by-side correlations, a cross-check is needed to verify that the bed is indeed planar. If it is, then displacements obtained using microresistivity curves from opposite pads (e.g., buttons 1-lA, 3-3A) should be equal in value but opposite in sign, and the dip can be obtained from any two orthogonal pairs at that depth. If this is not the case, however, a window is opened around the level under examination, and the vertical continuity of the displacements a certain number of levels above and below it is checked. The pad showing the best vertical continuity is kept. A similar procedure is then followed for Pads 2 and 4 and, again, the pad showing the best vertical continuity is kept. The orthogonal pair showing the smoothest continuity within the window is used for dip computation.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In order to evaluate the credibility of the dip, a quality value ranging from 0 to 20 is assigned to each dip according to the vertical continuity and the quality of the correlograms at the various levels or depths.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>If the environment of deposition produces little contrast between beds or the formation is highly crossbedded with sequences terminating over lateral distances of the same order as the borehole diameter, then pad-to-pad correlation may be difficult or impossible due to curve dissimilarity. CSB provides an excellent solution to this problem.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Correlation intervals as small as 2 in. have been matched with detailed core information, although 6-in. to 1-ft correlation intervals are most commonly used.</span><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=494&order=3','3')'><span style='font-size:10pt'>Figure 4</span></a><span style='font-size:10pt'> shows the detail available from the CSB as compared to visible core features. To make this comparison the CSB was processed with a 6-in. correlation interval and a 2-in. step and then plotted on a scale one-quarter of full size in order to match with the core photographs. Good dip agreement is apparent. Note the low contrast on the dip curves correlating to the fore-sets in the lower one-third of the photo. The truncation visible on the core is also evidenced on the dip plot. Such detail would not be possible with standard pad-to-pad correlation systems.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The good likeness of the side-by-side curves is useful in cases of high apparent dip. Under these conditions it becomes difficult to find an unambiguous curve match between the pads. Use of the side-by-side configuration allows reliable measurement of displacements between the curves from the same pad and computed dip values.</span><br /> </p><p><span style='font-family:Times'><strong>LOCDIP Computation</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>As discussed earlier, inflection points on the microresistivity curves describe geological events in the depositional sequence of the formation. The purpose of the LOCDIP program is to detect the geological events, or boundaries, and where applicable to associate a dip precisely at that boundary independent of dips at other depths. Instead of correlating intervals of curves, it detects features (inflection points) on each curve and attempts to link these around the borehole, in a manner somewhat similar to GEODIP processing. There are, however, some important differences:</span><br /> </p><p style='text-align: justify; margin-left: 81pt'><span style='font-size:10pt'><span style='font-family:Times New Roman'>·</span><span style='font-family:Arial Unicode MS'> To be retained as a LOCDIP result, an event must be recognized on at least seven of the eight microresistivity curves; GEODIP logic requires only three out of the four curves. Thus, LOCDIP logic is more demanding than GEODIP logic. <br /></span></span></p><p style='text-align: justify; margin-left: 81pt'><span style='font-size:10pt'>· A measurement of the planarity is derived for each of the possible dip planes at any level. The retained value corresponds to the surface that best approximates the set of these planes. By convention, a perfectly planar surface has a planarity of 100. <br /></span></p><p style='text-align: justify; margin-left: 81pt'><span style='font-size:10pt'>· Some events are recognized on only a few of the dip curves. In this case, the available correlations are traced across the applicable curves, with an "options" notation of "F" (fracture) or "P/L" (pebble or lens) for single-pad events or two/three-pad events, respectively. These interpretations, however, are not to be considered as certain, but rather as possible.<br /></span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The processing of the 8-curve data is designed to extract the maximum amount of dip information from the raw curves. A well may present several interpretation problems due to variations in lithology and bedding characteristics. A single computation system may not offer the total solution. It is useful, therefore, to be able to combine the results of several types of computation in one presentation.</span><br /> </span></p><p><br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>DUALDIP* Presentation</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The DUALDIP presentation for the 8-curve dipmeter tool allows results from more than one computation to be combined. <a href='javascript:figurewin('../../asp/graphic.asp?code=494&order=4','4')'>Figure 5</a> is an example of multiple computations on a short section. In the figure, the dips on the left side are side-by-side (CSB) results with a correlation length of 8 in. and a step of 4 in. This produces three dips per foot, or about 10 dips per meter.</span><br /> </p><p><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The tadpoles on the right are of two types. The round-headed tadpoles were computed from pad-to-pad correlations with a correlation interval of 4 ft and a step of 2 ft. This is the MSD computation.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The triangular-headed tadpoles are LOCDIP computations, also known as <em>pad-to-pad feature correlations. </em>These dips usually correspond to the more prominent bed boundaries, and are computed by the earlier mentioned pattern-recognition system. For each LOCDIP computation which used seven or eight of the dip curves, a solid correlation line is drawn on the plot showing exactly where the bed boundary was interpreted. For each of these correlations a local dip is shown. If fewer than seven curves are correlated, then the correlation is shown as a dotted line, but dip is not computed.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>This presentation not only gives a visual impression of the frequency of stratification and its planarity and parallelism, but it also allows the user to judge the validity of the correlations. This is of particular value in detailed studies of sedimentary features.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>All three systems may not, nor should they necessarily, give the same dip answer. This characteristic can be used to great advantage in interpreting sedimentary features, particularly thin, highly bedded clastics.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In <a href='javascript:figurewin('../../asp/graphic.asp?code=494&order=4','4')'>Figure 5</a> , the two local dips at A and B correspond to the top and bottom of a distinct sedimentary unit. They suggest the boundaries both dip at 1° northerly. All the finer bedding within these boundaries produced CSB or round-headed dips consistently north-northeast between 4° and 10°.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The internal bedding indicates sediment transport direction from south-southwest to north-northeast, with topset and bottomset surfaces approximately 1° northerly. The CSB result is different from that obtained from LOCDIP and MSD processing, whose computation system is restricted to major events, which can be correlated from pad to pad. The CSB logic favors events with some continuity; individual single events are less likely to be computed, particularly where both types are visible within the correlation interval. This tendency for different systems to favor different types of bedding planes has been very useful, particularly in the interpretation of fluvial environments.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Note also that the 4-ft MSD correlation showed the dip at C to be southwest about 90 and consistent over 4 ft. This is easily explained, considering the previous discussion of overlap effects, and it is supported by the LOCDIP computation at that depth. This boundary presents a dominant anomaly to the 4-ft correlation system, and for fine stratigraphy would be misleading by itself. When all bedding features, large and small, are parallel, all systems should give the same answer as at D.</span><br /> </p><p><span style='font-family:Times'><strong>Formation-Imaging Tool<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Successful dipmeter interpretation depends greatly upon the accurate evaluation of geological features. The application of the classic dip patterns is a relatively simple matter when geological events such as current bedding or lateral accretion are known. In many complex environments this is a severe problem. A whole core over the zone of importance solves these problems, but whole core availability is the exception rather than the rule. Formation imaging provides a continuous oriented borehole representation that can be used in conjunction with a whole core or, in most cases, by itself to evaluate geological events.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Interpretation </em>The goal of formation-image interpretation is to characterize formation properties to assist sedimentological interpretation, determine the presence of permeability paths and permeability barriers, help calculate net pay, plan perforation and fracturing, and to help decide whipstocks and where to drill next.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Formation images must always be interpreted after lithology has been fairly well defined, so supplemental data are usually necessary to enhance the confidence of image interpretation. As with other dipmeter interpretations, the more supplemental data available, the better the interpretation.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Measurement</em> The clustered microresistivity buttons on two or four of the microscanner pads provide a continuous electrical image of the borehole wall. The pads are oriented at right angles to achieve a three-dimensional perspective. These resistivity data are then mapped to a gray-scale or color "corelike" borehole wall image. This allows fine-scale features to be described through essentially the same interpretation procedure as that used in the examination of slabbed cores. The images characterize many types of structural and stratigraphic features. These oriented features, combined with a conventional dipmeter plot, are used to evaluate these events to extend the reservoir geometry beyond the wellbore.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Images of the rock formation exposed by the wellbore are processed from the microresistivity traces. Each image pad covers 2.8 in. of the borehole wall. Thus, 22% of an 8-in. borehole can be imaged with two pads and 44% with four pads on each logging pass. This coverage can be increased with multiple logging passes. The tool also contains a triaxial accelerometer and three magnetometers for orientation and to enable speed corrections to be made on the acquired data.<br /></span></p><p><span style='font-family:Times'><strong>Presentation of Images<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Several presentations are available for displaying the data. The vertical scale provides the most striking difference between the formation-imaging presentations and other logs. The normal detail scale for logs is 1:240, while the formation images are presented on a 1:5 scale. The standard presentations can be broadly classified into two types: <em>straight-line images</em> and <em>azimuthal images</em>.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Straight-Line Images</em> A straight-line presentation shows the images in a stationary horizontal scale ( <a href='javascript:figurewin('../../asp/graphic.asp?code=495&order=0','0')'>Figure 1</a> ). This presentation is divided into several sections. The left section contains the depth scale, the pad orientation, and the borehole deviation. The long arrow on the tadpole indicates the direction of borehole drift; the body of the tadpole indicates the magnitude of deviation by its position on the horizontal scale. The small arrow shows the azimuth of Pad 1. The next section contains the caliper and resistivity correlation curves. The calipers from Pads 1-3 and 2-4 are shown. The resistivity curve is used only for correlation and not for quantitative purposes. Pads 3 and 4 of the 2-pad tool provide the image. Both the raw microresistivity traces and the processed images are presented. The microresistivity traces are from the 27 image buttons. The image traces are computer enhanced using 16 gray levels; they range from white (resistive) to black (conductive).<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Another popular presentation is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=495&order=1','1')'>Figure 2</a> . In this example, the formation images are displayed on the same depth scale as the dipmeter log. This scale is not as effective for identifying individual sedimentary features but is better for displaying the overall features of a zone and showing how they relate to dip patterns.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Azimuthal Images</em> A BORMAP presentation is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=495&order=2','2')'>Figure 3</a> . The horizontal scale shifts according to the respective azimuths of each pad. Thus, multiple passes can be merged to portray a more complete picture of the wellbore. In this example, images from two logging passes (from a tool with two imaging pads) were merged to cover approximately 44% of the well-bore. There are vugs present at 4208.7 ft and at 4210.4 ft. This presentation is very effective for secondary porosity evaluation and for sedimentary structure identification.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Image-Examiner Workstation<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Image interpretation can be enhanced by means of a computer workstation equipped with image-examiner processing programs. This allows such interactive processing features as<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>scale changes of both the vertical and horizontal, to enhance the interpretation<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>a display of other logs for correlation on the same scales<br /></span></p><p style='margin-left: 81pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>graphic enhancement of specific features, such as bedding, texture, vugs, and fractures<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>dip computation of bedding surfaces, fault planes, and fractures<br /></span></p><p style='margin-left: 81pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>correlation of images to whole core sections, extending the interpretation to noncored sections<br /></span></p><p style='margin-left: 81pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>orientation of cores from features present in both the core and the formation images<br /></span></p><p style='margin-left: 81pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>quantification of images (such as sand count and calibration to core porosity) to increase interpretation accuracy<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Dip Computation/Thin Bed Definition </em>Computation of the dip magnitude and azimuth of specific beds is essential to many interpretations and can be performed on an image-examiner workstation. An example is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=495&order=3','3')'>Figure 4</a> . The magnitude is measured from horizontal (0°) to vertical (90°). The azimuth of the downdip direction is measured from true north. The thin sand shown at 6969 ft dips to the northwest. A sine wave is fit through both the upper and lower surface of the sand, indicating a 39° dip magnitude and an azimuth of 317°.<em><br /> </em>These dips are "true dip", since hole deviation is compensated. Apparent dips may be presented if a direct comparison with a whole core is required The actual thickness of the sand stringer, measured be-the sine waves, is 1.61 ft.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><br /> </span> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-63988878550863307542008-11-20T23:12:00.001-08:002008-11-20T23:12:49.386-08:00Dipmeter Surveys (Depositional Interpretation)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Depositional Interpretation <br /></span></h2></p><p><strong>Eolian Environment<br /></strong></p><p><span style='font-family:Times'><strong>Introduction<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>A dune is a hill of sand, deposited by wind, that rises to a single summit and possesses a slip face. Dunes may be various sizes and shapes depending on wind conditions, sand type, and sand supply. Dunes may be oriented perpendicular to the prevailing wind (e.g., <em>barchan </em>and <em>transverse </em>dunes), parallel to the prevailing wind (e.g., <em>seif </em>or <em>longitudinal </em>dunes), or they may acquire complex formations (e.g., <em>dome-shaped </em>or <em>star-shaped </em>dunes).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Dunes are the most impressive and important feature of a desert environment. They are also important geologically. The Nugget formation of the western United States, the Norphlet formation of the U.S. Gulf Coast, and the European Rotliegendes formation form important hydrocarbon reservoirs. The eolian Botucatu of Brazil is a large freshwater aquifer.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Much of the following information is based on the work of Reineck and Singh. (See <em>Depositional Sedimentary Environments, </em>1980, New York: Springer-Verlag.) <a href='javascript:figurewin('../../asp/graphic.asp?code=520&order=0','0')'>Figure 1</a> illustrates some typical dip patterns in eolian environments.<br /></span></p><p> <br /> </p><p><span style='font-family:Times'><strong>Parabolic Dunes<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Parabolic dunes are U-shaped sand ridges with their concave side toward the wind. Parabolic dunes are associated with blow-up features. The middle part of the parabolic dune moves forward ahead of the arms, which are believed to be hindered by vegetation.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The characteristic dip pattern of parabolic dunes is a red pattern at the center of the dune dipping in the direction of the prevailing wind ( <a href='javascript:figurewin('../../asp/graphic.asp?code=520&order=0','0')'>Figure 1</a> ).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The dips found near the tips of the arms may be skewed more than 90° from the direction of the prevailing wind.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Foreset laminae of parabolic dunes are low-angled relative to other dune types. The foreset laminae are characteristically concave-downward as a result of slip-face shape and the presence of vegetation. The azimuth spread of the dip of foreset laminae is rather large-up to 200°.<br /></span></p><p><span style='font-family:Times'><strong>Barchan Dunes<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Barchan dunes are crescent-shaped sand mounds occurring as isolated bodies, in chains, or in colonies of individual dunes coalescing into complex forms. Barchan dunes are formed by a unidirectional wind, and they migrate by sand avalanching on the slip face. The extremities or horns of a barchan extend forward and downwind, as the horns migrate more rapidly than the main body.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Simple barchans may be made complex by the coalescence of many sand dunes. In regions where the wind blows periodically from directions other than that of the prevailing wind, small, oblique slip faces may be produced, but the general dune form and direction of movement are retained.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>When interpreting eolian zones, note that the structural dip is at the left edge of the tadpole cloud unless the log is from an area that has undergone appreciable structural uplift. The general dip direction is in the direction of the prevailing wind. Near the horns, dips are less and may be almost 90° to the direction of the prevailing wind. The zones of crossbedding dips with constant magnitude near the center of barchan dunes reflect the angle of repose during deposition.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The angle-of-repose zones are underlain by fore set-generated blue dip patterns. The minimum dip found at the base of these blue patterns reflects the dip of interdunal layers and approximates structural dip. The foreset laminae of crossbedded units in barchan dunes are mainly planar (tabular types with a dip from 20 to 35° in the central part).<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=520&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> is a dipmeter log through the eolian Rotliegendes sand in Holland. The dip patterns are typical for barchan-type dunes.<br /></span></p><p style='text-align: justify'><br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>Dome-Shaped Dunes<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Dome-shaped dunes are low, circular sand ridges lacking a well-developed, downwind, steep slip face. Dome-shaped dunes develop when dune height is checked by a strong, unobstructed wind. The characteristic internal structure displays low-angled foreset laminae.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Dome-like dunes produce red dip patterns similar to parabolic dunes. The central portion of the dome contains dip in the direction of the prevailing wind. The dip left and right of the center may be skewed as much as 75° to the prevailing wind.<br /></span></p><p><span style='font-family:Times'><strong>Transverse Dunes<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Transverse dunes are elongate, almost straight sand ridges perpendicular to the predominant wind direction. These ridges are regularly spaced and are separated by broad interdune areas that may have developed as inland sabkhas.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Transverse dunes originate in areas of inland sabkhas, where the damp sabkha surface inhibits the growth of barchan horns. When the interdune sabkhas eventually disappear, a sand sea with transverse dunes may be produced. Dip patterns produced from transverse dunes are similar to the patterns found near the center of barchan dunes; the patterns consist of zones of angle-of-repose dips underlain by foreset-generated blue patterns.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Crossbedded units are mostly of the planar-tubular type. The foreset laminae are relatively long, even, and high-angled. The azimuth spread of foreset laminae dip is probably less than that of all other types of sand dunes, with one well-developed maxima in the direction of the prevailing wind.<br /></span></p><p><span style='font-family:Times'><strong>Longitudinal Dunes<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Seif or longitudinal dunes are elongate, continuous, serrated, straight sand ridges. Their long axes parallel the prevailing wind direction. Several seif dunes commonly occur as a series of long parallel ridges separated by broad interdune areas.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Sand is deposited alternately on opposite sides of the sand dunes. Crossbedding dips are normal to the elongation of the sand ridge; therefore, the two maxima of high-angle foresets are almost l80° apart. Locally, some low-angle bedding is present, especially in the lower part of a seif dune.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>It has been suggested that the most important factor in generating seif dunes is the existence of a strong wind with a uniform direction. The higher the wind velocity, the larger the seif dune and the greater the interdune spacing. All other conditions being equal, barchan dunes develop at lower wind velocities than seif dunes.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Seif dunes may be modified to barchan dunes if wind velocities are not strong enough to maintain the seif dune form. The depositional pattern in seif dunes produces red and blue dip patterns with an azimuth normal to the prevailing wind.<br /></span></p><p><span style='font-size:10pt'>Occasionally an azimuth reversal occurs within the blue patterns.<br /></span></p><p><span style='font-family:Times'><strong>Whalebacks<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Whalebacks are large-scale features associated with seif dunes. They are platforms of rather coarse-grained sediments left by the passage of a series of seif dunes along the same path.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The platform and the sides are composed of horizontally bedded sediments with crossbedded seif dune sediments below.<br /></span></p><p><span style='font-family:Times'><strong>Wadis<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Wadis are predominantly dry desert streambeds that are only active following sporadic, but often heavy, rains. Wadis are better developed near hills where the rainfall is slightly higher. Wadis are characterized by sporadic and abrupt fluvial activity and by a low water-to-sediment ratio. Deposition by flash floods is very rapid because of the sudden loss of velocity as the water is absorbed underground. Most wadis diverge downslope and deposit the bulk of their sediment in fan-shaped bodies at the downstream limit of the flow.<br /></span></p><p><span style='font-size:10pt'>Wadi channels are not permanent, and they may be filled by their own detritus or by wind-blown sediments. During subsequent seasons, a new channel system is likely to cut into the older sequences. Wadi channels produce dip patterns similar to those found in braided streams.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Small ripples, megaripples, and plane beds are the bedforms developed in wadi channels by the variable flow conditions. Deposits within the wadi channels may be conglomeratic and fanglomeratic. During certain phases of flow, the sediment transported through the wadi may resemble mud flows. The nature of the sediment is strongly controlled by source rocks and the availability of various grain sizes. Wadi deposits may lack pebbles and may contain only well-sorted sand. The deposits produce ripple and horizontal beddings.<br /></span></p><p><span style='font-family:Times'><strong>Desert Basins<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Desert basins represent areas of inland drainage with water flowing towards the center. Basins are often low depressions resulting from deflation of tectonic origin. Water accumulates in these low-lying areas, producing shallow, ephemeral lakes. The larger examples may be semipermanent desert lakes.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Inland sabkhas are formed when sediments are subjected to wetting by inflowing wadis or ground seepage, subsequent drying, and deposition of damp, salt-encrusted sediments. In deflation hollows, where the water table is higher than the ground surface, a small lake may develop. Sand dunes may be drowned and preserved as a consequence of a rising water table caused by seepage and inflowing water.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Abundant detrital sediment is brought to desert lakes and inland sabkhas during floods. As current velocity is almost nil, the deposition of silt and clay occurs from suspension, and individual thin beds may contain graded bedding. Gypsum, halite, and other evaporite minerals are commonly associated with these deposits. The uppermost clay layers may crack and curl during dry seasons, and these features may be preserved if covered by blown sand.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Detrital sediment is rarely deposited in lakes resulting from groundwater seepage; instead, salt pans are built. Some windblown detrital sediment may be incorporated as thin layers or impurities within the chemical precipitates.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Sediments of inland sabkhas are usually parallel-bedded with silty and clay-rich layers alternating with thin, sandy, gypsum or gypsiferous clay layers. These sediments are deposited as inflowing wadi sediments settle from suspension, or as wind-blown sediments are captured by adhesion ripples on the sabkha surface. Bedding is better developed in desert lake sediments than in inland sabkha sediments. Sabkha sediments sometimes generate only blank zones on the dipmeter plot.<br /></span></p><p style='text-align: justify'><strong>Deltaic Environment<br /></strong></p><p><span style='font-family:Times'><strong>Introduction<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Only a small percentage of modern coastlines are delta-dominated at any given time. Most coastlines are located in interdistributary environments where sediments deposited by older deltas are undergoing reworking and redeposition.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Deltas are constructed where rivers enter the sea. Where long-shore currents are weak and abundant sediments are available, deltas prograde seaward, forming elongate or birdfoot deltas. The modern Mississippi Delta is a classic example of a birdfoot delta. Strong longshore currents prevent or retard seaward progradation, and the resulting deltas form cuspate-arcuate shapes.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Deltas discharge seaward through active distributaries. Fan, crescent, or elongate sand bodies called <em>distributary mouth bars </em>or <em>distributary front sands </em>are deposited seaward of the mouth of each distributary. These and the following features are illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=521&order=0','0')'>Figure 1</a> .<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>During periods of high water, breaks occur in the natural levees formed along the distributary channel margins. Discharge through breaks or crevasses in the natural levees <em>forms crevasse splays. </em>Crevasse splays have the same shapes as distributary mouth bars. As the distributary channel progrades, bodies of water between distributary channels are constrained by sedimentary deposition into interdistributary embayments.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=521&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> is an example of dipmeter plots from a deltaic environment and a tide/wave-dominated environment. Distributary front deposition at rates of tens of feet of sediment per year exist. The associated rapid burial and subsidence appear important in sediment preservation because they prevent reworking of the sediments by waves, tides, and currents.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Identifying the Environment<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>It is possible to confuse a thin eolian sand section with a deltaic sand; therefore, recognizing a fossil delta depends in part on local knowledge that the sediments under investigation were deposited in a marine environment. If it is known that deltaic conditions existed during the deposition of a zone of interest, log character can be used to determine the probability of preserved deltaic sediments.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A strong family of mostly blue dip patterns is a good indicator. The blue patterns would be intermixed with a few red patterns with azimuths 90° from the blue patterns. Funnel-shaped SP and gamma ray curves are indicative of preserved deltaic sediments; however, a funnel shape alone does not identify a deltaic environment. Shale resistivities may provide clues on a strictly local basis to indicate that the zone of interest was deposited in a deltaic environment.<br /></span></p><p><span style='font-family:Times'><strong>Identifying Deltaic Features<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Once it has been determined that a zone of interest was deposited in a deltaic environment, the data should be compared to a generalized deltaic model. If the entire deltaic system was preserved, which is unlikely, the system would consist of the following:<br /></span></p><ul style='margin-left: 81pt'><li><span style='font-size:10pt'>distributary channels<br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>distributary mouth bars<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>crevasse splays<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>longshore current sand waves<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>marshes<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>These features become the pieces of the jigsaw puzzle you wish to solve. In the worst-case scenario, the entire delta would have been reworked, and all of the pieces would be missing. Usually, however, several of the pieces are present. They may be from adjacent parts of the puzzle, or they may fit randomly into the model with no adjacent pieces.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>There are several facts to help solve the puzzle. If the zone of interest was deposited during a deltaic period of deposition, strong dip patterns can be assigned a deltaic, rather than a reworked, origin. Also, the location of land during the time of deposition is known, at least approximately. Logs are responding to only fragments of each deltaic feature, not the entire system.<br /></span></p><p><span style='font-family:Times'><strong>Distributary Channels<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>If a complete depositional sequence were preserved, the dip patterns on the following illustrations would be seen. <a href='javascript:figurewin('../../asp/graphic.asp?code=521&order=2','2')'>Figure 3</a> shows the expected dip patterns within a distributary channel. When the channel is penetrated at or near its axis, only blue dip patterns, indicating flow down the channel, are recorded. The south-dipping blue pattern on this figure indicates flow down a north-south striking channel.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>When the channel is penetrated near the edge, only red dip patterns, dipping toward the channel axis, are found. Current velocities are lower near the channel edge; therefore, only laminar deposition occurs.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Between the two zones, a red-blue dip pattern combination is usually found. The basal layer of fill mimics the dip of the surface it is deposited on; therefore, the drape over the sloping surface of the channel cut creates a red pattern dipping toward the channel axis. This red pattern (or patterns) is overlain by blue patterns with a dip azimuth 90° to the underlying red pattern. These blue patterns result from flow down the channel. Foreset beds deposited by sediments transported down the channel are formed after the basal portion of the channel is filled and leveled.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Distributary Mouth Bars<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Within the distributary mouth bar seaward of the distributary channel mouth, only blue dip patterns would be recorded ( <a href='javascript:figurewin('../../asp/graphic.asp?code=521&order=3','3')'>Figure 4</a> ). These patterns indicate the direction of sediment transport.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The dip magnitude spread of the family of blue patterns is an indicator of the type of depositional environment and the probable sand geometry. If the magnitude spread of the family of dips is greater than 10°, the sand was probably deposited in an inertia-dominated environment, and the shape of the distributary mouth bar is probably elongate. If the family magnitude spread is 10° or less, the environment was friction-dominated, and the shape of the distributary mouth bar is probably fanlike or crescent.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The subsurface deltaic sediments usually consist of a stack of fossil delta remnants rather than sediments deposited by a single active delta. Dips belonging to patterns measured in the subsurface tend to be steeper than their original depositional angles. This steepening is probably the result of compaction.<br /></span></p><p><span style='font-family:Times'><strong>Discharge Direction<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The discharge directions of a delta are not always directly seaward. Some active distributaries of the modern Mississippi Delta discharge to the north-northeast-not to the south-southeast, which is the main direction of progradation.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=521&order=4','4')'><span style='font-size:10pt'>Figure 5</span></a><span style='font-size:10pt'> is an example of a preserved distributary mouth bar from the East Cameron Block 270 field. The distributary prograded to the northeast, a direction similar to the Main Pass distributary of the modern Mississippi Delta. Deltas may prograde almost across the continental shelf, as has the Mississippi Delta.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-family:Times'><strong>Distributary Channels and Distributary Mouth Bars<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Dip meters run in wells that penetrate both distributary channels and distributary mouth bars create the patterns shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=521&order=5','5')'>Figure 6</a> .<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Location A:</strong> A red pattern resulting from drape over an east-west striking channel overlies a blue pattern generated by distributary mouth bar sands transported from west to east.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><strong>Location B:</strong> The deepest blue pattern indicates distributary mouth bar sands. The overlying red pattern indicates drape over the base of the distributary channel. The shallowest blue indicates flow down the channel.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><strong>Location C:</strong> There is no red pattern indicative of drape at this location. Relative to the information from the other wells, it is possible to identify this as the channel axis. The underlying blue pattern indicates a distributary mouth bar sand. The overlying blue pattern indicates flow down the channel.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>This sequence is repeated on the opposite side of the channel, with red patterns dipping to the north (Locations D and E).<br /></span></p><p><span style='font-family:Times'><strong>Cuspate-Arcuate Deltas<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Rivers create cuspate-arcuate deltas by discharging their fresh water and sediments seaward, but the strong longshore currents transport the marine sediments in the direction of current flow, subparallel to the fossil coast-line. <a href='javascript:figurewin('../../asp/graphic.asp?code=521&order=6','6')'>Figure 7</a> is an example of a cuspate-arcuate delta from the Bekapai field, Mahakam Delta, Kalimantan. Strong longshore currents transported sediments that were carried to the sea by the ancestral Mahakam to the southwest. The dominant dip is southwesterly dipping blue patterns.<br /></span></p><p><br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>Creation and Destruction of a Delta<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The sediments deposited at a river mouth create increasing resistance to flow. Eventually, the river follows the path of least resistance and changes course. When the sediment supply to the delta is eliminated, deposition ceases, and destruction begins. Deltaic sediments exposed on land and the seafloor are attacked by rains, waves, currents, and tides. These destructive forces remove, re-sort, retransport, and redeposit the previously deposited sands and clays in new forms.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The amount of a fossil delta that is preserved depends on many variables: the depth of subsidence, the period of deltaic deposition, the thickness of the deltaic column, and the amount of protection from the open sea. One estimate by a knowledgeable geologist, Dr. John Kraft, estimates a worst-case preservation rate of less than one percent. The remaining 99% may be transported by waves, tides, and currents to be redeposited in an interdeltaic environment. <a href='javascript:figurewin('../../asp/graphic.asp?code=521&order=7','7')'>Figure 8</a> illustrates the dipmeter response in zones where some of the original bedding planes were destroyed by reworking.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Interdeltaic Environment<br /></strong></p><p><span style='font-family:Times; font-size:13pt'><strong>Introduction<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Many sediments deposited in an interdistributary environment by waves, tides, and currents were originally deposited within deltaic environments. Later reworking provided the raw materials for the interdeltaic deposition.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Dipmeter logs that were run through sediments deposited in interdeltaic environments tend to look rather sparse. They contain blank zones resulting from bioturbation and rooting, and open tadpoles from low-quality correlations.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>As is true in other marine environments, the direction to land during the time of deposition is a key direction ( <a href='javascript:figurewin('../../asp/graphic.asp?code=522&order=0','0')'>Figure 1</a> ). This information allows tentative identification of landwarddipping foresets deposited within tidal flood deltas, washover fans, and slipface deposits.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Other transport directions indicated by blue patterns are seaward-dipping ebb delta sands and sand waves deposited by longshore currents, paralleling the coast.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Beach sands dip seaward on their front portions and landward on their slip-face portions. Tidal flat sediments exhibit blue patterns dipping in opposing directions as a result of landward- and seaward-dipping foreset beds. Tidal channels in microtidal and mesotidal ranges generate red patterns dipping toward their axes.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In a microtidal range (less than 2 m), any ebb delta present would be small (<a href='javascript:figurewin('../../asp/graphic.asp?code=522&order=1','1')'> Figure 2</a> ). In microtidal environments, tidal inlets with pronounced flood deltas on their landward side exist. In a mesotidal range (between 2 and 4 m), a prominent ebb delta would be formed. In a macrotidal range (more than 4 m), a tidal estuary would be formed. Macrotidal estuaries contain sand bodies elongate in the directions of tidal flow.<br /></span></p><p style='text-align: justify'> <br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>Ebb Delta<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>In the ebb delta shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=522&order=2','2')'>Figure 3</a> , it is assumed that land is to the west and the coastline strike is north-south. A dipmeter log run at location A, in the southern portion of the ebb delta, would contain southeasterly dip, not directly seaward in an easterly direction. A dipmeter log run from a well drilled at location B would exhibit seaward or east dips. A well drilled at location C would penetrate both the marginal flood channel and the underlying ebb-deposited sediments. Foresets dipping back into the tidal channel were deposited on the flood tide; as a result, they dip to the southwest. Beds deposited during the ebb dip to the northeast.<br /></span></p><p><span style='font-family:Times'><strong>Tidal Channel<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Tidal channel dip patterns resemble patterns from other channel types. The basal layer of channel fill mimics the dip of the surface on which it is deposited. The channel base is a sloping surface except at the axis; therefore, red dip patterns are created with azimuths toward the channel axis and normal to the channel axis strike.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>After the fill smoothes and levels the channel base, foreset beds with dip along the channel are deposited. The type of deposition preserved-flood or ebb-depends on the location within the channel.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Sand waves formed within tidal channels may contain a large amount of shell hash. If preserved and buried, these waves would generate seaward-dipping blue dip patterns.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In <a href='javascript:figurewin('../../asp/graphic.asp?code=522&order=3','3')'>Figure 4</a> , the well location B is at or near the channel axis. Only sand-wave foresets would be deposited, because of the relatively flat underlying surface.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Flood Deltas<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Deposition within flood deltas occurs as landward-dipping foresets. Similar landward-dipping foresets are found within washover fans and slipface sands.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Dipmeter logs run at locations A, B, and C on <a href='javascript:figurewin('../../asp/graphic.asp?code=522&order=4','4')'>Figure 5</a> contain blue dip patterns dipping to the northwest, to the west, and to the southwest, respectively. Particular caution must be exercise in the interpretation of dipmeter logs run through sediments deposited in a tidal environment. The most significant dips are de rived from sediments deposited within the flood delta, the ebb delta, and the tidal inlet.<br /></span></p><p><span style='font-family:Times'><strong>Swash Bar and Recurved Spit<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Two groups of dips that may produce conflicting interpretations are <em>swash bars </em>and <em>recurved spits. </em>Swash bar dips create land-ward-dipping blue patterns, which can be mistaken for flood delta dips. This can lead to an offset seaward of the terminal lobe. The best approach to identifying swash bar deposits is to expect them to be preserved near the tops of tidal sands or carbonates; therefore, beware of blue patterns existing only in the top of a tidal sequence. Landward-dipping blue patterns from flood deltas should extend throughout most of the sand or carbonate under study.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Recurved spit dips are the other set of problem blue dip patterns. They tend to dip away from the inlet and can contribute to offsets in the wrong direction. These dips can be recognized by their dip in the direction of coastline strike.<br /></span></p><p><span style='font-family:Times'><strong>Longshore Current Sand Waves<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Longshore current sand waves are composed of fore set beds that generate blue dip patterns paralleling the fossil coastline. Deep water contains longshore currents strong enough to redistribute sands previously deposited by turbidity flows.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>To identify sand waves, one must (1) know that the sequence being interpreted is from an interdeltaic depositional environment and<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>(2) determine the direction to land during the time of deposition.<br /></span></p><p><span style='font-family:Times'><strong>Beach Sands<br /></strong></span></p><p><span style='font-family:Times'><strong>Shoreface Sands<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Shoreface sands were deposited between the beach and a water depth of 20 m, the fair-weather wavebase. These sands were deposited in a high-energy environment, and few, if any, of the bedding planes were deposited flat. After deposition, bioturbation occurred, destroying or distorting the original bedding.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Dipmeter logs run through shore face sands record a few widely scattered dips and blank zones because of bioturbation. Bioturbation decreases in the shallowest portion of the shore face zone; therefore, more dips are recorded as the mean low water line is approached. Beginning at depths of about 5 m, some low-angle, seaward-dipping crossbeds were deposited and preserved. These beds initially dip seaward 1° or 2°. Flaser bedding is also present in the lower shoreface zone.<br /></span></p><p><span style='font-family:Times'><strong>Beachface Sands<br /></strong></span></p><p><span style='font-size:10pt'>Beachface sands were deposited as parallel crossbeds dipping seaward plus or minus 5°.<br /></span></p><p><span style='font-family:Times'><strong>Runnel<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Deposition within a runnel may appear as megaripples dipping parallel to the beach, small ripples, or laminations. Preserved megaripples generate small blue dip patterns best identified by CSB computation. Small ripples usually create blank zones or false correlations; however, they can be identified on the multisensor dipmeter output of the 8-curve tool.<br /></span></p><p><span style='font-family:Times'><strong>Berm Crest<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Deposition on the berm crest is essentially horizontal. If preserved, the beds would indicate structural dip. Dunes, which also form on the berm crest, contain festoon cross-bedding, which generates a wide dip scatter.<br /></span></p><p><span style='font-family:Times'><strong>Back Beach<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>If the back beach escaped bioturbation by fiddler crabs or their ancestors, it would contain landwarddipping foresets that generate blue dip patterns. These landwarddipping patterns are the best indicators for determining the strike of a fossil beach.<br /></span></p><p><span style='font-family:Times'><strong>Washover Fans<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Washover fans generate landward-dipping blue patterns similar to slip face foresets and flood delta foresets. The character of other log responses provides clues for distinguishing these features.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Washover fans were deposited over marsh deposits by a catastrophic event. This process did not allow for appreciable sorting. Flood deltas were deposited in a subaqueous environment with winnowing before final deposition.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Slipface sands were deposited on a land surface containing some plant material; this, in turn, created a rooted layer. The rooted layer generates blank dip zones and is electrically more homogeneous than undisturbed bedding.<br /></span></p><p><span style='font-family:Times'><strong>Barlike or Convex-Upward Sands<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Barlike or convex-upward sands may be formed at the wave break point or as beach ridges. There is one distinct difference between these two types of sand Break point-bar sands are winnowed until there is little internal electrical contrast; therefore, dipmeter logs exhibit mostly blank zones. In contrast, beach ridges exhibit many internal dips ( <a href='javascript:figurewin('../../asp/graphic.asp?code=522&order=5','5')'>Figure 6</a> ).<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>When either type of sand is penetrated on the flanks, the drape the overlying beds creates a red dip pattern just above the sand A fault can create the same dip pattern; therefore, faulting must be ruled out before any stratigraphic interpretation is attempted The direction of the red pattern is toward the shaleout and normal to the strike of the bar or beach ridge. If the bar or ridge is penetrated at or near the crest, no drape would be present, and the sand would appear blanket-like.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>These same guidelines can be applied to oolitic bars. The drape extends beyond the limits of barlike sands. A red pattern in the silty zone, where a bar should have been located, dips away from the bar, and it can be used to determine the direction of sidetrack.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In some cases only blue patterns dipping toward the shaleout are found above a bar ( <a href='javascript:figurewin('../../asp/graphic.asp?code=522&order=6','6')'>Figure 7</a> ). These patterns tend to be components of a very subtle red dip pattern, and may be partially related to slump of the clays deposited above the bar.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Deep Water Environment<br /></strong></p><p><span style='font-family:Times'><strong>Introduction</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>This chapter addresses the processes of deposition and the resulting dip patterns encountered in deepwater environments. The processes of mass transportation are able to move, transport, and lay down sediments between their zone of origin and a topographically lower zone under the influence of gravity. Generally, these mechanisms provide intermittent and catastrophic transfers of large amounts of sediments, which are deposited at or near the base of a slope.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Mass transport consists of rockfalls, slides and slumps, and gravity flows (<a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=0','0')'> Figure 1</a> ).</span><br /> </p><p><span style='font-family:Times'><strong>Rockfalls</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Rockfalls are formed by free-falling bodies of sediments accumulating at the bases of fault scarps, canyon floors, and other steep slopes. The deposited sediments generally exhibit distinct limits, but no bedding.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The dimensions of clasts that form rock falls vary from sand-size to blocks measuring several tens of meters. The clasts are in contact and generally contain intergranular porosity.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The sequences resulting from submarine rock falls are often related to forereef escarpments or platform edges. On slopes in deep-sea environments, rockfalls may contain abyssal sediments. The accumulation of sediment blocks caused by rock slides can only occur at the foot of strongly inclined slopes, which are often characteristic of carbonate margins.</span><br /> </p><p><span style='font-family:Times'><strong>Slides and Slumps</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Subaqueous slides occur when a mass of semiconsolidated sediments moves along a basal shear surface. These slides are able to transfer considerable masses (up to tens of cubic kilometers) of sedimentary materials from the inner or outer continental platform to the abyssal plain. Any internal bedding characteristics of the mass are preserved during movement. Slides can be divided into <em>translational </em>or <em>glide </em>and <em>rotational </em>or <em>slump </em>types. The basal shear surface of a glide is a plane of slightly undulating surface paralleling the stratification.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In a slump, the concave shear surface permits rotation of the slump block. As a slump block moves down a slope, compression occurs at the foot of the block, and tension occurs at its rear. Compression produces thrusts and folds, and tension produces normal faults and open cracks. The central part of the block is generally not deformed.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Slump blocks penetrated in the subsurface are not always easy to identify. They may appear on the dipmeter as an isolated trend. When this occurs, the most probable explanation is either a tilted fault block (most commonly found between two nearby faults) or a slump block. If faulting can be ruled out, then the slump block becomes the most probable explanation.</span><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>Gravity Flow</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Sediment gravity flow is a general term for flows of mixed sediments and fluids in which the bedding coherence is destroyed and the individual grains move in a fluid medium. This includes mud flows or debris flows, grain flows, liquefied flows, and turbidity flows.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Mud flows exhibit essentially plastic behavior with the muddy carrier phase creating sediment coherence. The matrix containing the clasts is the main driving and lubricating force behind the flow.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The dynamics of grain flows are governed by the reciprocal interaction of clasts. This granular interaction causes sandy flows to exhibit plastic mechanical behavior rather than fluid behavior. In contrast, liquefied flows, fluidized flows, and turbidity currents exhibit a fluid behavior. Grain flows consist of cohesion-less sediment supported by dispersive pressure. This process requires steep slopes for initiation and sustained downs lope movement.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Liquefied flows consist of cohesionless sediment supported by upward displacement of fluid as loosely packed structures collapse. The sediments settle into tightly packed textures. Liquefied flows require slopes of greater than 3°.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Fluidized flows consist of cohesionless sediment supported by upward motion of escaping pore fluid. These flows are thin and short-lived.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Turbidity current flows contain clasts supported by fluid turbulence. These flows can move long distances on low-angle slopes.</span><br /> </p><p><br /> </p><p><span style='font-family:Times; font-size:13pt'><strong>Submarine Channel-Fan Complex</strong></span><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> illustrates the features found during the growth of submarine fans. Of these features, the obvious deepwater features interpretable by dipmeter logs are debris flows, which result in blank zones; feeder channels, which produce typical red dip patterns at the base and blue patterns with a 90° azimuth difference above; and midfans, which generate blue dip patterns. Outer fan sediments generate structural dips.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A submarine channel-fan complex can exhibit the same features as a delta complex, including natural levees. Submarine feeder channels are cut by downs lope sediment flows and later filled ( <a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=2','2')'>Figure 3</a> ). As with other types of channels, the basal layers of fill mimic the dip of the underlying surface. Deposition on a sloping surface produces a red pattern dipping toward the channel axis and normal with the channel strike. After the bottom was filled and leveled, foresets dipping down the channel were deposited; these, in turn, generated blue patterns dipping 90° from the underlying red patterns.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the midfan portion of the system, only blue patterns dipping in the direction of sediment transport are detected. Few obvious foreset beds are found within midfan outcrops, and this raises the question of what the dipmeter tools are measuring. It is possible the dipmeter sensor is detecting some type of permeability change associated with timelines or climbing ripples. Permeability changes do not always have a visual representation and may appear only on X-ray photographs.</span><br /> </p><p><span style='font-size:10pt'>In the outer fan portion of the system, only structural dips are detected because deposition was essentially horizontal. This is an environment in which the deposition of alternating laminations of sand and shale may become low-resistivity pay zones.</span><br /> </p><p><span style='font-family:Times'><strong>Transport Directions</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A common feature of deepwater sands is that transport directions are not directly offshore. Some sediments were transported parallel to the continental shelf while others were transported back into land ( <a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=3','3')'>Figure 4</a> ).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Landward transport can be a function of seafloor topography or it can be initiated by the presence of a down-to-the-basin growth fault. Whatever the cause, inshore transport in deepwater depositional environments does occur.</span><br /> </p><p style='text-align: justify'> <br /> </p><p><span style='font-family:Times'><strong>Deepwater Longshore Currents</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In some areas, considerable numbers of blue dip patterns indicate sediment transport parallel to the slope. This is a result of the reworking of previously deposited sediments by deepwater longshore currents. This is another environment conducive to the deposition of alternating sand-shale laminations.</span><br /> </p><p><span style='font-family:Times'><strong>Submarine Canyons</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Submarine canyons exhibit alternating up and down canyon sets of blue dip patterns generated by deepwater tidal action ( <a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=4','4')'>Figure 5</a> ).</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Submarine canyon fill sands closely resemble tidal sands on the dipmeter plot. The fill sands contain many blue patterns dipping both up and down the canyon. These patterns were probably generated by deepwater tidal action within the canyon. Canyon fill sands may be up to a thousand feet or more in thickness. They may also exhibit indicators of compaction underneath-e.g., downward-decreasing resistivity or increasing interval transit time gradients.</span><br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>Turbidity Flows</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Turbidity flows produce complex sand packages containing multiple depositional units. Separate reservoirs may be present, though sand-to-sand contact seems probable. <a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=5','5')'>Figure 6</a> illustrates dip patterns encountered in sand packages produced by turbidity flows. This package is made up of at least six submarine fans, two scour channels, and a sediment layer deposited in the upper portion of a submarine feeder channel. In other areas, this portion of the channel is filled with conglomerate. Shale layers are not required to separate one reservoir from another; an inch or so of silt suffices.</span><br /> </p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Debris Flows</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Debris flows are best recognized by the dual-dip curves themselves, since few (if any) meaningful dips are produced. Some correlations not extending around the four pads are seen on the presentation, but no tadpoles are produced. Conglomerates can produce these features.</span><br /> </p><p style='text-align: justify'><span style='font-family:Times'><strong>Feeder Channels</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The depositional environment of the sand at 6400 ft in High Island Block 560-561 is a continental slope environment; therefore, feeder channels would be the most probable feature ( <a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=6','6')'>Figure 7</a> ). The expected dip model would be a red dip pattern at the base of the sand section, with blue patterns above. The red pattern azimuth is toward the channel axis and normal to its strike. The blue dip patterns indicate flow down the channel. The azimuth of the blue patterns is approximately 90° from the azimuth of the red patterns.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The dipmeter log on Well 4 of High Island Block 561 exhibits the expected dip patterns for a filled feeder channel. The basal red pattern dips to the northwest, which is the direction of the channel axis. The overlying blue patterns dip to the southwest, which indicates flow down the channel from northeast to southwest.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The lower portion of the example shows the same dip pattern combination from the sand at 8900 ft. In this example the red pattern dips to the north; therefore, the channel axis lies north of the well, and the channel strike is west to east. The east-dipping blue pattern indicates sediment transport down the channel from west to east.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The relative magnitudes of the dip patterns in these examples indicate their approximate positions within their respective channels. The sand example at 6400 ft contains several blue patterns, but only one red pattern; this indicates a position near the channel axis, where the blue patterns dominate. Had the location been nearer the channel axis, only blue dip patterns would have been present.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The thin 8900-ft sand contains a strong red pattern and a weak blue pattern. This indicates a position near the edge of the channel, where current velocities were lower and drape over the underlying surface was the dominant type of deposition. Transport in this channel was from west to east paralleling the fossil coastline. This orientation may result from flow parallel to a down-to-the-south growth fault system in the area.</span><br /> </p><p><span style='font-family:Times; font-size:13pt'><strong>Dip Scatter as an Environment Indicator</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Dip scatter results from both the original attitude of deposition and postdepositional deformation. The products of both processes are diagnostic depositional indicators. The following comments on scatter are confined to a marine environment.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The marine ecological zones, their defining depths, and their location on the continental shelf and slope are illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=7','7')'>Figure 8</a> . The original concept of less scatter on the lower continental slope was due to a lack of paleo-calibrated dipmeter logs run through lower slope sediments. Later observations of dipmeter logs run in paleo-identified lower slope sediments confirmed that some of the greatest sediment jumbles exist at the base of the continental slope. Dip scatter is best used with shale resistivities, density-neutron responses, and other indicators.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>When deltaic deposition is preserved in its original form, it can mask effects of the surrounding depositional environment. Indicators are more obvious in a tide/wave-dominated environment than in a delta-dominated environment (<a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=8','8')'> Figure 9</a> , <a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=9','9')'>Figure 10</a> , <a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=10','10')'>Figure 11</a> ).</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify; margin-left: 72pt'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Inner neritic deposition in a tide/wave-dominated environment generates a 40° dip scatter and blank zones. Some scatter results from a high initial angle of deposition, but much of it is the result of bioturbation. Bioturbation produces zones of no correlation or zones where miscorrelations are probable. Near the 20-m boundary between the inner and middle neritic zones, the amount of bioturbation and the corresponding dip scatter decrease.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The scatter across the middle neritic zone ranges from 20° on the shoreward side to 3° on the seaward side. Local experience allows additional subdivision of the middle neritic zone into 50- to 100-ft, 100- to 200-ft, and 200- to 300-ft ranges.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Dip scatter in outer neritic sediments ranges from none, where parallel laminations exist, to 2°. Sediment spreading by long-shore currents in this zone can produce laminated, low-resistivity pay zones.</span><br /> </p><p><span style='font-family:Times'><strong>Continental Slope Sediments</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Dipmeter logs run through continental slope sediments tend to be difficult to interpret because of postdepositional deformation by downslope creep, slump, and fracturing. Shales, in particular, may be so severely deformed that few meaningful dips can be computed. Sometimes the only intact bedding planes are found within sands; when this occurs, the sand dips are used for determining structure.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Shale resistivities can provide clues to the proximity of sand bodies associated with shorelines or deltaic depositions. Shale resistivities are partially a function of grain size; therefore, the presence of silt-sized particles increases the resistivity values. Assuming a model progressing from sand to silt to clay, the presence of increased silt creates higher shale resistivity values.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the northern Gulf of Mexico, shale resistivities less than 0.8 ohm-m usually indicate deposition in a slope or abyssal depth range. There are, however, exceptions to this general rule.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Dip scatter of 60° on the continental slope results from postdepositional deformation. The scattered dips result from deformation; they are not related to structural or stratigraphic dips. The dip scatter again decreases to a maximum of 2° in the abyssal range. Some sediment transport by deepwater longshore currents also occurs in this environment.</span><br /> </p><p><span style='font-family:Times'><strong>Sea Level Fluctuations</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A Pleistocene example illustrates changes in scatter resulting from sea level fluctuations during glacial and interglacial periods. During the interglacial periods, sea level is high and deposition occurs in low-energy environments-probably the outer shelf. This permits layer-cake deposition with dip variations less than 3°. During glacial periods, the sea level drops, and deposition occurs in inner and midshelf environments. The environmental changes increase dip scatter considerably.</span><br /> </p><p><span style='font-family:Times'><strong>Compaction Features</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Many thick, channel-like sands were formed by compaction, not by the cut-and-fill process. Sands deposited on a mud bottom gradually sank downward, compressing and dewatering the underlying muds.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Shales formed from compressed muds exhibit downward-decreasing resistivity gradients and downward-increasing interval transit time gradients. Density-neutron log response gradients are also present (<a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=11','11')'> Figure 12</a> ).</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The dip pattern resulting from compaction is a mega-red pattern with interspersed blue groups dipping in the same direction. No right-angle relationship exists between the azimuth of the red and blue dip groups, as it does in features resulting from the cut-and-fill process.</span><br /> </p><p><span style='font-family:Times'><strong>Deepwater Chalks</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Localized dipmeter interpretation rules are occasionally convenient. The following set of rules was developed for the deepwater chalks of the Norwegian Central Graben. <a href='javascript:figurewin('../../asp/graphic.asp?code=523&order=12','12')'>Figure 13</a> illustrates an Ekofisk chalk example. In developing these rules, it was noted that chalk wells whose dipmeter logs exhibited many blank or scattered dip zones and dip patterns were better producers than wells containing zones exhibiting mainly structural dips.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>To quantify the interpretation process, multipliers or weights of 4, 2, and 1 were assigned respectively to blank or scatter zones, red patterns, and blue patterns. These arbitrary weights are based on the permeability of each type of zone.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Blank or scatter zones result primarily from chalk debris flows or conglomerates that contain the highest permeability; therefore, they were assigned the highest weight.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Red dip patterns represent beds draped over a sloping surface. These draped layers permit laminar flow, which has a lower permeability; therefore, red patterns were assigned a weight of two.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Blue dip patterns indicate foreset-generated crossbeds cutting across the reservoir at some angle that interfered with flow into the well. Blue dip patterns have the lowest permeability and the lowest weight factor.</span><br /> </p><p><span style='font-family:Times'><strong>Reservoir Quality Factor</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The following equation was developed to determine whether a chalk interval is capable of commercial production. The potential for commercial production was called the quality factor. The quality factor is the proportion of the total footage under study contributed by each type of zone multiplied by the weight factor for the zone. The equation is given below:</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where:</span><br /> </span></p><p><span style='font-size:10pt'>F<sub>D</sub> = the total footage of dipmeter blank or scattered dip zones</span><br /> </p><p><span style='font-size:10pt'>F<sub>r</sub> = the total footage of dipmeter red patterns</span><br /> </p><p><span style='font-size:10pt'>F<sub>b</sub> = the total footage of dipmeter blue patterns.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Using this approach on operator data, it was discovered that chalk intervals such as the Ekofisk, Tod, or Hor with quality factors of 2.6 or greater contained intervals capable of commercial production.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>For the commercial threshold of 2.6 to be a reliable indicator, the interval must be sufficiently thick. Quality factors can be contoured on both regional and fieldwide bases for the Central Graben area. Other weight factors could have been chosen that would have worked as well. The value of the commercial threshold would have changed. Similar techniques may have applications in areas where sandstones have undergone some downs lope creep and slump or shallow-water working.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Fluvial Environment<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Fluvial Channel Environment<br /></strong></p><p><span style='font-family:Times; font-size:13pt'><strong>Interpretation of Fluvial channels<br /></strong></span></p><p><span style='font-size:10pt'>The following are the five basic steps in interpreting a dipmeter log for a fluvial channel:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Determine the structural dip (and delete it if necessary).<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Determine the stratigraphic encasement.<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Define the depositional environment.<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Orient the sand trend.<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Locate the offset.<br /></span></p><p><span style='font-family:Times'><strong>Structural Dip<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Structural dip is determined from the shales above and below the channel. These dips may be different, since channels frequently occur as unconformities. The shale above the channel usually reflects the structural dip required for interpretation. In very low-angle situations, the stratigraphic gain may be more important than structural dip. The influence of coalescing channels repeatedly affects the structural position of fluvial channels.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Generally, if structural dip is greater than 4°, then the structural dip should be deleted. Sometimes, if the dip magnitudes are low (less than 10°), then even 2° dip should be removed.<br /></span></p><p><span style='font-family:Times'><strong>Stratigraphic Encasement<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The stratigraphic encasement is the interval in which the channel facies occur, including both the sand and shale components of a channel. Detailed correlations with offset logs are used for defining the stratigraphic encasement. Under special circumstances, the channel abandonment facies, or clay plug, can be identified from higher gamma ray or more resistive shale log responses. Red dip patterns, reflecting compaction features, may also be used to define channel facies. In all cases, identifying the interval is critical to the interpretation.<br /></span></p><p><span style='font-family:Times'><strong>Depositional Environment<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Success in defining the depositional environment depends on the geologist's input, core and sample data, log responses, formation images, and dipmeter arrow plots.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Local knowledge of the geology is very important in identifying the environment. Cores and samples are an integral component in new areas and are always useful in any area.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Electrical formation images are a valuable aid to the interpretation of the thin, fluvial sand zones.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Log responses are generally used to identify a fining-upward sequence, which infers a channel system. Distinguishing a braided stream from a meandering stream is only possible when very simple depositional sequences are penetrated. The braided stream contains several fining-upward sequences within the sand. A meandering stream contains one overall fining-upward sequence. This becomes very complex when the borehole penetrates several coalescing units. Coalesced point bars occurring in meandering streams may be interpreted as braided streams.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Dipmeter patterns are very similar in braided and meandering stream environments. Families of red and blue dip patterns with 90° azimuth differences typically occur in both environments. Braided streams can sometimes be recognized by the identification of transverse bars within the stratigraphic encasement.<br /></span></p><p><br /> </p><p><span style='font-family:Times'><strong>Channel Orientation<br /></strong></span></p><p><span style='font-size:10pt'>Channel orientation from dipmeter patterns is usually determined by the following priorities:<br /></span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>1. strong blue<br /></span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>2. strong red<br /></span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>3. weak blue<br /></span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>4. weak red<br /></span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>5. erosional or drape<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Channels are generally elongated parallel to the blue patterns and perpendicular to the red patterns.<br /></span></p><p><span style='font-family:Times'><strong>Locating the Offset<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Considerations for locating an offset include reservoir geometry, reservoir quality, structural position, surface restrictions, and secondary-recovery prospects.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Reservoir quality is determined primarily by permeability, bed thickness, and porosity. In a point bar, for example, the coarser, better-developed sand is generally near the thalweg, and fine-grained, poor-permeability sand is generally near the inside bank. Also, the leading edge of a point bar usually has better sand quality than the trailing edge.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Structural position is critical when a water or gas contact has been penetrated. The structural position often depends on compaction over coalescing channels and stratigraphic gains within the channel system.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Optimum location of an injection or a production well in a secondary-recovery project is dependent on the relative position of the well in the reservoir. A well near the leading edge of a point bar, for example, usually depletes quickly on primary production. The well can only produce from one direction, toward the middle of the point bar. This well can be used quite effectively as an injection well.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Required Accuracy </em>Fluvial channels are usually narrow in width. This requires high accuracy in the measurement of the channel orientation. Typically, fluvial channels have a productive width of approximately 40 times their productive thickness. A 10-ft thick channel sand has an estimated productive width of 400 ft.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>An azimuth diagram, as shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=1825&order=0','0')'>Figure 1</a> , can help in defining the channel orientation. There are several segments to the diagram.<br /></span></p><p style='text-align: justify'><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'>1. Depths are determined from the logs and the dipmeter plot.<br /></span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>2. The geologist and the dipmeter interpreter agree up on the type of deposition.<br /></span></p><p style='text-align: justify; margin-left: 81pt'><span style='font-size:10pt'>3. Structural dip is determined from the surrounding shale sections. If the dip above and below the sand is different, the sand is assumed to be deposited at an unconformity and the structural dip above the sand is recorded.<br /></span></p><p style='text-align: justify; margin-left: 81pt'><span style='font-size:10pt'>4. Confidence rating is a means to rank the quality of the interpretation. The rating is from A (highest) to D (lowest): A = strong blue and red, B = strong blue or red, C = weak blue or red, and D = erosion, drape, or intuition.<br /></span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>5. Orientation is shown as a line along the sand trend.<br /></span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>6. Current flow is the arrow on the end of the orientation line.<br /></span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>7. Channel thalweg is the arrow in the center of the azimuth diagram.<br /></span></p><p><br /> </p><p><br /> </p><p><strong>Determination of Well Position in a Point Bar<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>A relation between the blue and red dip patterns allows the determination of relative position in a point bar ( <a href='javascript:figurewin('../../asp/graphic.asp?code=1825&order=1','1')'>Figure 2</a> ). Blue pattern azimuths are usually parallel to the sand axis, since current flow is across the point bar. Red pattern azimuths are generally perpendicular to the sand axis and point toward the channel thalweg.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>For wells located on the leading edge of a point bar, blue and red pattern azimuths are normally greater than 90° in angle difference. When a well is located midpoint, the blue and red pattern azimuths are approximately 90° different (perpendicular) to each other. For wells positioned on the trailing edge of a point bar, the blue and red pattern azimuths are usually less than 90° in angle difference.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=1825&order=2','2')'><span style='font-size:10pt'>Figure 3</span></a><span style='font-size:10pt'> shows a dipmeter plot through a Cretaceous sand interval in a fluvial meander channel. The strong NE red and SE blue dip patterns show the channel thalweg to be N67E, a current direction of S47E, and an orientation of N47W-S47E. The angle difference between the red and blue dip pattern azimuths is slightly less than 90°. This indicates the well position to be on the trailing edge of a point bar.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Exercise 1.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>This exercise uses a classic deltaic example. The sand, shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=1613&order=0','0')'>Figure 1</a> , from 6744 ft to 6900 ft was deposited in a deltaic environment.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In which part of the delta complex was this sand deposited? What is the strike of the sand?<br /></span></p><p><span style='font-size:10pt'>In what direction is the thickest part of the sand body? What was the direction of current flow?<br /></span></p><p><span style='font-size:10pt'>Was the entire sand deposited as one feature, or was there more than one feature deposited?<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Solution 1:<br /></span></p><p><span style='font-size:10pt'>This sand was deposited as fill within a distributary channel.<br /></span></p><p><span style='font-size:10pt'>The strike of the channel is NE-SW.<br /></span></p><p><span style='font-size:10pt'>The axis lies to the NW of the well.<br /></span></p><p><span style='font-size:10pt'>Current flow was down the channel from NE to SW.<br /></span></p><p><span style='font-size:10pt'>There is more than one channel present.<br /></span></p><p><span style='font-size:10pt'>The main channel is below 6784 ft. This is the feature to consider when offsetting the well.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Above 6784 ft, the current flow diminished as the channel began to fill with sand, and channel switching occurred.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>There is another minor channel between 6784 and 6761 ft. Its strike is also NE-SW, and its axis lies to the NW. Flow was from the NE to SW. The few scattered dips within this interval indicate some reworking.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Exercise 2.<br /></span></p><p><span style='font-size:10pt'>In <a href='javascript:figurewin('../../asp/graphic.asp?code=1614&order=0','0')'>Figure 1</a> , the sand between 3810 and 4060 ft was deposited in an interdeltaic environment.<br /></span></p><p><span style='font-size:10pt'>What type of sand is it?<br /></span></p><p><span style='font-size:10pt'>What are its attributes?<br /></span></p><p><br /> </p><p><span style='font-size:10pt'>Solution 2:<br /></span></p><p><span style='font-size:10pt'>This sand is the product of previously deposited deltaic sediments reworked by waves, tides, and currents.<br /></span></p><p><span style='font-size:10pt'>The top of the sand is now barlike, and it shales out to the NE. The strike of the sand is NW-SE.<br /></span></p><p><span style='font-size:10pt'>The blank zone near the top results from shallow-water reworking and bioturbation.<br /></span></p><p><br /> </p><p><span style='font-size:10pt'>Exercise 3.<br /></span></p><p><a href='javascript:figurewin('../../asp/graphic.asp?code=1615&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> represents a Pennsylvanian sand deposited in a fluvial meander channel.<br /></span></p><p><span style='font-size:10pt'>What is the current flow direction?<br /></span></p><p><span style='font-size:10pt'>What is the thalweg direction?<br /></span></p><p><span style='font-size:10pt'>What is the channel orientation?<br /></span></p><p><span style='font-size:10pt'>Construct the azimuth diagram.<br /></span></p><p><span style='font-size:10pt'>What is the position of this well on the point bar?<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Solution 3:<br /></span></p><p><span style='font-size:10pt'>The current direction is south.<br /></span></p><p><span style='font-size:10pt'>Channel thalweg is N41W.<br /></span></p><p><span style='font-size:10pt'>The orientation is along the blue pattern azimuth (NS)<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The angle difference between the red and blue pattern azimuths is greater than 90°. This indicates that this well is on the leading edge of the point bar.<br /></span></p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-76550927394733727752008-11-20T23:11:00.001-08:002008-11-20T23:11:49.616-08:00Dipmeter Surveys (General Principles)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>General Principles <br /></span></h2></p><p><span style='font-family:Times'><strong>Introduction<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Since its introduction in the 1930s, the dipmeter tool has found steadily increasing application in the petroleum industry. Used initially in exploration, the tool helped to locate and identify the major features of geologic structure serving as oil traps. As techniques became more refined and interpretation became more secure, the dipmeter's range of applications expanded, making it the principal logging tool for describing internal lithologic features and the sedimentological processes responsible for them.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The current emphasis on investigating sedimentary bedding conditions has further enhanced the utility of the dipmeter log. The high sampling density of 120 readings per foot of borehole depth makes the dipmeter tool virtually the only logging device that can supply the petroleum geologist with detailed information on finestructured sedimentary beds in the subsurface.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The dipmeter tool measures conductivity or resistivity changes, hole size, and sonde orientation-nothing more, nothing less. It does not directly measure the dip of bed boundaries or the dip of lithology changes. The conductivity changes are input into a computer program that correlates the recorded wiggle traces and computes apparent dip from the correlations. Computed dips are then corrected for sonde tilt and converted into true dips. The true dips are plotted and used to make inferences of structural dips, bed geometries, and depositional environments.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Dips displayed on the tadpole or arrow plot result from a combination of the original depositional dips, differential compaction and structural rotation during subsidence, and postdepositional deformation.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>AS is true with other logs, information other than that contained on the dipmeter log is required to make the best interpretation. The minimum required input from the geologist is to describe missing sections and depositional environments. The more information available, the better the dipmeter interpretation.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The dipmeter tool operates on the following principle. A bedding surface cutting across a borehole at some angle causes microresistivity changes to be recorded at different depths on the individual dipmeter curves, which are recorded from electrodes on pads located at various circumferential positions around the borehole. <a href='javascript:figurewin('../../asp/graphic.asp?code=481&order=0','0')'>Figure 1</a> shows a borehole intersected by a steeply dipping, thin resistive bed. Note that as the four pads ascend the hole, each measure electrode contacts the thin bed at a different elevation, giving rise to displacements, or shifts, between curves.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The depth differences, or displacements between the curves, depend upon the dip magnitude and direction, or <em>azimuth, </em>of the bedding surfaces. Mathematical correlation methods are applied to measure these displacements, either individual features or short intervals being matched together. The dip and azimuth of the bedding can then be computed, and corrected for the effect of the deviation of the borehole.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>It should be noted that formation dip computations with the conventional 4-curve tool require that a bedding plane be crossed by at least three of the four pads, since three points are needed to define a plane. This creates the constraint that pad-to-pad correlation must be established between the resistivity curves recorded by at least three of the four pad electrodes.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Generally, in well-bedded or laminated formations, the recorded data allow the determination of formation dip and azimuth. Pad-to-pad correlations are limited for many stratigraphic studies, however, because of the fine detail associated with sedimentary features. Eight-curve and microelectric scanning tools incorporate a number of major improvements over the 4-curve tool to overcome this limitation, and are specifically applicable to sedimentary studies.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Although the newer tools are replacing the 4-curve tool, many hundreds of the 4-curve logs have been run in the past and will continue to be used for geologic and production studies. Therefore, for completeness, the 4-curve tool and field log will be discussed first and the 8-curve dipmeter and formation imaging measurements will be covered later in more detail.<br /></span></p><p style='text-align: justify'><strong>Four Curve Dipmeter Tool<br /></strong></p><p><span style='font-family:Times'><strong>Tools Available<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>A number of dipmeter tools are available. Three-arm dipmeter tools were used for many years, but these have now been entirely superseded by four-arm and six-arm tools. <a href='javascript:figurewin('../../asp/graphic.asp?code=482&order=0','0')'>Figure 1</a> illustrates a commonly used four-arm dipmeter tool. All currently used dipmeter tools have the following common characteristics:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the <em>orientation section </em>measures tool deviation from vertical, tool azimuth with respect to north, and the orientation of the reference electrode pad to either north or the low side of the hole<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the <em>caliper section </em>measures two or more hole diameters<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the microelectrode array records the resistivity of the formation in the very localized area where the pads contact the formation;<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the gross correlation device, such as a moderately deep resistivity curve or a gamma ray or SP curve<br /></span></p><p style='text-align: justify; margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Until recently, orientation was measured using a pendulum to indicate deviation from vertical and a magnetic compass to indicate tool rotation relative to magnetic north. Recently introduced tools use flux gate magnetometers, gyroscopes, and/ or accelerometers to deduce the tool position and orientation.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The microresistivity pads carry small "button" electrodes for water-base muds and "knife-edge blade" electrodes for oil-base muds, although the latter are not always very effective.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In the field the norm is to supply a 5-in. print of the orientation curves, the correlation traces, and the caliper curves. All data are recorded on magnetic tape.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>On the rare occasions when it may be desirable to compute dip results from the film rather than from the digital data tape, a film on a very expanded scale (60 in. = 100 ft) is required. <a href='javascript:figurewin('../../asp/graphic.asp?code=482&order=1','1')'>Figure 2</a> illustrates the far more detailed 60-in. dipmeter presentation.<br /></span></p><p style='text-align: justify'><br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>The 4-Curve Dipmeter Tool<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The 4-curve device uses four identical microresistivity electrodes mounted on four pads. The four caliper arms are actuated hydraulically from the surface with a force sufficient to maintain good pad contact with the borehole wall under most conditions. The resistivity measurements are sampled 60 times per foot, or every 0.2 in. Such detail is essential, because even 1° of structural dip may be significant in determining the location of hydrocarbon traps. A 1° dip across an 8-in. borehole causes a shift of 0.14 in. between curves.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The electrodes are small enough to resolve fine structure with linear dimensions down to about 0.4 in. (1 cm). Because dipmeter correlations depend on variations in resistivity, the circuitry for the electrode output is arranged so that the curve deflections are proportional to the electrode current. Current varies widely according to the contrast between the resistivity of the formation in front of the electrode and the formation surrounding the sonde. The curves are recorded with a "floating zero" on a nonlinear scale designed to accommodate large variations in local resistivity.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=482&order=2','2')'><span style='font-size:10pt'>Figure 3</span></a><span style='font-size:10pt'> shows the four primary dip curves. On this expanded depth scale, it is apparent that a consistent shift occurs between any two curves. The shifts in this case result from bedding planes intersecting the borehole at an angle of approximately 30°. This angle is the dip with respect to a plane normal to the instrument axis.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The cable speed at the surface is measured, but the velocity of the downhole tool may be different and may alternately accelerate and decelerate with changes in friction because of the elastic properties of the cable. It is important for purposes of dip computation that the instantaneous velocity of the tool be known throughout the logging run. A fifth electrode (known as the <em>speed button) </em>provides for this correction. The curve recorded by this electrode should very closely correlate with the curve recorded by the electrode mounted below it on the same pad, and thus yield a displacement equal to the separation between them. However, if the instantaneous tool velocity varies from the constant surface cable speed, this apparent displacement also would vary, and velocity corrections must be made.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Without knowing the orientation of the tool in space, the computed dip would be the slope of a geologic feature relative to the plane defined by the four resistivity pads. To convert this angle to true dip, three continuously measured angles are required:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>deviation of the tool from the vertical (inclination)<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>hole-drift azimuth<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>azimuth of Electrode No. 1 from magnetic north<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The deviation and the first of the two azimuths are measured directly. <em>A relative-bearing </em>measurement is also made (the angular rotation about the axis of the tool of Electrode No. 1 from the upper generatrix of the hole), and it is from this angle and the azimuth of Electrode No. 1 that the hole-drift azimuth is computed. The relationship is:<br /></span></p><p><span style='font-size:10pt'>hole-drift azimuth = azimuth pad 1 - relative bearing<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Deviation and relative bearing are measured with pendulum systems, and the azimuth of Pad 1 with a magnetic compass.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>True north is the reference for the orientation of the tool. True north and magnetic north are frequently different; this difference is referred to as <em>magnetic declination. </em>Maps showing current values of magnetic declination are available. At point A on such maps, magnetic north is 20° east of true north; therefore, 20° must be added to the magnetic-north bearing to obtain the orientation of the tool with respect to true north.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>East declination </em>refers to conditions in which magnetic north is east of true north. East declination requires that the declination value be added to the magnetic-north azimuth measurement to obtain orientation with respect to true north.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>West declination </em>refers to conditions in which magnetic north is west of true north and requires that the declination value be subtracted from the magnetic-north azimuth measurement.<br /></span></p><p><span style='font-size:10pt'>True dip magnitude and the downdip direction with respect to true north is calculated from all of the previously mentioned acquired data-i.e., dip curve shifts, caliper measurements, deviation, deviation azimuth, and azimuth of Pad 1.<br /></span></p><p><span style='font-family:Times'><strong>The 4-Curve Dipmeter Field Log<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>At the wellsite, a field monitor log is recorded for each run of the tool. By carefully monitoring the four dip correlation curves on this log, the field engineer can ensure the reliability of the final computation.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The log heading provides a review of definitions of the various angles measured and calculated for the tool. The choice of low-angle or high-angle unit affects those definitions and calculations. The low-angle unit is for holes as much as 36° from vertical, the high-angle for holes up to 72° from vertical.<br /></span></p><p><span style='font-size:10pt'>The angle called <em>azimuth </em>is:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the clockwise angle between magnetic north and the horizontal projection of the arm carrying the reference electrode (No. 1) for a low-angle unit.<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the clockwise angle from north to the horizontal projection of the axis of the tool-called DHD on the log-for a high-angle unit.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The relative-bearing angle is measured clockwise from the high side of the tool to the reference electrode. Azimuth and relative-bearing traces should move roughly parallel to each other in a low-angle unit.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The major part of the log, the right-hand side, contains the four correlation curves. The log heading shows the relative position of each curve and indicates the direction in which resistivity increases.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>On the far right-hand side of the log are the two caliper curves, showing the hole diameter between Pads 1 and 3 as a dashed line and that between Pads 2 and 4 as a solid line.<br /></span></p><p><span style='font-size:10pt'>The depth scale appears in the center column of the field log.<br /></span></p><p style='text-align: justify'><strong>Dipmeter Applications<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Structural Dip<br /></strong></p><p><span style='font-family:Times'><strong>Definitions of Formation Dip<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The dipmeter survey records ways in which subsurface layers of rock have been deposited and subsequently moved. The raw data consists of <em>orientation information, </em>showing where the downhole tool is located with respect to vertical and geographic coordinates; and <em>correlation information, </em>used to determine the attitude of bedding planes with respect to the tool. The field log does not indicate formation dip. Computer processing of the raw data is required before any geological information can be extracted. The two important computer-processed parameters, <em>bed-dip magnitude </em>and <em>dip azimuth, </em>yield a great deal of valuable information when studied with regard to how these parameters vary with depth.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Dip angle </em>is the angle formed between vertical and a normal taken from a bedding plane. Thus, a horizontal bed has a dip of 0° and a vertical bed has a dip of 90° (see <a href='javascript:figurewin('../../asp/graphic.asp?code=484&order=0','0')'>Figure 1</a> ). The <em>dip azimuth </em>is the angle formed between geographic north and the direction of greatest slope on a bedding plane. Dip azimuth is conventionally measured clockwise from north, so that a plane dipping to east has a dip azimuth of 90°, and one to west 270° ( <a href='javascript:figurewin('../../asp/graphic.asp?code=484&order=1','1')'>Figure 2</a> ).<br /></span></p><p style='text-align: justify'> <br /></p><p style='text-align: justify'><span style='font-size:10pt'>Dipmeter surveys have a variety of applications. At the lowest level, the <em>raw data </em>may be used to compute (1) a deviation survey, (2) true vertical depth, (3) the integrated hole volume (as an aid to fracture detection) and (4) thin-bed definition.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>At the intermediate level, computed dipmeter results may be used to determine the gross geologic structural features crossed by the wellbore, sedimentary details within sand bodies, the depositional environment, and true stratigraphic and vertical thicknesses.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>At the highest level, computed dipmeter results from many wells may be combined to produce structural cross sections and trend surface maps.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The most important applications of the dipmeter survey are in exploration drilling, to help identify local structure and stratigraphy, and in development drilling, to help map the productive horizons and indicate direction to follow for further field development.<br /></span></p><p><span style='font-family:Times'><strong>Introduction<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The primary, and sometimes the only, use of a dipmeter is for determining structural dip. Structural dip is the attitude of the formations resulting from tectonic movements. Structural dip information might be used by the geologist for possible whipstocking or deviating the present well or to locate a future well updip or downdip.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Structural dip determination from logs is not always obvious. It is possible to have two equally plausible trends; when this occurs, additional information is necessary to determine the most probable trend.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In tensional areas, such as the U.S. Gulf Coast, offshore West Africa, and portions of the North Sea, structural dip consists of a dip trend extending at least a thousand feet. The trend would remain constant or change gradually, unless a fault or unconformity is crossed.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Thrust provinces tend to exhibit more stages of local structural deformation than tensional areas. This increased structural deformation is due to tectonic or major erosional events, and it negates the thousand-foot structural dip rule.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>As a general rule, structural dip extends horizontally no farther than it does vertically. When determining structural dip, use the trends with the greatest vertical extent.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In addition to green groups, which indicate structural dip, red and blue groups are also useful for determining the direction of structural dip. Red and blue groups are particularly helpful when dip magnitude is low (about 1° or 2°). At low angles there is often a choice of trends; the most probable trend matches the majority of red and blue dip groups.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Low-energy environments allow deposition of horizontal sediment layers. The dip of layers that have undergone only structural uplift indicates the structural dip.<br /></span></p><p><span style='font-family:Times'><strong>Determining Structural Dip<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>To determine structural dip from an arrow plot, examine the reduced scale tadpole plot for zones of low dip scatter. Use either the 1-in. or the 2-in. scale. The zones of least scatter are derived from sediment layers deposited in low-energy environments, and they produce dips indicating the structural dip.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>From the zones of least scatter, pick a dip trend extending as far vertically as possible; this is the approximate structural trend. Next, use the 5-in. scale to determine the exact dip magnitude and azimuth of the trend ( <a href='javascript:figurewin('../../asp/graphic.asp?code=484&order=2','2')'>Figure 3</a> ). Dips plotted on the reduced scales are pooled; therefore, any trend determined from the 1-in. or 2-in. plots would be slightly in error.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Unless the logged section is short, there may be several structural dip trends on the log. Structural dip changes indicate sections missing due to faulting or unconformities, or indicate the end of periods of postdepositional uplift. It is important to determine the exact location of dip changes. Sometimes the point of change can be determined exactly; in other conditions it may be difficult or impossible to determine.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>One technique for locating points of change is to determine the obvious dip trends above and below the point of change, then extend both trends toward each other as far as possible using isolated dips for support ( <a href='javascript:figurewin('../../asp/graphic.asp?code=484&order=3','3')'>Figure 4</a> ). The point of change is located between the two extended trends. This technique does not locate the exact point of change, but it does better define the zone in which the change occurs.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Hole Deviation as a Dip Indicator<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Hole deviation may be used in some instances as a dip indicator. The hole tends to drift or walk when dip is present. The following general rules can help in identifying structural dip.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Compacted Formations </em>Compacted formations cause the bit to walk or drift updip in a hole drilled with mud. Updip drift occurs as the bit attempts to align perpendicular with the dip of the bedding planes. When air or gas is used for drilling, the hole usually drifts downdip.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Uncompacted Formations </em>Less compacted formations are more complex, but in uncompacted formations the hole generally drifts downdip. In one offshore area the hole drifts downdip to about 6000 ft, then clockwise along strike as the zones become more consolidated. The clockwise drift results from bit rotation. Near 12,000 ft, the bit encounters more compacted beds, and the bit drifts updip. Unless controlled, the hole follows a U-shaped path.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Prior knowledge of hole-drift tendencies can save rig time; the surface location can be offset relative to the proposed bottomhole location, reducing the need to control the parameters that affect drilling rate.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Faults and Conformities </em>Whenever a fault or unconformity is encountered, the bit will create a dogleg. The Plio-Pleistocene example in <a href='javascript:figurewin('../../asp/graphic.asp?code=484&order=4','4')'>Figure 5</a> illustrates the effect of a change in formation compaction on direction of hole drift. There is a down-to-the-south-southeast growth fault at 8200 ft. Structural dip is to the north-northwest on both sides to the fault. On the downthrown side of the fault the hole drifts east-northeast or 90° clockwise from the downdip direction. The upthrown drift is south-southeast or updip. The hole-drift direction changes across the fault because of an abrupt change in formation compaction.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Flat Structural Dip </em>When flat or almost-flat structural dip is encountered, the hole slowly spirals through 360°. A complete rotation may require up to 1000 ft of depth.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Low Structural Dip<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Low structural dip is indicated by a tadpole cloud with its left edge at the zero dip line. This is illustrated in column B in <a href='javascript:figurewin('../../asp/graphic.asp?code=484&order=5','5')'>Figure 6</a> . If the dip trend is flat, some dips would have magnitudes of a few tenths of a degree and very few actual zero dips would be computed. Five or six tadpoles per hundred feet would be near zero (less than 1°). Not every interval would contain these few very low dips, since the beds were not deposited flat.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The directions of the red and blue dip groups also indicate the presence of very low dip trends. An area that was flat during deposition would have red, blue, and green dip groups lacking a common azimuth.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Do not overlook a low dip trend when a few, almost-flat dips are present. Column C in <a href='javascript:figurewin('../../asp/graphic.asp?code=484&order=5','5')'>Figure 6</a> contains a low (2°) southeast trend. When an obvious trend is present, honor it.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Difficult Environments<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The most difficult environments for determining structural dips are from sediments deposited in shallow water and on the continental slope. Both environments produce a high degree of dip scatter.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In the shallow water environment, the scatter results from the initial high-angle depositions, reworking by waves, and bioturbation. The scatter from beds deposited on the continental slope results from post-depositional deformation.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Fishing operations increase the difficulty of determining structural dip because of the damage they cause to formations near the borehole. The dipmeter is a shallow investigation tool, and its measurements are made from the zone that is damaged during fishing jobs. Formation damage increases the scatter on the tadpole plot; the greater the formation damage, the greater the dip scatter. Zones of least scatter with a 2° or 3° magnitude variation may exhibit 10° or more after a fishing job. Wells drilled with mud weights that were too heavy exhibit the same damage pattern.<br /></span></p><p><span style='font-family:Times'><strong>The 8-Curve Dipmeter Tool<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The 8-curve tool emits a current from the entire lower section of the sonde into the formation. A small portion flows from the electrodes to record the microresistivity dip curves. The rest of the current serves to focus this small electrode current, providing a measurement with very good vertical resolution. Comparison of the detail of the microresistivity curves with cores shows the resolution to be on the order of 0.4 in. (1 cm). All current is returned to the metal housing of the tool string above the insulating sleeve.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The inclinometry cartridge fits inside the top of the sonde. Its axis is accurately aligned with that of the sonde and includes a triaxial accelerometer and three single-axis magnetometers.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The four arms that carry the measure electrodes have a maximum diameter of 21 in. A simplified mechanical linkage is used so that the electrodes describe arcs of circles as the caliper arms extend. The opposite arms are linked, making the sonde self-centralizing in the hole. In an oval hole, however, each pair of arms opens to a different diameter, and so the electrodes on them are noncoplanar. This noncoplanar geometry is accounted for in the computation process for dip calculations. The 4-curve tool design uses a more complex arm geometry to keep all electrodes coplanar.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The bottom of the sonde, where the dipmeter pads are mounted, is decoupled from the weight of the electronics and communications cartridges by means of a flex joint. Using a cross-linked arm arrangement, it remains centralized in holes where the deviation is less than or equal to 70° (with the pad pressure control at its maximum). The centralization assures tangential contact between pads and the borehole wall, ensuring that the electrodes on the pad maintain good formation contact. The formation-imaging tool also uses this sonde design.<br /></span></p><p><a href='javascript:figurewin('../../asp/graphic.asp?code=485&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> shows a comparison of the measuring electrodes on the 4-curve tool, the 8-curve tool, and the 2-pad and 4-pad formation-imaging tools. For the 8-curve tool there are two measure electrodes on each of the four pads. The short spacing (3 cm) between the side-by-side electrodes results in a better curve likeness than that from the pad-to-pad configuration. This enables a larger number of high-credibility correlations to be made, with the result that shorter correlation intervals can be used to measure displacements between the side-by-side curves while maintaining a sharp and unambiguous curve match. By using processing methods that exploit the improved data-collection capabilities of the 8-curve tool, a fine vertical resolution of dips is achieved.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The 2-pad formation-imaging pad has the two side-by-side electrodes, plus an array of 27 resistivity buttons for detailed formation scanning. The 4-pad version has 16 electrodes per pad.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>With previous pad-to-pad configurations of the 4-pad device, the lower limit for meaningful interval correlations was on the order of one dip computation per foot. Using the side-by-side correlation technique, this can be reduced to about 3 in. under favorable conditions, thus enabling more information on sedimentological dips to be derived.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The mechanical inclinometer in the 4-curve tool has been replaced in the newer tools by a triaxial accelerometer and three magnetometers. The three-axis accelerometer is housed in a single unit. The Al, A2, and A3 axes correspond to Pad 1, Pad 2, and the tool axis direction, respectively. Accelerometer information is used to derive tool axis deviation and make speed corrections to the recorded curves. The magnetometer has a separate unit for each of the above axes. By measuring the direction of the earth's magnetic and gravity fields in relation to the tool axis, azimuth information is obtained.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The inclinometer gives accurate tool-deviation (0.2°) and tool-azimuth (2°) information. Also, since there are no moving parts, there are no problems caused by friction or inertial delays as there were with earlier mechanical designs. The response time of the system, therefore, is very fast, so that any sudden tool movement is recorded and taken into account during the processing of dip results.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>At the wellsite, the computation program uses the microresistivity information from the two additional electrodes (or speed buttons) to perform the speed correction. At the computing center, additional processing is performed and the speed correction is further refined. The accelerometer data are first used to correct the eight dip curves and the two speed curves for the effect of irregular tool movement. The displacements with the speed curves are then used to remove any remaining minor speed fluctuations. The original dip curves can than be corrected to their true downhole depths.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The 8-curve tool has a sampling rate of 0.1 in., as compared with 0.2 in. for the 4-curve tool.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The total current (called Emex) that is sent into the formation is automatically controlled by the surface computer to allow for major changes in formation resistivity. In this way the microresistivity curve activity is maintained in both high- and low-resistivity zones so that good correlations can be made. In addition, the microresistivity curves may be played back and re-scaled at the wellsite or computing center to remove the visual effect of variation in Emex current. This ensures that information about grain-size or textural change in the formation is not obscured, as might be the case on the original raw data curves.<br /></span></p><p><span style='font-family:Times'><strong>The 8-Curve Dipmeter Field Log<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>A real-time field log is recorded during the logging runs. After listing details concerning the tool and recording system, the log heading also identifies the various curves and scales. The following curves are presented:<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><strong>Hole Deviation.</strong> This is computed from sonde deviation using values of sonde length and cartridge standoff. Either the hole or sonde deviation can be presented (default is the tool deviation calculated with zero standoff).<br /></span></p><p><span style='font-size:10pt'><strong>Hole Azimuth</strong>. Displayed on a -40° to 360° scale.<br /></span></p><p><span style='font-size:10pt'><strong>Pad 1 Azimuth.</strong> Displayed on a -40° to 360° scale, this curve shows the azimuth of Pad 1.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><strong>Relative Bearing.</strong> Displayed on a -40° to 360° scale, this curve is presented as a cross-check between Pad 1 azimuth (P1AZ) and hole azimuth (HAZI). The relationship is RB = P1AZ - HAZI<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><strong>Dip Curves.</strong> These are the eight raw microresistivity curves before any Emex correction. The speed curves are not presented.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><strong>Emex Curves.</strong> Both Emex current and voltage are displayed. As an aid to the field engineer, they allow the operation of the Automatic Emex Control to be monitored during logging.<br /></span></p><p><span style='font-size:10pt'><strong>Calipers.</strong> Two caliper diameters set at 90° to each other are presented on a linear 20-in. scale.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The field log is readily used to evaluate the data quality. Dip curves should be visually similar in detail and activity. Any departure from this norm may signal unusual conditions or faulty tool operation. The user of computed data is encouraged to study the curves carefully when judging the quality of the computations.<br /></span></p><p><strong>Dipmeter Computation <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Given that a plane cutting a wellbore produces resistivity anomalies at slightly differing depths on the wall of the borehole facing up- or downdip, the computation of dip and dip azimuth is reduced to a problem of trigonometry. Any plane can be uniquely defined by three points in space. A four-arm dipmeter provides four points. If the bedding planes are uniformly thick and plane at the intersection with the wellbore, only three of the available four points are necessary to compute a dip. When one of the correlation traces is substandard due to hole conditions or recording techniques, the fourth trace allows a margin of safety. Parts (a) and (b) of <a href='javascript:figurewin('../../asp/graphic.asp?code=486&order=0','0')'>Figure 1</a> show a cross section of a borehole with a four-arm dipmeter tool, and a schematic of the correlation curves that might be recorded. A comparison of displacements of an anomaly on two correlation curves is key to computing the formation dip. <a href='javascript:figurewin('../../asp/graphic.asp?code=486&order=1','1')'>Figure 2</a> illustrates a dipping plane cutting across a borehole and the expected displacements.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The starting point for dip computation is thus the correlation of one trace to another in order to discover the relevant displacement. The correlation process can be made optically using the 60 in. per 100 ft record and a special apparatus known as an optical comparator, or it can be done by computer. Optical correlation is rarely used anymore since it requires a skilled specialist, takes time, and makes no allowance for tool acceleration and deceleration. Computer-based correlation can be made using a variety of techniques, such as pattern recognition, Fourier analysis, and conventional correlograms. The most commonly used technique builds correlograms. Three parameters are used to control the correlation process, as illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=486&order=2','2')'>Figure 3</a> . They are the correlation interval, the search angle, and the step distance.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Correlation intervals may range from a few inches to several feet, depending on the information sought. For detailed stratigraphy with high-quality raw data, a correlation interval of 3 in. to 2 ft may be used. For standard work, 2 ft to 6 ft is good, while for structural information, 6 ft to 18 ft will do.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The search angle defines how far up and down the hole to seek a correlation and, depending on the hole size, reflects the analyst's guess of the highest expected dip.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The step distance defines the depth increment to be used between rounds of correlations. This is usually set to half the correlation interval. Thus, a dipmeter computed on 4 ft x 2 ft x 35° means a correlation interval of 4 ft was used with a step of 2 ft and a search angle of 35°</span><br /> </p><p><span style='font-size:10pt'>Since only three points are required to define a plane, a four-arm dipmeter survey forms an overdetermined system. Any three curves of the four can provide a dip.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Three items may be selected from a choice of four in twelve ways. Potentially, therefore, many dips may be computed at the same depth. In practice, it is found that they do not all agree. For the same reason that four-legged stools tend to wobble on an uneven floor, but three-legged stools do not, a number of dips are possible simply as a result of nature not providing us with bedding planes that are perfect planes at the scale of one borehole diameter. Add to this the effects of borehole rugosity, floating pads, and the like, and the result is a scatter of possible dips. The choice of the correct dip then becomes an exercise in common sense. In general, this exercise has come to be known as "clustering." Simply stated: If at any level in the well the majority of the possible dips agree with each other <em>and </em>agree with the majority of the dips at adjacent levels in the well, then those are the most probable dips to use. The criterion for judging the worth of any type of dipmeter computation is, of course, its ability to reflect the known geologic facts.</span><br /> </p><p><span style='font-family:Times'><strong>Computing Dip</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the early days of the dipmeter, operators made dip measurements directly from readouts similar to the modern field log. Conductivity curves were recorded in much greater detail at a scale of 1:20, or 60 in. = 100 ft.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Each curve feature is the signature of a geologic event in the depositional sequence through which the tool passes. The same event can often be recognized in each of the eight curves, though depth may vary because of dip. By measuring the displacement of the event between each of the curves and knowing the precise depth scale, the actual displacement may be read in inches or fractions of inches of borehole. The dip angle relative to the plane of the electrodes can be calculated trigonometrically. Hole deviation and direction, the orientation of Pad 1, the true dip angle, and direction relative to a horizontal plane can also be calculated.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Computer processing of dipmeter data has completely replaced the manual method for normal applications, but the basic principles have remained. Visual correlation and inspection of detailed logs is still useful in quality control and in studies of fractures and other specific geological events.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the following discussion of dip computation systems, references are made to examples of dip results in order to show the effects of computation type, tool type, and computation parameters. Here we provide an explanation of the presentation method.</span><br /> </p><p><span style='font-family:Times'><strong>Other Presentations</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Several approaches for processing raw dipmeter data and for displaying the results are available. The choice of system or systems to use should be determined by the type of problem to be solved-structural, stratigraphic, or (as is often the case) both.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In addition to the various arrow plots, azimuth-frequency diagrams, and formation-imaging displays that have been described and illustrated, a number of other graphic and tabular presentations are available from dipmeter data. The more popular ones are covered in the dipmeter interpretation sections of this manual.</span><br /> </p><p style='text-align: justify'><strong>Data Presentation<br /></strong></p><p><span style='font-family:Times'><strong>Interpretation and Applications<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Once a dipmeter has been computed, a number of ways of presenting the answers is available. These include:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>tadpole or arrow plots<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>SODA (separation of dip and azimuth) plots<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>listings<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>azimuth frequency plots<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>histograms<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>polar plots<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>stick plots<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>stratigraphic plots<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A typical <em>tadpole plot </em>is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=487&order=0','0')'>Figure 1</a> . The dip magnitude is read from the position of the base of the tadpole on the plot. The dip azimuth is read by observing the direction in which the tail of the tadpole points. The azimuth convention is to measure angles clockwise from north. Thus a north dip points uphole, an east dip to the right, a south dip down-hole, and a west dip to the left.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-size:10pt'><em>SODA plots </em>separate dip and azimuth as distinct points on separate tracks of the answer plot.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Listing </em>In addition to the dip and dip azimuth, these listings may include further details such as dip quality and hole volume.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Azimuth frequency diagrams </em>(or rose plots) present statistical information regarding some depth interval in the well, usually 100 ft or 500 ft. Within that interval a polar plot is built with the number of dips having a dip azimuth of a particular direction plotted in a circular histogram. These are most useful for making a quick scan of the geologic column for trends in dip direction with depth. Conventional histograms of both dip and dip azimuth can also be presented ( <a href='javascript:figurewin('../../asp/graphic.asp?code=487&order=1','1')'>Figure 2</a> ).<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Polar plots </em>can be built in two ways. One way, the rose plot, has already been described. Another way is to scale the plot with zero dip at the outside and 900 at the middle. Thus the azimuth of the <em>lowest </em>dips becomes more apparent. This type of plot, popular for picking structural dip, is illustrated by <a href='javascript:figurewin('../../asp/graphic.asp?code=487&order=2','2')'>Figure 3</a> .<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Stick plots </em>(<a href='javascript:figurewin('../../asp/graphic.asp?code=487&order=3','3')'> Figure 4</a> and <a href='javascript:figurewin('../../asp/graphic.asp?code=487&order=4','4')'>Figure 5</a> ) show a series of short lines inclined to the horizontal. Each line represents the dip angle as projected in some line of cross section. A stick plot can be oriented whichever way the geologist wishes. If the orientation is changed, the new axes must be relabeled. It is normal to distort the horizontal and vertical scales on these plots to fit the geologist's mapping requirements. Stick plots, normally used in multiwell projects to draw cross sections, are particularly helpful where the interwell correlation is not immediately obvious from conventional logs.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Stratigraphic plots </em>attempt to give a visual representation of the bed stratigraphy. Each dip may be represented by the trace of the bedding plane on the borehole wall. If the trace could be "unwrapped" and laid on a flat surface, a sine wave would be visible, its amplitude a reflection of the dip magnitude and its low point an indication of the dip azimuth. <a href='javascript:figurewin('../../asp/graphic.asp?code=487&order=5','5')'>Figure 6</a> illustrates such a plot.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Dipmeter plots may be interpreted by observing the variation of dip and dip azimuth with depth in conjunction with the openhole logs. Here color helps highlight certain types of patterns. Conventionally, dips of more or less constant azimuth that show an increase in dip magnitude with depth are colored red; those that show a decrease in dip magnitude are colored green. <a href='javascript:figurewin('../../asp/graphic.asp?code=487&order=6','6')'>Figure 7</a> illustrates these patterns.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Broadly speaking, dip interpretation may be split into two parts, structural and sedimentary. Gross structural characteristics, such as unconformities, folds, anticlines, and synclines, produce patterns that vary gradually over hundreds of feet. Sedimentary characteristics, such as crossbedding, only appear within sedimentary beds and are localized to a few feet to tens of feet. To become familiar with some of these patterns and their associated geologic features, six cases may be considered.<br /></span></p><p><span style='font-family:Times'><strong>Presentation of Dip Data<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The basic method of presentation of computed dip answers is the <em>arrow </em>or <em>tadpole plot. </em>Each tadpole consists of a dot with an attached tail. In <a href='javascript:figurewin('../../asp/graphic.asp?code=487&order=7','7')'>Figure 8</a> the position of the top dot shows a dip magnitude of 20°. Magnitude is the dip angle with respect to horizontal. The tail of the tadpole always points in the downdip direction in this example-N60E, or 60° east of north. The computed dipmeter result is composed of many, often thousands, of tadpoles. From the tadpoles it is possible to recognize changes in dip and direction up and down the well. Changes in magnitude and direction are shown as depth increases.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>During the computation process, the computer outputs quantities that are used to qualify the sharpness or reliability of the correlation. This determination of answer quality is represented on the tadpole plot in three basic codes. Solid tadpoles represent answers of high accuracy and confidence. Hollow tadpoles represent answers of a lesser degree of the same. No tadpoles, or <em>blank zones, </em>are intervals for which actual correlations were sufficiently in doubt that a decision could not be reached. This method of plotting enables the user to make a judgment on data quality.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=487&order=8','8')'><span style='font-size:10pt'>Figure 9</span></a><span style='font-size:10pt'> is a typical tadpole plot over 40 m of hole. Note the solid tadpoles, hollow tadpoles, and blank zone, as previously described. The second set of tadpoles to the far right indicates the hole-drift angle from vertical and the direction of drift. This information can be very useful in interpreting dip data and will be addressed later.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>An azimuth frequency plot (also known as a <em>rose diagram) </em>is shown on the same track as the dip tadpoles. Each of these plots represents azimuth distribution of all dips between the arrowheads A and B.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>From a series of these plots over a long interval, one may recognize major direction changes without studying the tadpole plot in detail. The curves on the left of the figure are the two calipers and a computed resistivity. Gamma ray curves may also be displayed. The calipers are a useful indicator of difficult logging conditions, particularly poor pad contact due to hole irregularities. The calipers may also show an enlarged hole where the borehole intercepts a fault or fractured zone. The resistivity curve can be used to positively tie the computed dip plot on depth with other openhole logs.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Tadpole Plot Characteristics<br /></strong></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=487&order=9','9')'><span style='font-size:10pt'>Figure 10</span></a><span style='font-size:10pt'> is a dipmeter plot of a section with excellent parallel bedding, less well-defined bedding, and a blank zone, where no correlations could be found. Note that a consistent trend of hollow tadpoles can give a high-quality interpretation although each individual dip may not in itself imply high accuracy; this is the case within the top 15 m of the log.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The general appearance of the dipmeter plot when variables such as tadpole scatter, tadpole quality, and other trends are considered reflects changes in bedding characteristics that are functions of depositional environment, tectonics, diagenesis, rock stress, and other useful geologic factors not deduced from most other logging devices. Indeed, the sequence of those observable characteristics often can be repeated from well to well as consistently as can lithologic sequences, and can provide additional geologic information about an area.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Note that during interpretation of any dipmeter plot, the major influence on the quality of the tadpole is the rock characteristic. Poor bedding may be influenced by any of the following:<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Note that during interpretation of any dipmeter plot, the major influence on the quality of the tadpole is the rock characteristic. Poor bedding may be influenced by any of the following:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>lack of textural or mineral stratification<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>small-scale heterogeneities--e.g., concretions, cross-laminations<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>bioturbation<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>diagenesis--e.g., dolomitization of limestones or cementation of clastic rocks resulting in obliteration of original bedding<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>deformation by creep, slumping, diapirism, or plastic flow<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>fracturing due to tectonic stress and movement<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>rubble in fault zones<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>in some cases, swelling of clay-rich formations adjacent to the borehole by absorption of drilling fluids or modification of the rock stress by the drilling process<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>dips paralleling the hole axis<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>From the appearance of the plot we can infer formation characteristics related to sedimentary and tectonic processes that further enhance the overall interpretation.<br /></span></p><p style='text-align: justify'><strong>Interpretation<br /></strong></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>1. <strong>Folded Structure. <a href='javascript:figurewin('../../asp/graphic.asp?code=488&order=0','0')'/></strong>Figure 1 shows a folded structure. Note that in the shallow part of the well, dips are moderate and to the north.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the deeper section, the well has crossed the axial plane of the fold and dips are more pronounced and to the south. At the point the well crosses the axial plane, dips are flat. It is here that a hydrocarbon trap exists. From the dips on the flanks it is possible to compute both the tilt of the axial plane and the plunge of the fold.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>2. <strong>Unconformity. <a href='javascript:figurewin('../../asp/graphic.asp?code=488&order=1','1')'/></strong>Figure 2 illustrates an unconformity. A series of sediments in the deeper part of the well was originally deposited flat. Thereafter, these sediments were tilted and then eroded and a new set of beds deposited. At the interface between the old and new sediments, there is an abrupt change of dip.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>3. <strong>Faults. </strong>Faults may be picked from dip patterns by observing the drag patterns, if present, on either side of a fault. <a href='javascript:figurewin('../../asp/graphic.asp?code=488&order=2','2')'>Figure 3</a> shows a normal fault with drag. Above the intersection of the wellbore with the fault, a red pattern will develop (dip increasing with depth). Below the intersection of the wellbore with the fault, a blue pattern will develop (decreasing dip with depth). At the intersection of the wellbore with the fault plane, the dip of the fault plane itself may be seen occasionally. Note that the fault dips down in the direction of the azimuth of the drag pattern. It thus strikes perpendicular to that direction.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>4. <strong>Current Bedding. </strong>Among the sedimentary details that may be inferred from a dipmeter plot is the direction of transportation of sediments by streams. <a href='javascript:figurewin('../../asp/graphic.asp?code=488&order=3','3')'>Figure 4</a> shows the sort of pattern to be expected in such a case. Here, blue pat- terns develop with the dip azimuth in the patterns pointing downstream. Depending on where the well is drilled, it may be of interest to move upstream toward the source or down- stream to finer sediments or broader deposits.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>5. <strong>Channel Cut and Fill. </strong>A common type of deposit results when a channel is cut and refilled with reservoir sand. A red pattern will develop together with a characteristic S</span>p<span style='font-size:10pt'> shape, broadening to the base. In drilling such plays, it is useful to know in which direction the channel extends and in which direction it thickens.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Note that the well in <a href='javascript:figurewin('../../asp/graphic.asp?code=488&order=4','4')'>Figure 5</a> was drilled off the axis of the channel. Had it been drilled to the north, a thicker section of sand would have been found. To move to the center of a channel, therefore, offset the well in the same direction that the red pattern tadpoles point. To follow the channel, move at right angles to the red pattern dip azimuth, in this case either east or west.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>6. <strong>Buried Bar with Shale Drape. </strong>Another common feature is a buried bar over which subsequent shale deposits have been draped. Here, dips within the sand body decrease with depth (blue), but, above the sand body, dips in the shale increase with depth (red) ( <a href='javascript:figurewin('../../asp/graphic.asp?code=488&order=5','5')'>Figure 6</a> ). The SP usually shows a characteristic pattern, broad at the top. To follow the bar, wells should be offset at right angles to the dip azimuth seen within the bar. To drill a thicker section, a well should be offset in the opposite direction to the dip seen in the bar.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Another application of the dipmeter survey is the detection of fractures. There are many methods available for fracture detection, but no single method by itself is completely reliable. The use of the dipmeter for fracture finding, then, is just one of many methods, and should be used to complement the others.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The theory is very simple. A fracture may be invaded with mud filtrate and therefore offer a less resistive path to electric current. If one of the dipmeter pads happens to lie in front of a fracture, it will record a low resistivity value. Another pad at the same depth may not be in front of a fracture and will record a higher resistivity. Thus, comparison of adjacent pad traces should reveal the presence of a fracture if the two resistivity values are different.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Curves can be displayed in various ways to highlight such differences. <a href='javascript:figurewin('../../asp/graphic.asp?code=488&order=6','6')'>Figure 7</a> shows one such presentation. Note that since the orientation of the dipmeter tool is known, the orientation of the fracture can be deduced.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Good dip information requires good raw data. To ensure such data the following guidelines are suggested:</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>Recondition the hole prior to running the dipmeter. <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>Use a swivel-head adapter to reduce tool rotation while logging.</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Log at 1800 to 2400 ft/hour to reduce tool jerking. Slow down even more if the tension on the line is erratic.</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Reject sections of log where the tool rotates once in less than 60 ft of hole.</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Make repeat sections and/or overlaps of 100 ft to 200 ft every time the logging is stopped for film or tape changes.</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Inspect the raw log for dead correlation curves, insensitive curves, stuck calipers, etc. As a last resort, three good correlation curves are sufficient, but four are much better.</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Carefully inspect the orientation curves for nonsense readings, such as a hole deviation less than zero.</span><br /> </p><p style='text-align: justify'><h2><span style='font-family:Symbol'></span><span style='font-size:10pt'>On a computed log, check the dip against field controls for consistency. Many dipmeter surveys have been off by 90° or 180° due to incorrect pad wiring or erroneous computation.</span></h2></p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-21007150371351244492008-11-20T22:07:00.001-08:002008-11-20T22:07:01.573-08:00Well Logging Tools & Techniques (Cased Hole Logs)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Cased Hole Logs <br /></span></h2></p><p><strong>Pulsed Neutron Logs <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>A pulsed neutron log provides a means of evaluating a formation after the well has been cased. It is of particular value for</span> :<br /></p><ul style='margin-left: 81pt'><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>evaluating old wells, where the original openhole logs are inadequate or nonexistent <br /></span></div></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>monitoring reservoir performance over an extended period of time</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>monitoring the progress of the secondary and tertiary recovery projects</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>evaluating the formation, as a last resort, should the drillpipe become stuck</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>It is the most widely used and most direct logging method in cased holes at the present time. Other nuclear measurements are being developed that may eventually give superior results; these include the carbon/oxygen type logs and activation logs.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Though all commercially available tools are designed to measure the same formation parameters, their operating systems are all slightly different.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Principle of Measurement </em>Regardless of the tool used, the principle of measurement remains the same. When a neutron generator is turned on for a very short period of time, a "burst" of neutrons leaves the tool. Since neutrons can easily pass through both the steel housing of the tool and the tubing/ casing, a "cloud" of neutrons gathers in the formation. Fast neutrons soon become "thermalized" by collisions with atoms in the formation. The most effective thermalizing agent is the hydrogen present in the pore space in the form of water or hydrocarbon. Once in the thermal state, a neutron is liable to be captured. The capture process depends on the capture cross section of the formation. In general, chlorine dominates the capture process. Since chlorine is present in formation water in the form of salt (NaCl), the ability of the formation to capture thermal neutrons reflects the salt content and, hence, the water saturation. The capturing of a thermal neutron by a chlorine atom gives rise to a capture gamma ray. Pulsed neutron tools therefore monitor these capture gamma rays. Thus, the common elements of all commercial pulsed neutron tools are a pulsed neutron generator and two gamma ray detectors at different distances from the neutron generator. <a href='javascript:figurewin('../../asp/graphic.asp?code=422&order=0','0')'>Figure 1</a> illustrates a generalized neutron tool.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The cloud of neutrons produced by the initial neutron generator burst results in a cloud of thermal neutrons in the vicinity of the tool, which dies away as the neutrons are captured by chlorine atoms or other neutron absorbers in the formation. If there is plenty of chlorine present (i.e., high water saturation), the cloud of thermal neutrons disappears quite quickly. If, however, hydrocarbons are present (i.e., low water saturation), the cloud of thermal neutrons decays much more slowly.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The rate of decay is measured by monitoring how many capture gamma rays enter the gamma ray counter(s) as a function of time. <a href='javascript:figurewin('../../asp/graphic.asp?code=422&order=1','1')'>Figure 2</a> plots the relative counting rate on the y-axis, and time, in microseconds, following the initial burst of fast neutrons, on the x-axis. Note that after a few hundred microseconds a straight-line portion of the decay curve develops. Note also how the water line has a steeper slope than the oil line. At later times note the background gamma ray count rate that remains substantially constant.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The y-axis in <a href='javascript:figurewin('../../asp/graphic.asp?code=422&order=1','1')'>Figure 2</a> is logarithmic but the x-axis (time scale) is linear. Thus, the straight-line portions represent exponential decay. If N is the number of gamma rays observed at time t and No is the number observed at t = 0, then</span><br /> </p><p style='margin-left: 36pt'><strong><span style='font-size:10pt'>N = No e<sup>t/<span style='font-family:Symbol'></span></sup></span><br /> </strong></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where r is the time constant of the decay process. t is measured in units of time. It is convenient to quote values of t in microseconds (1 microsecond = l0-6 seconds). The capture cross section of the formation, the property of interest, is directly related to t by the equation:</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>S = 4550/t</span><br /> </span></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where S is the capture cross section measured in capture units (CU).</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Thus S is best measured by finding the straight-line portion of the capture gamma ray decay, and measuring its slope. This is accomplished in different ways by various commercially available tools.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>On a typical pulsed neutron log as many as 9 curves may be displayed. <a href='javascript:figurewin('../../asp/graphic.asp?code=422&order=2','2')'>Figure 3</a> illustrates a typical presentation:<br /></span></p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:107px'/><col style='width:47px'/><col style='width:94px'/><col style='width:179px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt; text-decoration:underline'><strong>Curve Name</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt; text-decoration:underline'><strong>Units</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt; text-decoration:underline'><strong>Logs Track</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt; text-decoration:underline'><strong>Remarks</strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sigma (<span style='font-family:Symbol'></span>)</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>CU</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>2 & 3</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Main curve</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Tau ()</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>µ-sec</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>2 & 3</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Ratio</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>-</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>2</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Pseudoporosity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Near Counts</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>cps</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>3</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Near detector, gate 1</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Far Counts</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>cps</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>3</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Far detector, gate 1</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Monitor or Background</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>cps</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>1</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Near detector, gate 3</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Quality Control</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>-</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>1</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Check of 7 loop</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Gamma Ray</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>API</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>1</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Natural gamma</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Casing Collar Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>-</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>1</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Both memorized and direct</span></p></td></tr></tbody></table></div><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>The Sigma Curve </em>The <span style='font-family:Symbol'></span> curve, the principal pulsed neutron measurement, behaves rather like an openhole resistivity curve; i.e., it deflects to the left (high values of <span style='font-family:Symbol'></span> in wet zones and to the right (low values of <span style='font-family:Symbol'></span> in hydrocarbon-bearing zones or low-porosity formations.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Since <span style='font-family:Symbol'></span> values in shales are quite high, they tend to mask the effect of hydrocarbons, making shaly pay zones at first appear to be water-bearing. <a href='javascript:figurewin('../../asp/graphic.asp?code=422&order=3','3')'>Figure 4</a> is a comparison of <span style='font-family:Symbol'></span> with resistivity.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>The Tau Curve </em><span style='font-family:Symbol'></span><em><br /> </em>is just another way of looking at <span style='font-family:Symbol'></span>. In fact, <span style='font-family:Symbol'></span> is the basic measurement of the tool (the decay time constant for the thermal neutron population). However, all interpretation equations for pulsed neutron logs are linear functions of <span style='font-family:Symbol'></span>. Thus, it is much easier to work with <span style='font-family:Symbol'></span> than with <span style='font-family:Symbol'></span>. It is recommended that <span style='font-family:Symbol'></span> be recorded on tape but left of f the log presentation, since its scaled reciprocal (<span style='font-family:Symbol'></span>) gives exactly the same information in a form that is easier to work with.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Ratio Curve </em>The ratio curve is a porosity indicator derived by taking the ratio of gamma ray counts seen during gate 1 at the near and far detectors. The ratio curve, behaving very much like a compensated neutron porosity curve, deflects to the right (low ratio) in low porosity or in the presence of gas. <a href='javascript:figurewin('../../asp/graphic.asp?code=422&order=4','4')'>Figure 5</a> shows the ratio curve response to a pocket of gas trapped below a packer behind a tubing nipple. In the absence of any openhole porosity logs, the ratio can be used in combination with <span style='font-family:Symbol'></span> to find formation porosity.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Near and Far Count-Rate Display </em>In track 3 the near and far count rates are displayed as an overlay ( <a href='javascript:figurewin('../../asp/graphic.asp?code=422&order=5','5')'>Figure 6</a> ). When the correct scales are chosen for the near and far count rate displays, the result is a useful "quick-look" log with the following properties:</span><br /> </p><p><span style='font-family:Arial Unicode MS; font-size:10pt'>in gas Fl > Nl (dotted left of solid) <br /></span></p><p><span style='font-family:Arial Unicode MS; font-size:10pt'>in shales Fl < Nl (dotted right of solid)<br /></span></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>and in clean oil- or water-bearing zones, the two curves lie practically on top of one another.</span><br /> </span></p><p><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Background and Quality Curves </em>The background curve is a very insensitive natural gamma ray curve. Little movement shows on this curve except in "hot" zones, which are very radioactive. This curve is sometimes omitted without any great loss.</span><br /> </p><p><span style='font-size:10pt'>To summarize, the most important curves to work with are:</span><br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:122px'/><col style='width:143px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-family:Symbol; font-size:10pt'></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>for water saturation</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Ratio</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>for porosity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>GR</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>for shale content</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Near/far display</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>for gas indications</span></p></td></tr></tbody></table></div><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Pulsed Neutron Interpretation<br /></strong></p><p><strong>Capture Cross Sections <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The capture cross section of a formation depends on the chemical elements present, and on their relative abundance. <span style='font-family:Symbol'></span> values vary over a wide range.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Common matrix materials (sand, lime, and dolomite) exhibit capture cross sections in the range of 8 to 12 CU. Pore-filling fluids such as water, oil, and gas also show a wide range, brines varying from 22 CU (fresh water) up to 120 CU (saturated brine). Oils, depending on the amount of dissolved gas they contain, range from 18 to 22 CU. Gases, depending on their gravity, temperature, and pressure, range from 4 to 12 CU.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Interpretation of Pulsed Neutron Logs </em>Practical interpretation of pulsed neutron logs in clean formations is conceptually very simple. The total formation capture cross section (<span style='font-family:Symbol'></span>) recorded on the log, is the sum of the products of the volume fractions found in the formation and their respective capture cross sections. Thus, in its simplest form:</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Symbol'></span> log = <span style='font-family:Symbol'></span><br /> <sub>matrix</sub> • (1 -<span style='font-family:Symbol'></span>) + <span style='font-family:Symbol'></span><br /> <sub>fluid</sub> • <span style='font-family:Symbol'></span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=423&order=0','0')'><span style='font-family:Arial Unicode MS; font-size:10pt'>Figure 1</span></a><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'> should clarify the mathematical relationship. If the "fluid" is a mixture of oil and water, the log response is described by</span><br /> </span></p><p style='text-align: justify; margin-left: 36pt'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>S <sub>log</sub> = S <sub>ma</sub> (1 -f) + S <sub>w</sub>f S<sub>w</sub> + S <sub>hy</sub> f (1 - S<sub>w</sub>)</span><br /> </span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>By rearrangement of the equation, we have</span><br /> </span></p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>Reservoir Monitoring-Time Lapse Technique </em>Pulse neutron logs are useful for monitoring the depletion of a reservoir. The time lapse method is used. A base log is run in the well shortly after initial completion but before substantial depletion of the producing horizons. A few days, weeks, or even months of production are required to "clean up" near-wellbore effects of the drilling operation, such as mud filtrate invasion. Once a base log is obtained, the well may be relogged at time intervals over the life of the field, depending on production rate variations.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Successive logs may be overlaid so that changes in saturation can be easily spotted by changes in <span style='font-family:Symbol'></span>. A good example of this ( <a href='javascript:figurewin('../../asp/graphic.asp?code=423&order=1','1')'>Figure 2</a> ) shows a base log and three additional logs at roughly six-month intervals. Note the rapid rise of the oil-water contact(s) with passage of time.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Log-Inject-Log </em>The log-inject-log technique is used to find residual oil saturations. Once a base log is run, the formation is injected with waters of different salinities and logged again. In <a href='javascript:figurewin('../../asp/graphic.asp?code=423&order=2','2')'>Figure 3</a> , the formation was injected with brine and logged, then injected with seawater and logged a third time. Provided the capture cross section of the seawater and brine flushes are known, all the unknown quantities may be normalized out and the residual oil saturation found, using</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Note that it is not necessary to know either Sma or Soil. The technique has many variations, some using specially chlorinated oil that has a high capture cross section.<br /></span></p><p><strong>Inelastic Neutron-Gamma (Carbon-Oxygen) Logs <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>High-energy neutrons (14 Mev) produced by a pulsed-neutron source are directed into the formation, and the energy spectrum of gamma rays produced by the neutron bombardment is sampled at various times both during and after the neutron burst. Neutrons can interact with matter in two distinct ways to create gamma rays: by inelastic scattering with nuclei at high energies (>5 Mev) and, through capture or absorption, by nuclei at low energies (<.025 Mev). The gamma rays produced from each of these reactions have unique energies that depend on the type of nucleus with which the neutron reacts. By measuring the number and energy of gamma rays produced by neutron bombardment, the elemental composition of the formation can be inferred.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Applications </em>These tools provide a measure of the oil saturation, C/O ratio; lithology, Si/(Ca + Si) ratio; porosity, H/(Ca + Si) ratio; shale, Fe/(Ca + Si) ratio; and salinity, Cl/H ratio, in open or cased holes. This logging method is used to determine the presence of hydrocarbons behind casing, regard-less of formation water salinity.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>At present, reliable measurements can be made only with optimum borehole and formation conditions. The major interpretive uncertainty stems from the inability of the measurement to distinguish between carbon associated with carbonates (e.g., limestone, CaCO<sub>3</sub>) and carbon associated with hydrocarbons.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Depending on the tool used, the tool either (a) measures the number of gamma rays in two energy "windows," centered around the expected carbon and oxygen inelastic scattering energies during the burst and around the silicon and calcium thermal capture energies after the burst, or (b) employs a "spectral fitting analysis" to determine the yields of carbon, oxygen, calcium, silicon, and several other elements. This spectral fitting analysis uses three gates: the burst gate, the background gate, and the capture gate. The burst gate is at the source, the background gate cuts down on borehole interference, and the capture gate gives capture readings. The burst gate minus the background gate gives the inelastic spectrum and the capture gate gives the capture spectrum ( <a href='javascript:figurewin('../../asp/graphic.asp?code=424&order=0','0')'>Figure 1</a> ). <br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Ratios of element yields (C/O, Si/Ca, Cl/H, etc.) are normally presented. Given a constant porosity and lithology, an increase in the carbon-oxygen ratio indicates an increase in oil saturation. It should be noted that by taking elemental ratios, any variations in neutron output from the source are normalized.</span><br /> </p><p><br /> </p><p><br /> </p><p><span style='font-size:10pt'>Note the following considerations:</span><br /> </p><p style='margin-left: 45pt'><span style='font-size:10pt'><span style='font-family:Times New Roman'>·</span><span style='font-family:Arial Unicode MS'> The log is generally run in cased holes when conditions are not favorable for pulsed neutron logs because of low formation water <br/>salinities. <br/></span><span style='font-family:Times New Roman'>·</span><span style='font-family:Arial Unicode MS'> Optimum formation conditions are high porosity (>20%), low water salinity (<50,000 ppm NaCl), and consistent or known lithology. The log can be useful where salinities are unknown or variable. <br/></span><span style='font-family:Times New Roman'>·</span><span style='font-family:Arial Unicode MS'> Depth of investigation is very shallow for measurements on the inelastic scattering spectrum. This limits the tool's openhole use and forces consideration of the effects from the casing annulus. <br/></span><span style='font-family:Times New Roman'>·</span><span style='font-family:Arial Unicode MS'> Optimum borehole conditions are a small-diameter hole and constant fluid composition in the casing. If an oil-water contact or varying salinities are expected in the casing, a fluid displacer should be considered. <br/></span><span style='font-family:Times New Roman'>·</span><span style='font-family:Arial Unicode MS'> At present, the statistical uncertainty in analyzing the spectrum is the tool's limiting feature. Advances in detector design and spectrum analysis should <br/>solve these problems.<br /></span></span></p><p><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=424&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> shows a continuous carbon/oxygen log. The curves it presents are:<br /></span></p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:108px'/><col style='width:434px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 3px; padding-left: 3px; padding-bottom: 3px; padding-right: 3px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Track 1</strong></span></p></td><td style='padding-top: 3px; padding-left: 3px; padding-bottom: 3px; padding-right: 3px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt' vAlign='middle'><p><span style='font-size:10pt'>Monitor</span></p></td></tr><tr><td style='padding-top: 3px; padding-left: 3px; padding-bottom: 3px; padding-right: 3px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt' vAlign='middle'><p> </p></td><td style='padding-top: 3px; padding-left: 3px; padding-bottom: 3px; padding-right: 3px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt' vAlign='middle'><p><span style='font-size:10pt'>Silicon correlation</span></p></td></tr><tr><td style='padding-top: 3px; padding-left: 3px; padding-bottom: 3px; padding-right: 3px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Tracks 2 and 3</strong> </span></p></td><td style='padding-top: 3px; padding-left: 3px; padding-bottom: 3px; padding-right: 3px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Silicon-calcium ratio (capturespectrum)Carbon-oxygen ratio</span><br /> <span style='font-size:10pt'>Calcium-silicon ratio (inelastic</span><br /> <span style='font-size:10pt'>spectrum)</span> </p></td></tr></tbody></table></div><p><br /> </p><p><a href='javascript:figurewin('../../asp/graphic.asp?code=424&order=2','2')'><span style='font-size:10pt'>Figure 3</span></a><span style='font-size:10pt'> shows an inelastic neutron gamma log of the sort that employs spectral filtering. The data it records are:</span><br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:112px'/><col style='width:430px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 3px; padding-left: 3px; padding-bottom: 3px; padding-right: 3px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt' vAlign='middle'><p><span style='font-size:10pt'><strong>Track 1</strong></span></p></td><td style='padding-top: 3px; padding-left: 3px; padding-bottom: 3px; padding-right: 3px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt' vAlign='middle'><p><span style='font-size:10pt'>Ion-Indicating ratio Fe/(Si+Ca)</span><br /> <span style='font-size:10pt'>Porosity indicating ratio (H/(Si+Ca)</span></p></td></tr><tr><td style='padding-top: 3px; padding-left: 3px; padding-bottom: 3px; padding-right: 3px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt' vAlign='middle'><p> </p></td><td style='padding-top: 3px; padding-left: 3px; padding-bottom: 3px; padding-right: 3px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt' vAlign='middle'><p> </p></td></tr><tr><td style='padding-top: 3px; padding-left: 3px; padding-bottom: 3px; padding-right: 3px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Tracks 2 and 3</strong> </span></p></td><td style='padding-top: 3px; padding-left: 3px; padding-bottom: 3px; padding-right: 3px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Lithology indicator (Si/(Si+Ca)</span> <br/><span style='font-size:10pt'>Carbon/oxygen ratio (C/O)</span> <br/><span style='font-size:10pt'>Salinity indicator (Cl/H)</span> </p></td></tr></tbody></table></div><p><strong>Cement Bond Logging <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>This variant of acoustic logging makes use<strong><br /> </strong>of the observation that on acoustic logs run inside casing with good cement bonding, the amplitude of the signal detected at the receiver is much reduced, while in unsupported casing the signal remains strong. The log format may include a gamma ray and casing collar log for depth control, a transit-time curve, and an amplitude measurement for evaluation of bonding. There may also be a "signature" or a "variable density" display of the actual waveforms. These displays aid both quality control and log evaluation. In <a href='javascript:figurewin('../../asp/graphic.asp?code=425&order=0','0')'>Figure 1</a> , a typical cement bond log presentation, GR and casing collar logs are omitted.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Measurement Principle </em>A cement sheath bonded to the casing can be intuitively predicted to attenuate sound propagation in the pipe. CBL tools are able to differentiate between "no cement" and "solid cement." In the in-between range, however, these tools are not yet able to provide unambiguous answers to the question, Will the cement job prevent high-pressure fluid flow in the annulus? Even so, the tool is a valuable and much-used adjunct to completion work.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Cement bond logs began as auxiliaries to the acoustic log, run with tools designed for D-type logging. The information supplied was important enough to motivate development of special CBL tools, which now do the majority of the bond-logging measurements.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The chief problem with acoustic-type CBL tools is that the casing-signal attenuation is not directly related to the degree of hydraulic sealing provided by the annular cement. Hence, no matter how accurately the attenuation is measured, answers are still in terms of probabilities, except in the extreme conditions of perfect or no bonding.</span><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=425&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> illustrates the interplay of cement presence, bonding, signature, variable density display, and amplitude.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A CBL log should always include a section above the presumed cement top, where the pipe is completely unbonded. This gives one endpoint for the log; the amplitude curve should never read higher than this. The other endpoint is given by the zero point on the log scale. The curve never reads zero, but comes close (2-3 mv) in well-bonded pipe.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The paradox of acoustic-amplitude-type CBL logging is that the signal of most interest is zero or near it, but the equipment triggers on a finite signal in normal operating mode. As the signal approaches zero, it gets harder and harder to fine-tune the system to pick up the right signal. To correct this, the more sophisticated tools allow a detection window set at a selected time interval after the first pulse. This time is normally close to the casing transit time.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>As with normal interval transit time logging, good quality control with the CBL requires the use of an oscilloscope picture. With most equipment, this is the only way to be sure that the amplitude measurement is made on the first-arriving half-cycle of acoustic energy, essential for meaningful interpretation. <a href='javascript:figurewin('../../asp/graphic.asp?code=425&order=2','2')'>Figure 3</a> illustrates this concept.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In normal logging mode, the system triggers on the first arriving (E<sub>l</sub>) half-cycle, measuring both its single-receiver travel time (time from transmitter to receiver) and its amplitude. Two things can prevent this: (1) weak signals in well-bonded pipe can go below the detection threshold and (2) in hard-rock country, it is possible for formation signals to arrive ahead of casing signals. In the first case, cycle skips appear on the log ( <a href='javascript:figurewin('../../asp/graphic.asp?code=425&order=3','3')'>Figure 4</a> ), and the amplitudes recorded in the "skip" intervals are not interpretable. In the second case, the transit-time curve departs from the fairly straight-line value of casing transit time, and begins to follow formation variations. The scale is not directly correlatable, since the CBL transit time is a 3-ft single-receiver measurement and is not borehole-compensated. Normal casing transit time is 3 ft X 57 µsec/ft plus the travel time from tool to casing and back again, usually around 250-260 µ sec.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Most CBL tools assume in-phase arrivals through all sides of the casing, meaning that the tool must be centered. The degree of centering can be judged from the transit-time curve. A poorly centered tool produces shorter transit times. Centering may be virtually impossible in deviated holes or large casings.</span><br /> </p><p style='text-align: justify'><br /> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-37102749721965863332008-11-20T22:06:00.001-08:002008-11-20T22:06:15.349-08:00Well Logging Tools & Techniques (Casing Inspection Logs)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Casing Inspection Logs <br /></span></h2></p><p><span style='font-family:Times'><strong>Casing Inspection Logs<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Inspection of the mechanical state of the completion string is an important aspect of production logging. Many production (or injection) problems can be traced back to mechanical damage to, or corrosion of, the completion string. A number of inspection methods are avail-able, including<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>multifingered caliper logs<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>electrical potential logs<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>electromagnetic devices<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>borehole televiewers or borehole TV<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The majority of these devices measure the extent to which corrosion has taken place. Only the electrical potential logs indicate where corrosion is currently taking place. With the exception of the caliper logs, all the devices require that the tubing be pulled before running the survey, since most methods are designed to inspect casing rather than tubing, and most employ large-diameter tools.<br /></span></p><p><strong>Caliper Logs <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Various arrangements of caliper mechanisms are available to gauge the internal shape of a casing or tubing string. <a href='javascript:figurewin('../../asp/graphic.asp?code=427&order=0','0')'>Figure 1</a> illustrates three such tools.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Tubing profile calipers determine the extent of wear and corrosion and detect holes in the tubing string--all in a single run into the well. The large number of feelers on each size of caliper ensures detection of even very small irregularities in the tubing wall.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In pumping wells, the tubing caliper log may be run by one person, not a whole pulling unit crew. A "pull sheet" showing the maximum percentage of wall loss of every joint of tubing in the well may be prepared. Before the well is pulled, a program of rearranging the tubing string can be provided. Moving partially worn joints nearer the surface and discarding thin-wall joints substantially prolongs the effective life of tubing strings and reduces pulling costs in pumping wells. In flowing or gas lift wells, the tubing profile caliper provides an economical method of periodically checking for corrosion damage, monitoring the effectiveness of a corrosion inhibitor program, or detecting and removing damaged tubing joints when "working over" a well.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>One accessory tool that may be run in combination with the tubing profile caliper is a split detector. This tool, functioning much like a magnetic collar locator, is designed to detect and log vertical splits or hairline cracks in the tubing that might be difficult to locate with the profile caliper. In practice, the split detector is used to log down the tubing, and the profile caliper to log up the tubing. This gives a complete inspection for wall thickness and splits in one run of the cable in the well.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Casing profile calipers, which log 4 1/2-in. through 20-in. OD casing, are especially valuable where drilling operations have been carried on for an extended period of time through a string of casing. The determination of casing wear is of great importance when deciding if a liner can be safely hung, or if a full production string is required. In producing wells, the casing profile caliper will locate holes or areas of corrosion that may require remedial work. The tool is also valuable when abandoning wells because it permits grading of casing to be salvaged before it is pulled.</span><br /> </p><p><strong>Electrical Potential Lags <br /></strong></p><p><span style='font-size:10pt'>An electrical potential log determines the galvanic current flow entering or leaving the casing.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>This indicates not only where corrosion is taking place and the amount of iron being lost, but also where cathodic protection will be effective. The magnitude and direction of the current inside and outside the casing is derived mathematically from electrical potential measurements made at fixed intervals throughout the casing string. In order to achieve reliable results from this kind of survey, the borehole fluid must be an electrical insulator; i.e., the hole must either be empty or filled with oil or gas. Mud or other aqueous solutions cause a "short" that invalidates the measurements. The log itself is a recording versus depth of the small galvanic voltages detected.</span><strong><br /> <a href='javascript:figurewin('../../asp/graphic.asp?code=428&order=0','0')'/></strong><span style='font-size:10pt'>Figure 1 illustrates such a log, showing three runs, for each of which a different cathodic protection voltage was applied to the casing string.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=428&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> and <a href='javascript:figurewin('../../asp/graphic.asp?code=428&order=2','2')'>Figure 3</a> show an interpretation of casing potential profile logs run both with and without cathodic protection. Note that in Figure 3 the metal loss has been reduced to practically zero by application of an appropriate cathodic protection.</span><br /> </p><p style='text-align: justify'><br /> </p><p><strong>Electromagnetic Devices <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The most commonly used casing corrosion inspection tools are of the electromagnetic type. They come in two versions: those that attempt to measure the remaining metal thickness in a casing string, and those that try to detect defects in the inner or outer wall of the casing.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>They operate in a manner similar to openhole-induction tools. Each consists of a transmitter coil and a receiver coil. An alternating current is sent through the transmitter coil. This sets up an alternating magnetic field that interacts both with the casing and the receiver coil (</span><strong><br /> <a href='javascript:figurewin('../../asp/graphic.asp?code=429&order=0','0')'/></strong><span style='font-size:10pt'>Figure 1 ). The coils are spaced about three casing diameters apart to ensure that the flux lines sensed by the receiver coil are those that have passed through the casing.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The signal induced in the receiver coil will be out of phase with the transmitted signal. In general, the phase difference is controlled by the thickness of the casing wall. Thus, the raw log measurement is one of phase lag in degrees and the log is scaled in degrees. <a href='javascript:figurewin('../../asp/graphic.asp?code=429&order=1','1')'>Figure 2</a> illustrates an ETT log in severely corroded casing. Note that an increasing thickness corresponds to an increase in the phase shift angle. Some presentations of this log show a rescaling in terms of actual pipe thickness. This requires that the operator make some calibration readings in the type of casing present in the well. It is common to see large differences in thickness between adjacent stands due to a number of variables, such as the drift diameter of the pipe, the weight/foot, and the magnetic relative permeability of the steel used.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Another closely related measurement uses a slightly different technique and forms the basis of the pipe analysis log (PAL), also known as the vertilog. Two electromagnetic measurements are of interest in the context of the pipe analysis tool: magnetic flux leakage and eddy current distortion.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>If the poles of a magnet are positioned near a sheet of steel, magnetic flux will flow through the sheet ( <a href='javascript:figurewin('../../asp/graphic.asp?code=429&order=2','2')'>Figure 3</a> ). As long as the metal has no flaws the flux lines will be parallel to the surface. However, at the location of a cavity, either on the surface of the sheet or inside it, the uniform flux pattern will be distorted. The flux lines will move away from the surface of the steel at the location of the anomaly, an effect known as flux leakage. The amount of flux distortion will depend upon the size of the defect. If a coil is moved at a constant speed along the direction of magnetic flux parallel to the metal sheet, a voltage will be induced in the coil as it passes through the area of flux leakage.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The larger the anomaly, the greater the flux leakage, and therefore the greater the voltage. The magnetic flux is distorted on both faces of the sheet, regardless of the location of the defect, and therefore the coil only needs to be moved along one surface to survey the sheet completely. As the coil must be moved through a changing magnetic flux to produce a voltage, no signal is generated when it is moved parallel to the surface of an undamaged sheet of steel.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>When a relatively high frequency alternating current is applied to a coil close to a sheet of steel, the resulting magnetic field induces eddy currents in the steel ( <a href='javascript:figurewin('../../asp/graphic.asp?code=429&order=3','3')'>Figure 4</a> ). These eddy currents in turn produce a magnetic field that tends to cancel the original field, and the total magnetic field is the vector sum of the two fields. A measure voltage would be induced in a sensor coil situated in the magnetic field. The generation of eddy currents is, at relatively high frequencies, a near-surface effect, so if the surface of the steel adjacent to the coil is damaged, the magnitude of the eddy currents will be reduced and, consequently, the total magnetic field will be increased. This will result in a variation in the sensor coil voltage. A flaw in the sheet of metal on the surface away from the coils will not be detected and, depending upon its distance from the surface, a cavity within the sheet will not influence the eddy currents either.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The measuring sonde of the pipe analysis tool consists of an iron core with the pole pieces of an electromagnet at each end, and twelve sensor pads in two arrays between the pole pieces ( <a href='javascript:figurewin('../../asp/graphic.asp?code=429&order=4','4')'>Figure 5</a> ). The two arrays are juxtaposed to ensure complete coverage of the inner surface of the casing. Each of the pads contains a transmitting coil for the eddy current measurement, and two sensor coils wound in opposite directions for both the flux leakage and eddy current measurements. The two sensor coils are wound in opposite directions so that for both measurements there is zero voltage so long as no anomaly exists, but a signal will be produced when the quality of the casing is different below the two coils. The same sensor coils can be used for both measurements, as two distinct frequencies are involved. A frequency of 2 kHz is used for the eddy cur-rent measurement, giving a depth of investigation of about 1 mm. The sensor pads are mounted on springs so that they are held in contact with the casing, facilitated through centralization of the sonde. Various sizes of magnet pole pieces are available and are selected according to the inside diameter of the casing (casing ID) to optimize the signal strength for the flux leakage measurement.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Six measurements of flux leakage and eddy current distortion are made on each array, and the maximum signal from each array is sent uphole to the surface instrumentation. Four signals are recorded, both eddy current and flux leakage data from the two arrays.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The flux leakage data correspond to anomalies located anywhere in the casing, while eddy current distortion only occurs at the inside wall of the casing. The standard presentation of the measurements is as shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=429&order=5','5')'>Figure 6</a> , with the data from the two arrays displayed in tracks 2 and 3. Enhanced data are displayed in track 1, making any anomalies more obvious. At any particular depth the larger of the two flux leakage readings is selected and held for about 0.3 seconds on the display; the same is done for the eddy current data. This enhancement only occurs if the signal amplitudes exceed a certain threshold, to ensure that only significant defects are made more apparent. The holding of the signal allows signal levels to be seen more clearly.</span><br /> </p><p><strong>Borehole Televiewer <br /></strong></p><p><span style='font-size:10pt'>Tools with TV capability are available for borehole scanning.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The oldest is the borehole televiewer (BHTV), which uses a rotating ultrasonic transmitter and receiver to produce an image of the borehole or casing. There is also a borehole television camera that uses a TV camera and an intense light source to transmit a visual image of the borehole wall to the surface ( <a href='javascript:figurewin('../../asp/graphic.asp?code=430&order=0','0')'>Figure 1</a> ). The borehole television camera records on videotape and can be viewed with conventional video playback equipment.</span><br /> </p><p style='text-align: justify'><br /> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-67265358369812997762008-11-20T22:04:00.001-08:002008-11-20T22:04:38.159-08:00Well Logging Tools & Techniques (Production Logs)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Production Logs <br /></span></h2></p><p><strong>Production Logs <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Production Logs fit into three categories: profile logging, fluid identification, and temperature logging.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Profile Logging </em>Profile logging may be used to monitor injection rates in injection wells, to monitor production rates in producing wells, or to detect casing, tubing, and/or packer leaks, and channeling behind pipe in poorly cemented zones.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Although some tools can handle both environments, there are some methods applicable only to injection profiling.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In general, profiles may be obtained without disturbing dynamic well behavior by using the proper pressure control equipment and operating techniques; i.e., logs can, and should, be run through tubing without having to kill the well or pull the tubing.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Before attempting to obtain a profile log, plan the operation in advance with the logging service company, paying particular attention to:</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>expected flow rate <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>casing and tubing size, type, and weight</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>expected wellhead pressure</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>type of Christmas tree connections</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>tubing restrictions</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>corrosive or poisonous production fluids</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>completion records</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>openhole logs</span><br /> </p><p><span style='font-family:Arial Unicode MS; font-size:10pt'>Profiling tools available for measurement of fluid flow rates fall into three major categories: <br /></span></p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>continuous flowmeters <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>packer or restrictor type flowmeters</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>radioactive tracers (velocity and tracer modes)</span><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=431&order=0','0')'><span style='font-family:Arial Unicode MS; font-size:10pt'>Figure 1</span></a><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'> , <a href='javascript:figurewin('../../asp/graphic.asp?code=431&order=1','1')'>Figure 2</a> , and <a href='javascript:figurewin('../../asp/graphic.asp?code=431&order=2','2')'>Figure 3</a> illustrate the three types of flowmeter--the packer, the continuous, and the fullbore; <a href='javascript:figurewin('../../asp/graphic.asp?code=431&order=3','3')'>Figure 4</a> illustrates a radioactive tracer tool.</span><br /> </span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'> <br /></p><p> <br /></p><p><span style='font-size:10pt'>The accuracy of fluid flow rate measurements depends on:</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>the number of commingled phases <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>the well deviation</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the type of tool and the way it is run</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>hole diameter variations</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>production/injection rate variations</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Greater confidence in results can be expected when there is only one phase flowing (oil or water or gas), when the well is vertical, and when the appropriate tool is used for the particular well conditions. A lesser degree of confidence can be placed in results in deviated wells, conditions producing froth or slug flow, in wells that are "heading," and where the design limitations of the tools are exceeded (e.g., continuous flow-meters in low flow rate wells). For safety reasons, radioactive tracer surveys should only be run in injection wells.</span><br /> </span></p><p style='text-align: justify'> <br /></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=431&order=4','4')'><span style='font-size:10pt'>Figure 5</span></a><span style='font-size:10pt'> shows a production profile made from a flowmeter survey.</span><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=431&order=5','5')'><span style='font-size:10pt'>Figure 6</span></a><span style='font-size:10pt'> shows a radioactive tracer survey made in a "time-lapse" mode. Note the final destination of the released tracer material.</span><br /> </p><p><strong>Fluid Identification <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Production logging tools that can differentiate between oil, gas, and water in a producing well allow diagnosis of a number of completion problems, better understanding of reservoir performance, and monitoring of secondary and tertiary recovery projects.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In particular, they help to pinpoint gas, oil, and water entries into, and exits from, the production string, as well as to determine, in combination with flow measurements, how much of which fluid is produced from which horizon.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Many tools are available to distinguish one type of fluid from another. Their functions are measurement of fluid density, measurement of fluid dielectric constant, recovery of a fluid sample at well flowing pressure, and measurement of frequency spectrum of noise generated by fluid flow.</span><br /> </p><p><span style='font-size:10pt'>Two commonly used devices are:</span><br /> </p><ul style='margin-left: 81pt'><li><div><span style='font-family:Arial Unicode MS; font-size:10pt'>the gradiomanometer ( <a href='javascript:figurewin('../../asp/graphic.asp?code=432&order=0','0')'>Figure 1</a> ), which measures the pressure difference in the wellbore between two pressure sensors a fixed distance apart <br /></span></div><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>the fluid density log ( <a href='javascript:figurewin('../../asp/graphic.asp?code=432&order=1','1')'>Figure 2</a> ), which measures the absorption of gamma rays by the fluid between a gamma ray source and a detector<br /></span></p></li></ul><p> <br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>The hydro log ( <a href='javascript:figurewin('../../asp/graphic.asp?code=432&order=2','2')'>Figure 3</a> ) measures the dielectric constant of the fluid flowing in the wellbore. Because of the large difference between the dielectric constant of oil and water, the holdup of the flowing mixture may be estimated.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=432&order=3','3')'><span style='font-size:10pt'>Figure 4</span></a><span style='font-size:10pt'> illustrates a downhole fluid sampler. This instrument may be used to retrieve a sample of fluid from the well. It is useful for collecting oil, water, and gas samples for PVT analysis and pinpointing fluid levels in a well.<br /></span></p><p style='text-align: justify'><br /> <span style='font-size:10pt'>Turbulent fluid movement generates noise. Both the amplitude and frequency of this noise vary with the quantity and type of fluid and the medium through which the fluid is flowing. Measurements of these characteristic sounds can be interpreted to indicate the type of fluid flow and its location. In the case of gas, it is possible to calculate the approximate rate of flow.</span><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><strong>Temperature Logging<br /></strong></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Temperature logs may be used to monitor fluid flow in production or injection wells; they have the added advantage of detecting fluid flow outside the completion string in tubing/casing annulus or casing/formation annulus. They are particularly useful for finding gas entries to, or exits from, the wellbore; channels in poorly cemented sections; lost circulation zones in openhole; and the cement top in a recently cemented well.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Three types of temperature measurements are commonly available: a conventional temperature survey, a differential temperature survey, and a radial differential temperature survey.</span><br /> </p><p><a href='javascript:figurewin('../../asp/graphic.asp?code=433&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> illustrates a conventional thermometer and associated temperature survey.</span><br /> </p><p><br /> </p><p><br /> </p><p><a href='javascript:figurewin('../../asp/graphic.asp?code=433&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> illustrates the radial differential thermometer and its associated survey, in connection with which the operator should</span><br /> </p><ul style='margin-left: 81pt'><li><div><span style='font-family:Arial Unicode MS; font-size:10pt'>choose an appropriate scale so that there are no excessive scale changes over the zone of interest <br /></span></div><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>log going down where possible so that the presence of the tool and cable in the wellbore does not influence the measurement being made</span><br /> </p></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>remember that temperature-measuring devices are normally quite sensitive to temperature changes, but not very accurate in absolute terms<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=433&order=2','2')'><span style='font-size:10pt'>Figure 3</span></a><span style='font-size:10pt'> illustrates a temperature log showing oil production through a perforated interval.<br /></span></p><p style='text-align: justify'><br /> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-30101826758812218522008-11-20T22:03:00.003-08:002008-11-20T22:03:54.772-08:00Well Logging Tools & Techniques (Sampling & Testing)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Sampling & Testing <br /></span></h2></p><p><strong>Sidewall Coring Devices <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The objectives of coring are to bring a sample of the formation and its pore fluids to the surface in an unaltered state, to preserve the sample, and to transport it to a laboratory for analysis.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>These objectives are hard to meet since the very act of cutting a core will, to some extent, alter both the properties of the rock itself and the saturation of the fluids in its pores.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A number of techniques exist for minimizing the damage to formation samples. Other techniques, aimed at restoring the original state of the formation sample when it was at reservoir conditions, may also be brought into play at the time the core is analyzed.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Two methods of retrieving formation samples using wireline tools are currently in use: the conventional sidewall core gun, and a relatively new device, the core plugger.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Sidewall </em>Cores <a href='javascript:figurewin('../../asp/graphic.asp?code=434&order=0','0')'>Figure 1</a> illustrates a sidewall core gun; <a href='javascript:figurewin('../../asp/graphic.asp?code=434&order=1','1')'>Figure 2</a> shows it in close-up. The body of the gun carries a number of hollow steel bullets that can be fired selectively into the formation by means of explosive charges. Once lodged in the formation, the bullet can be retrieved by means of attached flexible steel wires. By raising the gun in the borehole, the tension on the wires is usually increased sufficiently to dislodge the bullet.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Once samples have been collected, the gun is raised to the surface and each core plug stored in a glass jar marked with the well name and the depth from which it was cut. Subsequently, these cores may be analyzed for porosity, permeability, and hydrocarbon content.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Note that the gun is equipped with an SP electrode. This allows the tool to be placed at the correct depth in the well prior to sampling by correlation of a short section of the S<sub>p</sub> log with other openhole logs already run.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>These guns come in a variety of shapes and sizes. On average, they are capable of retrieving 60 samples in one trip into the hole. The diameter of the core barrel may be anywhere between 3/4 in. and 1 1/8 in. The length of the core retrieved is a function of many variables. Depending on the strength of the explosive charge used, the type of core barrel selected, and the hardness of the formation, the length of the recovered sample may be as long as 2 in., or as short as nothing at all.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>There are obvious limitations to the amount of data that can be obtained from sidewall cores. In the first place, the sample is taken from a part of the formation that has been flushed with mud filtrate. Secondly, the act of explosively firing the coring bullet into the formation may induce local fracturing. Occasionally, the retainer wires used to retrieve the core barrel may sever and the bullet will be lost in the hole. Lastly, the trip up the hole to the surface involves a considerable amount of flushing through the mud column. Despite these drawbacks, sidewall cores are still good quick-look indicators of formation properties. It is normal practice to inspect these cores at the wellsite for hydrocarbon odor, fluorescence, stain, and cut if a mud logging unit or geologist's doghouse is available.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Core <em>Plugger </em>The core plugger uses a motorized circular bit to bore into the wall of the formation in order to retrieve samples. Currently, this tool is capable of cutting up to 12 core samples in one run in the hole. Core size is 15/16 in. in diameter and 1 3/4 in. long. Each core takes about five minutes to cut. This device works better than the conventional sidewall core gun in consolidated formations, and causes no physical damage to the sample.</span><br /> </p><p><strong>Wireline Formation Testers <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Wireline formation testers serve a number of useful purposes, including obtaining a sample of formation fluid, gauging formation permeability, and measuring formation pressure to determine formation pressure gradients.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Wireline formation testers have been used for many years to recover samples of formation fluid both in open and cased holes. Traditional tools suffered from a number of drawbacks, such as lack of resolution and accuracy of pressure gauges, and the inability of the instrumentation to tell the operator whether or not a good packer seal was obtained until it was too late to rectify the situation.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>These inadequacies have now largely been overcome by the introduction of two key features of modern repeat formation testers, namely quartz crystal pressure gauges and pretest capabilities that allow the operator to rectify a bad seal before it leads to undesirable results. An added bonus is the ability of these tools to make pressure tests independent of sample taking. Indeed, in practice nowadays it is quite common to use these tools solely to make pressure tests.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Tool Characteristics and Applications</em> Most service companies now offer a repeat formation tester that includes pretest chambers, sample chambers, and a high-resolution pressure gauge.</span><br /> </p><p><span style='font-size:10pt'>Wireline formation testers are particularly useful</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>when investigating zones of interest in which conventional tests are not feasible, such as those too far above TD, those lacking good intervals for setting straddle packers, or those with very short intervals, where depth control is critical <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>for pinning down water-oil, gas-oil, or gas-water contacts</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>when rig time is critical</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>when pressure control is critical because of time of day or rig locations</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>When ordering the service, give plenty of notice to the service company. Variables such as sample size, packer hardness, choke size, pressure gauges, and water cushions may not be universally available. If a sample of recovered hydrocarbons is needed for PVT lab analysis, a special pressure cylinder should be requested.</span><br /> </span></p><p><span style='font-size:10pt'>When running the tool, a valid test is one that recovers significant quantities of fluid and/or records formation and hydrostatic pressure.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A dry test is indeterminate, and the tool should be repositioned several times to determine whether the formation is impermeable (in which case all tests will be dry) or the tool was set in a shale or tight streak (in which case repositioning should result in a valid test).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A lost packer seal is also indeterminate. In that case, the tool should be repositioned. Openhole logs are particularly helpful in resolving dry tests and lost packer seals. The microlog, if available, is useful as an indicator of tight streaks, and caliper logs, particularly the four-arm type, are useful for avoiding hole conditions leading to lost packer seals.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Operating Principles <a href='javascript:figurewin('../../asp/graphic.asp?code=435&order=0','0')'/></em>Figure 1 shows the RFT tool in the closed position (a) for descending into the well, and in the open (set) position (b) for pressure measurement and sample taking.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Communication between the formation and the tool interior is established through the probe. <a href='javascript:figurewin('../../asp/graphic.asp?code=435&order=1','1')'>Figure 2</a> is a schematic of the tool's sampling system. Note the details of the actuation of the filter probe: in the setting cycle it is forced to cut through mudcake, and in the sampling cycle it is retracted to open the path for formation fluids.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Note also the pretest chambers and the position of the sample chambers. The two pretest chambers, automatically activated every time the tool is set, withdraw 10 cc of formation fluid each. Chamber 2 has a higher flow rate than chamber 1. The actual rates of fluid withdrawal vary with the tool and the downhole conditions but are approximately 50 cc/min for chamber 1 and 125 cc/min for chamber 2, resulting in pretest times of roughly 12 seconds and 5 seconds. The pretest samples are expelled back into the mud column and are not saved.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> <a href='javascript:figurewin('../../asp/graphic.asp?code=435&order=2','2')'><span style='font-size:10pt'>Figure 3</span></a><span style='font-size:10pt'> shows a typical log produced during a test. Since the tool is stationary in the hole during the test, the recording is made on a time scale with increasing time in the down-hole direction on the log. Notice that in track 1, pressure is recorded in analog form. Four subtracks record the units, tens, hundreds, and thousands of psi.</span><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><span style='font-size:10pt'>Each record shows the following pressures:</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'><span style='font-family:Times New Roman'>·</span><span style='font-family:Arial Unicode MS'> before tool is set--hydrostatic <br/></span><span style='font-family:Times New Roman'>·</span><span style='font-family:Arial Unicode MS'> during pretest--drawdown <br/></span><span style='font-family:Times New Roman'>·</span><span style='font-family:Arial Unicode MS'> after pretest--buildup <br/></span><span style='font-family:Times New Roman'>·</span><span style='font-family:Arial Unicode MS'> after buildup--formation pressure<br /></span></span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The standard gauge used in the RFT is a strain gauge calibrated by a "dead weight" tester. The accuracy of this system, after applying temperature corrections, is 0.41% of full scale, i.e., 41 psi for a 10,000 psi gauge. The resolution of the gauge is about I psi, with a repeatability of 3 psi. The accuracy may be improved to 0.31% full scale if a special calibration technique is employed involving placement of the gauge and the downhole electronics in a temperature-controlled oven.</span><br /> </span></p><p><span style='font-size:10pt'>Where greater accuracy is required, a high-precision quartz gauge may be used. The accuracy is then 0.5 psi, provided that the temperature is known within 1</span><span style='font-family:Symbol'></span><span style='font-size:10pt'> C. Resolution is on the order of 0.01 psi.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>It should be noted ( <a href='javascript:figurewin('../../asp/graphic.asp?code=435&order=3','3')'>Figure 4</a> ) that the quartz gauge is located lower in the tool than the reference measurement point that is the strain gauge. Hence, the pressure recorded by the two gauges is different due to the hydrostatic head of a column of silicone grease. In some cases, a further pressure difference may be noted between the two gauges, since the strain gauge is calibrated in psig and the quartz gauge is psia.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Interpretation </em>In order to make the greatest use of RFT data, the analyst should be able to interpret the following types of RFT records:</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>pretest records for formation permeability <br /></span></li><li><span style='font-family:Arial Unicode MS; font-size:10pt'>post pretest buildup for formation permeability <br /></span></li><li><span style='font-family:Arial Unicode MS; font-size:10pt'>large-sample fill-up time for formation permeability <br /></span></li><li><span style='font-family:Arial Unicode MS; font-size:10pt'>sequential pressure readings versus depth for pore pressure gradients <br /></span></li><li><span style='font-family:Arial Unicode MS; font-size:10pt'>large-sample collection data for expected formation product ion<br /></span></li></ul><p><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>Pretest Records for Formation Permeability <a href='javascript:figurewin('../../asp/graphic.asp?code=435&order=4','4')'/></em>Figure 5 shows a typical pretest record. In reality, only one pretest is required to estimate formation permeability. The magnitude of the pressure differential (DP) between pretest sampling pressure and formation pressure coupled with the flow rate during pretest is sufficient to define permeability. In general, this may be found by a relation of the form</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS; font-size:10pt'>k = A • C • q • µ / DP<br /></span></p><p><span style='font-family:Arial Unicode MS; font-size:10pt'>where: <br /></span></p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS; font-size:10pt'>k is permeability in millidarcies</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>A is constant to take care of units</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>C is the flow shape factor</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>q is the flow rate in cc/second</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>µ is the viscosity of the fluid in cp</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>P is the drawdown in psi</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>A number of flow regimes may exist around an RFT tool and the borehole. It is generally agreed that the flow is somewhere between hemispherical and spherical. Computer modeling of the probe/formation system for one service company's tool shows that the combination of constants A • C to be used should be such that <br /></span></p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The flow rate is derived by dividing the 10 cc volume of the pretest chamber by the sampling time read from the pressure record. The viscosity, µ is considered to be that of the mud filtrate and may be estimated from published charts. DP is read from the pressure recording as the difference between pretest sampling pressure and formation pressure.</span><br /> </span></p><p><span style='font-size:10pt'>The pretest method of permeability determination has these limitations:</span><br /> </p><ul style='margin-left: 81pt'><li><div><span style='font-family:Arial Unicode MS; font-size:10pt'>If the permeability is very high, the drawdown is very small and cannot be measured accurately. <br /></span></div><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>If the permeability is very low, the sampling pressure may drop below the bubble-point, in which case gas or water vapor is liberated and the</span><br /> </p><p><span style='font-size:10pt'>flow rate of the liquid withdrawn is less than the volumetric displacement rate of the pretest pistons.</span><br /> </p><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>The volume of formation investigated is small and hence the permeability measured may be that of the damaged zone, if present, and thus not representative of the formation as a whole.</span><br /> </p></li></ul><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>In general, a good estimate of formation permeability may be obtained from a visual inspection of the pretest record.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Post Pretest Buildup for Formation Permeability </em>Permeabilities obtained from pretest may be subject to the errors mentioned above; they also may not be measuring absolute permeability but the relative permeability to the water in the flushed zone. <a href='javascript:figurewin('../../asp/graphic.asp?code=435&order=5','5')'>Figure 6</a> marks the pretest region on a set of relative permeability curves, from which it can be deduced that the pretest permeabilities are less than half absolute permeability when measured in an invaded oil zone.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A preferred method of calculating permeability is the analysis of the late-time portion of the pressure buildup record after the pretest disturbance has been made. A much larger rock volume can be investigated in this fashion. The method effectively measures k<sub>ro</sub> close to Sw<sub>irr</sub>, very close to k absolute (see <a href='javascript:figurewin('../../asp/graphic.asp?code=435&order=5','5')'>Figure 6</a> ) when the measurement is made above the transition zone.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Figures 7a and 7b illustrate two modes of propagation of a pressure disturbance; <a href='javascript:figurewin('../../asp/graphic.asp?code=435&order=6','6')'>Figure 7a</a> is for spherical propagation and <a href='javascript:figurewin('../../asp/graphic.asp?code=435&order=7','7')'>Figure 7b</a> for cylindrical propagation. In a thin bed, the cylindrical mode predominates, whereas in a thick bed the spherical mode prevails.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In order to determine whether cylindrical or spherical flow is predominant in a test, the pressure may be plotted against one of two time functions, respectively derived on the assumption of cylindrical and spherical flow. The characteristics of these time functions are such that a plot of pressure versus the relevant time function for the actual flow regime involved produces a straight line whose slope is proportional to the formation permeability and whose intercept at the zero time point gives the formation pressure. <a href='javascript:figurewin('../../asp/graphic.asp?code=435&order=8','8')'>Figure 8</a> gives an example of such time-pressure plots.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Large-Sample Fill-Up Time for Formation Permeability </em>When a large sample of formation fluid is recovered, the time taken to fill the sample chamber can be used as an indicator of permeability. Drawdown is here considered to be the formation pressure itself, since the sample chamber is for all practical purposes at atmospheric pressure. This may not hold true if the fill-up time is limited by a water cushion and a choke. Use this method with discretion and take it for what it is: a quick and dirty way of finding permeability.</span><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><span style='font-size:10pt'>For one service company's large sample chamber, the following equation may be used:</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where:</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS; font-size:10pt'>k is fill-up permeability in mud</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>C is flow-shape factor</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>q is flow rate in cc/sec</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>µ is fluid viscosity in cp</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>P is drawdown pressure in psi</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>Sequential Pressure Readings versus Depth for Pore Pressure Gradients </em>Since many formation pressure measurements may be made on one trip in the hole, pressure gradients can be calculated and plotted. The easiest method is to plot formation pressure against depth. It is useful to plot hydrostatic pressure on the same plot.</span><br /> </span></p><p><span style='font-size:10pt'>Gas-oil and oil-water contacts are evident on a plot of this nature. The fluid density can be deduced from the pressure gradient, by using</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS; font-size:10pt'>fluid density gm/cc = pressure gradient (psi/ft) • 2.3072<br /></span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Care should be taken in low-porosity transition zones where capillary pressure effects are pronounced. Log-derived oil-water contacts (OWC), for example, may appear somewhat shallower in the well than the free water level indicated from plots of formation pressure versus depth.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Formation Production Estimates </em>When a large sample is recovered, it is possible to predict formation productivity by analysis of the recovered oil, water, and gas. At the surface a miniseparator is used to measure the volumes of oil, water, and gas recovered ( <a href='javascript:figurewin('../../asp/graphic.asp?code=435&order=9','9')'>Figure 9</a> ). The water recovered will be a mixture of mud filtrate and formation water. The amount of formation water is calculated from the relationship</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p><span style='font-size:10pt'>% </span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Empirical charts then link recovered volumes to predicted production. Three areas are delineated on the chart indicating formations that are gas, oil, and water productive. An estimate of water cut can also be made using</span><br /> </p><p><br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>REFERENCES<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Alger, R. P., S. Locke, W. A. Nagel, and H. Sherman. 1971. The dual spacing neutron log-CNL. SPE Paper 3565.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Allaud, L., and N. Martin. 1979. Schlumberger, The history of a technique. 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M. 1985. openhole log analysis and formation evaluation. Boston, MA: IHRDC.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Bateman, R. N., and C. E. Konen. 1977. The log analyst and the programmable pocket calculator. The Log Analyst (September-October).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Berry, W. R., N. P. Head, and N. L. Mougne. 1979. Dielectric constant logging: A progress report. SPWLA 20th symposium (June).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Blakeman, a. R. 1962. A method of analyzing electrical logs recorded on a logarithmic scale. J. Pet. Tech. (August).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Bobek, J. a., C. C. Mattax, and M. 0. Denekas. 1958. Reservoir rock wettability--its significance and evaluation. Pet. Trans. AlME 213:155-160.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Bradley, J. S. 1980. Fluid and electrical formation conductivity factors calculated for a spherical-grain onion-skin model. The Log Analyst 21 (1) :24-32.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Chew, W. C. 1982. Response of the deep propagation tool in invaded boreholes. SPE 10989.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Coates, G. R., and J. L. Dumanoir. 1974. A new approach to improved log-derived permeability. The Log Analyst 15 (1):17-29.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Cox, J. W., and L. L. Raymer. 1976. The effect of potassium salt muds on gamma ray and spontaneous potential measurements. SPWLA 17th Annual Logging Symposium.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>de Witte, L. 1950. Relations between resistivities and fluid contents of porous rocks. oil and Gas journal (August 24).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Doll, H. G. 1949. Introduction to induction logging. J. Pet. Tech. (June).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>1949. The SP log in shaly sands. J. Pet. Tech. 2912.<br /></span></p><p><span style='font-size:10pt'>. 1949. The SP log: Theoretical analysis and principles of interpretation. Trans. AIME 179:146.<br /></span></p><p><span style='font-size:10pt'>. 1950. The microlog. Trans. AIME 189.<br /></span></p><p><span style='font-size:10pt'>. 1951. The laterolog. j Pet. Tech. (November).<br /></span></p><p><span style='font-size:10pt'>. 1953. The microlaterolog. J. Pet. Tech. (January).<br /></span></p><p><span style='font-size:10pt'>. 1955. Filtrate invasion in highly permeable sands. Pet. Eng. (January).<br /></span></p><p><span style='font-size:10pt'>. 1955. The invasion process in high permeability sands. Pet. Eng. (January).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Doll, H. G., and N. Martin. 1960. Suggestions for better electric log combinations and improved interpretations. Geophysics (August).<br /></span></p><p><span style='font-size:10pt'>Dresser Atlas. 1974. Log review 1. (REP 03/81): Sec. 4. Dresser Industries Inc.<br /></span></p><p><span style='font-size:10pt'>Dresser Atlas. 1979. Gamma ray spectral data assists in complex formation evaluation. (February).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Dumanoir, J. L., H. P. Tixier, and M. Martin. 1957. Interpretation of the induction-electrical log in fresh mud. J. Pet. Tech. (July).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Eck, M. E., and D. E. Powell. 1983. Application of electromagnetic propagation logging in the Permian basin of West Texas. SPE 12183.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Ellis, D., C. Flaum, C. Roulet, E. Marienbach, and B. Seeman. 1983. Litho-density tool calibration. SPE 12048.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Evers, J. F., and B. G. Iyer. 1975. A statistical study of the SP log in fresh water formation of northern Wyoming. SPWLA 16th Annual Logging Symposium (June).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Fertl, W. H., and E. Frost, Jr. 1982. Experiences with natural gamma ray spectral logging in North America. SPE 11145.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Fertl, W. H., W. L. Stapp, D. B. Vaello, and W. C. Vercellino. 1980. Spectral gamma ray logging in the Texas Austin Chalk Trend. J. Pet. Tech. (March).<br /></span></p><p><span style='font-size:10pt'>Frank, R. W. 1986. Prospecting with old E-logs. Houston: Schlumberger Educational Services.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Garner, J. S., and J. L. Dumanoir. 1980. Litho-density log interpretation. Paper N, Trans., SPWLA 21st Annual Logging Symposium, Lafayette, LA. (July).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Geng Xiuwen, Yong Yizu, Lu Da, and Shao Shufang. 1983. Dielectric log: A logging method for determining oil saturation. J. Pet. Tech. (October).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Goetz, J. F., W. J. Prins, and J. F. Logar. 1977. Reservoir delineation by wireline techniques. 6th Annual Convention of the Indonesia Petroleum Association, Jakarta (May).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Gondouin, M., M. P. Tixier, and G. L. Simard. 1957. An experimental study on the influence of the chemical composition of electrolytes on the SP curve. Trans. AIM 210:58.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Graton, L. C., and H. J. Fraser. 1935. Systematic packing of spheres--with particular relation to porosity and permeability. J. of Geol. 43: 785-909.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Hassan, N., A. Hossin, and A. Combaz. 1976. Fundamentals of the differential gamma ray log-interpretation technique. Paper presented at SPWLA 17th Annual logging Symposium, Denver (June).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Hicks, W. G., and J. H. Berry. 1956. Application of continuous velocity logs to determination of fluid saturation of reservoir rocks. Geophysics 21 (July):3.<br /></span></p><p><span style='font-size:10pt'>Hilchie, D. W. 1979. Old electrical log interpretation. Golden, CO: Douglas W. Hilchie, Inc.<br /></span></p><p><span style='font-size:10pt'>. 1984. A new water resistivity versus temperature equation. The Log Analyst (July-August) :20.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Honarpour, M., L. F. Koederitz, and A. H. Harvey. 1982. Empirical equations for estimating two-phase relative permeability in consolidated rock. J. Pet. Tech. (December).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Horst, G., and L. Creager. 1974. Progress report on the interpretation of the dual laterolog-Rxo tool in the Permian basin. SPWLA 15th Annual Symposium (June).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Huchital, G. S., R. Hutin, Y. Thoraval, and B. Clark. 1956. The deep propagation tool (a new electromagnetic logging tool). SPE 10988, presented at the Annual Technical Conference and Exposition, San Antonio, Texas (October).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Johnson R., and C. J. Evans. 1983. Results of recent electromagnetic propagation time logging in the Worth Sea. Presented at the SPWLA 8th European Formation Evaluation Symposium, London (March).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Kenyon, W. E., and P. L. Baker. 1984. EPT interpretation in carbonates drilled with salt muds. SPE 13192, presented at the Annual Technical Conference and Exhibition, Houston, Texas (September).<br /></span></p><p><span style='font-size:10pt'>Kokesh, F. P. 1951. Gamma ray logging. Oil and Gas Journal (July).<br /></span></p><p><span style='font-size:10pt'>Kokesh, F. P., and R. B. Blizard. 1959. Geometric factors in sonic logging. Geophysics 24 (February, no. 1).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Kokesh, F. P., R. J. Schwartz, W. B. Wall, and R. L. Morris. 1965. A new approach to sonic logging and other acoustic measurements. J. Pet. Tech. 17 (March) :3.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Le Blanc, R. J., Sr. 1977. Distribution and continuity of sandstone reservoirs (Parts 1 and 2). J. Pet. Tech. (July) :776-804.<br /></span></p><p><span style='font-size:10pt'>Leverett, M. C. 1941. Capillary behavior in porous solids. Trans. AIME.<br /></span></p><p><span style='font-size:10pt'>Lynch, E. J. 1962. Formation evaluation. Harper's Geoscience Series. New York: Harper and Row.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Marett, G., P. Chevalier, P. Souhaite, and J. Suau. 1976. Shaly sand evaluation using gamma ray spectrometry applied to the North Sea Jurassic. SPWLA 17th Annual Symposium (June).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Mason, K. L. 1984. Tricone bit selection using sonic logs. SPE 13256, presented at the Annual Technical Conference and Exhibition, Houston, Texas (September).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Mazzagatti, R. P., D. J. Dowling, J. C. Sims, A. E. Bussian, and R. S. Simpson. 1983. Laboratory measurements of dielectric constant near 20 MH3. SPE 12097.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Meador, R. A., and P. T. Cox. 1975. Dielectric constant logging: A salinity independent estimation of formation water volume. SPE 5504.<br /></span></p><p><span style='font-size:10pt'>Molina, N. N. 1983. Systematic approach aids reservoir stimulation. Oil and Gas Journal (April).<br /></span></p><p><span style='font-size:10pt'>Moran, J. H., and K. S. Kunz. 1962. Basic theory of induction logging. Geophysics (December).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Morris, R. L. and W. P. Biggs. 1967. Using log-derived values of water saturation and porosity. SPWLA Symposium.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Morris, R. L., D. R. Grine, and T. E. Arkfeld. 1964. Using compressional and shear acoustic amplitudes for the location of fractures. J. Pet. Tech. 16 (June) :6.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Overton, H. L., and L. B. Lipson. 1958. A correlation of the electrical properties of drilling fluids with solids content. Petroleum Trans. AIMS 213.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Pickett, G. R. 1963. Acoustic character logs and their applications in formation evaluations. J. Pet. Tech. 15 (June) :6. <br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Pirson, S. J., E. M. Boatman, and R. L. Nettle. 1964. Prediction of relative permeability characteristics of intergranular reservoir rocks from electrical resistivity measurements. J. Pet. Tech. (May):565-570.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Poupon, A., C. Clavier, J. Dumanoir, R. Gaymard, and A. Misk. 1970. log analysis of sand-shale sequences: A systematic approach. J. Pet. Tech. (July) :867-881.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Quirein, J. A., J. S. Gardner, and J. T. Watson. 1982. Combined natural gamma ray spectral/litho-density measurements applied to complex lithologies. SPE 11143.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Rau, R. N., and R. P. Wharton. 1980. Measurement of core electrical parameters at UHF and microwave frequencies. SPE 9380.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Raymer, L. L. 1981. Elevation and hydrocarbon density correction for log derived permeability relationships. The Log Analyst. (May-June) :3-7.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Raymer, L. L., R. W. Hoyle, and N. P. Tixier. 1962. Formation density log applications in liquid-filled holes. J. Pet. Tech. (March).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Raymer, L. L., and S. R. Hunt. 1980. An improved sonic transit time-to-porosity transform. SPWLA 21st Symposium (July).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Raymer, L. L., and P. M. Freeman. 1984. In-situ determination of capillary pressure, pore throat size and distribution, and permeability from wireline data. Paper CCC, SPWLA 25th Annual logging Symposium (June 10-13).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Raza, S. H., L. S. Treiber, and D. L. Archer. 1968. Wettability of reservoir rocks and its evaluation. Producers Monthly (April).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Rockwood, S. H., G. H. Lair, and B. J. Langford. 1957. Reservoir volumetric parameters defined by capillary pressure studies. Trans. AIMS 210.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Runge, R. J., A. S. Worthington, and D. R. Lucas. 1969. Ultra-log spaced electric log (ULSEL). The Log Analyst (September-October) :10.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Schlumberger, C. M. Schlumberger, and E. G. Leonardon. 1934. (3 papers, all in Trans. AIMS 110): Some observations concerning electrical measurements in anisotropic media, and their interpretation, p. 159; Electrical coring: A method of determining bottomhole data by electrical measurements, p. 237.; A new contribution to subsurface studies by means of electrical measurements in drill holes, p. 273.<br /></span></p><p><span style='font-size:10pt'>Schlumberger. 1969. log interpretation principles.<br /></span></p><p><span style='font-size:10pt'>Schlumberger Ltd. 1972, 1977. log interpretation charts.<br /></span></p><p><span style='font-size:10pt'>Schlumberger Well Services. Seismic applications. Flyer.<br /></span></p><p><span style='font-size:10pt'>Schlumberger Well Services. 1972. The essentials of log interpretation practice.<br /></span></p><p><span style='font-size:10pt'>Schlumberger Well Services. 1972. log interpretation principles. Vol. 1, Chap. 2 and 13.<br /></span></p><p><span style='font-size:10pt'>Schlumberger Well Services. 1973. Production log interpretation.<br /></span></p><p><span style='font-size:10pt'>Schlumberger Well Services. 1979. Well Evaluation Conference.<br /></span></p><p><span style='font-size:10pt'>Schlumberger Well Services. 1982. Litho-density tool interpretation. (M 086108).<br /></span></p><p><span style='font-size:10pt'>Schlumberger Well Services. 1982. Well evaluation developments --continental Europe.<br /></span></p><p><span style='font-size:10pt'>Schlumberger Well Services. 1984. log interpretation charts.<br /></span></p><p><span style='font-size:10pt'>Schlumberger Well Surveying Corporation. 1962. Induction log correction charts.<br /></span></p><p><span style='font-size:10pt'>Schuster, N. A., J. D. Badon, and E. R. Robbins. 1976. Application of the ISF/sonic combination tool to Gulf Coast formations. Trans. GCAGS.<br /></span></p><p><span style='font-size:10pt'>Segesman, F. 1962. New SP correction charts. Geophysics 27 (December) :6, pert 1.<br /></span></p><p><span style='font-size:10pt'>Segesman, F., and M. P. Tixier. 1958. Some effects of invasion on the SP curve. Presented at the Annual Meeting, SPE (October).<br /></span></p><p><span style='font-size:10pt'>Sen, P. N. 1980. The dielectric and conductivity response of sedimentary rocks. SPE 9379.<br /></span></p><p><span style='font-size:10pt'>Sherman, H., and S. Locke. 1975. Effect of porosity on depth of investigation of neutron and density sondes. Paper SPE 5510, presented at the Annual Meeting, SPE/AIMS, Dallas, Texas September-October).<br /></span></p><p><span style='font-size:10pt'>Silva, P., and Z. Bassiouni. 1981. A new approach to the determination of formation water resistivity from the SP log. SPWLA 22nd Annual logging Symposium.<br /></span></p><p><span style='font-size:10pt'>Smith, H. D., Jr., C. A. Robbins, D. M. Arnold, and J. G. Deaton. 1983. A multi-function compensated spectral natural gamma ray logging system. SPE 12050.<br /></span></p><p><span style='font-size:10pt'>SPWLA. 1979. The art of ancient log analysis. SPWLA Reprint Series.<br /></span></p><p><span style='font-size:10pt'>Suau, J., P. Grimaldi, A. Poupon, and P. Souhaite. 1972. The dual laterolog-Rxo tool. SPE Paper 4018, presented at the Annual Symposium of the SPE.<br /></span></p><p><span style='font-size:10pt'>Thomas, D. H. 1977. Seismic applications of sonic logs. 5th European S SPWLA logging Symposium.<br /></span></p><p><span style='font-size:10pt'>Timur, A. 1968. An investigation of permeability, porosity, and residual water saturation relationship for sandstone reservoirs. The Log Analyst 9 (4) :8-17.<br /></span></p><p><span style='font-size:10pt'>Tittle, C. W. 1961. Theory of neutron logging. Geophysics 26: 27-29.<br /></span></p><p><span style='font-size:10pt'>Tittman, J., H. Sherman, W. A. Nagel, and R. P. Alger. 1966. The sidewall epithermal neutron porosity log. Trans. AIMS 237:1351-1362.<br /></span></p><p><span style='font-size:10pt'>Tittman, J., and J. S. Wahl. 1965. The physical foundations of formation density logging (gamma-gamma). Geophysics (April).<br /></span></p><p><span style='font-size:10pt'>Tixier, M. P. 1949. Evaluation of permeability from electric-log resistivity gradients. Oil and Gas Journal 48 (June 16):113.<br /></span></p><p><span style='font-size:10pt'>Tixier, M. P., R. P. Alger, W. P. Biggs, and B. N. Carpenter. 1965. Combined logs pinpoint reservoir resistivity. Pet. Eng. (February-March).<br /></span></p><p><span style='font-size:10pt'>Tixier, M. P., R. P. Alger, and C. A. Doh. 1959. Sonic logging. J. Pet. Tech. 11 (May) :5.<br /></span></p><p><span style='font-size:10pt'>Tixier, M. P., R. P. Alger, and D. R. Tanguy. 1960. New developments in inductions and sonic logging. J. Pet. Tech. 12 (May) :5.<br /></span></p><p><span style='font-size:10pt'>Tixier, M. P., M. Martin, and J. Tittman. 1956. Fundamentals of logging. Lecture 6, Petroleum Engineering Conference, University of Kansas, Lawrence.<br /></span></p><p><span style='font-size:10pt'>Truman, R. B., R. P. Alger, J. G. Connell, and R. L. Smith. 1972. Progress report on interpretation of the dual-spacing neutron log (CNL) in the U.S. Presented at the SPWLA Annual Meeting.<br /></span></p><p><span style='font-size:10pt'>Wahl, J. S., W. B. Nelligan, and A. H. Frentrop. 1970. The thermal neutron decay time log. Soc. Pet. Eng. J. (December) :365-379.<br /></span></p><p><span style='font-size:10pt'>Wahl, J. S., J. Tittman, and C. W. Johnstone. 1964. The dual spacing formation density log. Trans. AIMS 231:1411-1416, and J. Pet. Tech. (December).<br /></span></p><p><span style='font-size:10pt'>Watson, C. C. 1983. Numerical simulation of the litho-density tool lithology response. SPE 12051.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Weinberg, A. M., and E. P. Wigner. 1958. The physical theory of neutron chain reactors. Chicago: University of Chicago Press.<br /></span></p><p><span style='font-size:10pt'>Wharton, R. P., G. A. Hazen, R. W. Rau, and D. L. Best. 1980. Electromagnetic propagation logging: Advances in technique and interpretation. SPE 9267.<br /></span></p><p><span style='font-size:10pt'>Williams, H., and H. F. Dunlap. 1984. Short-term variations in drilling parameters, their measurement and implications. The Log Analyst (September-October):3-9.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Wyllie, M. R. J. 1949. A quantitative analysis of the electrochemical component of the SP curve. Trans. AIME 186:17.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Wyllie, M. R. J., A. R. Gregory, and G. H. F. Gardner. 1956. Elastic wave velocities in heterogeneous and porous media. Geophysics 21 (January):l.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>________ . 1958. An experimental investigation of factors affecting elastic wave velocities in porous media. Geophysics 23 (July) :3.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Wyllie, M. R. J. and W. D. Rose. 1950. Some theoretical considerations related to the quantitative evaluation of the physical characteristics of reservoir rock from electrical log data. J. Pet. Tech. 189 (April):105-108.<br /></span></p><p><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-10266219572984710302008-11-20T22:03:00.001-08:002008-11-20T22:03:11.389-08:00Well Logging Tools & Techniques (Special Open Hole Tools)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Special Open Hole Tools<br /></span></h2></p><p><span style='font-family:Times'><strong>Caliper Logs<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The caliper log measures the diameter of the borehole. The first caliper logs were developed to determine borehole size in holes shot with nitroglycerin. These early logs showed large variations in hole size, even in the portions of the hole that had not been shot. This illustrated the need for the caliper log over the entire hole.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Methods of Recording </em>Several types of caliper are currently in use. One type consists of three or four spring-driven arms that contact the wall of the borehole. The instrument is lowered to the total depth, and the arms are released either mechanically or electrically. The spring tension against the arms centers the tool in the well. The arms move in and out with the change in wellbore diameter. The arm motion is transmitted to a rheostat so that change in the resistance of an electric circuit is proportional to the hole diameter. The borehole diameter is recorded at the surface by measuring the potential across this resistance.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Another instrument uses three flexible springs that contact the wall of the borehole. These springs are connected to a plunger that moves up or down as the springs expand or contract with changes in borehole diameter. The plunger passes through two coils. When an alternating current is passed through one coil, an electromotive force (emf) is induced in the other coil. The amount of this induced emf is a function of the plunger position and is proportional to borehole diameter.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Both of these instruments may be adjusted to record borehole area rather than hole diameter. If the caliper log is used to determine hole volume, it is desirable to record area on a linear scale. If the caliper log is used to determine hole configuration, the hole diameter is recorded on a linear scale.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A third type of caliper log, the microcaliper, is discussed in connection with the electrical-log microdevices. This instrument uses two pads rather than arms or flexible springs. Hole diameter is determined by the movement of these pads, which are held against the borehole wall by springs.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Typical Configuration on the Borehole </em>A schematic drawing of a typical borehole ( <a href='javascript:figurewin('../../asp/graphic.asp?code=417&order=0','0')'>Figure 1</a> ) shows that some formations cave considerably, causing enlarged holes. Other formations do not cave, and because of the presence of mudcake, the hole size may actually be reduced to less than bit size. Some formations (not shown here) may swell, causing reduction in hole size.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The primary cause of formation caving is the action of the drilling fluid, bit, and drillpipe. Most drilling muds, composed primarily of water, exert chemical action on shales (hydration of the shales), often causing them to disintegrate and slough into the hole. The amount and rate of this sloughing depend on the nature of the mud and shale. "Heaving" shales swell rather than disintegrate.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>If a fresh-water mud is used to drill a salt section, it dissolves salt until the mud becomes salt-saturated. The drilling fluid does not "react" with rock such as limestone, dolomite, and sandstone. If those formations are permeable, however, a mudcake will rapidly form ( <a href='javascript:figurewin('../../asp/graphic.asp?code=417&order=0','0')'>Figure 1</a> ). Mudcake character (density and thickness) varies with the mud used to drill the well, and its thickness is limited by erosion of the circulating drilling fluid.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>If/when shallow portions of the hole are drilled with water, loosely cemented sands encountered may cave.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The action of the bit is not very important, but if a thin sand is surrounded by shales that have caved, the bit probably knocks off part of the sand ledge with each round trip.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Action of the drillpipe against the side of the hole causes some enlargement even in sandstones and limestone. Though this enlargement may not be great enough to affect hole volume appreciably, it may cause keyseating and necessitate a fishing job. Formation "wear" by the drillpipe causes the hole to be noncylindrical, in which case a four-arm caliper will display the long and short axes of the hole.<br /></span></p><p><strong>Interpretation and Application of Caliper Logs <br /></strong></p><p style='text-align: justify'><em>C</em><span style='font-size:10pt'>aliper logs are usually recorded on vertical scales from 1 in. = 100 ft to 5 in. - 100 ft. The horizontal scale is selected to show a detailed picture of hole diameter and is usually in the order of 1 in. = 4 in. Because of the difference in scales, it is easy to get the impression from caliper logs that tremendous cavities are created. Keep in mind that when a normal borehole is plotted on the same horizontal and vertical scales, it is evident that it is quite "regular."</span><br /> </p><p><span style='font-size:10pt'>The primary uses of the caliper log are:</span><br /> </p><ul style='margin-left: 81pt'><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>to compute hole volume to determine the amount of cement needed to fill up to a certain depth</span><br /> </span></div></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>to determine hole diameter accurately for use in interpreting other logs</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>to locate permeable zones as evidenced by the presence of a filter cake</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Other applications of the caliper log include proper location of casing centralizers and packer seats for openhole drillstem tests.</span><br /> </span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Caliper logs are referred to as <em>borehole geometry logs </em>in conjunction with hole deviation and hole azimuth measurements. <a href='javascript:figurewin('../../asp/graphic.asp?code=418&order=0','0')'>Figure 1</a> is an example of such a log using a standard three-track presentation. The borehole orientation is displayed in track 1 while the two independent orthogonal caliper readings are recorded in track 2 with a standard scaling. The caliper data in track 3 show a reduced sensitivity, and are displayed together with the bit size and future casing size. This visual display, enhanced by the shading between the calipers and the bit size, quickly gives a clear impression of the borehole shape. Within the depth track, the total hole volume integration is recorded along the edge of track 1, and the cement volume (the difference between the total hole volume and future casing volume) is presented along the edge of track 2.</span><br /> </p><p><strong>Nuclear Magnetic Resonance <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Nuclear magnetic resonance logging measures the signal generated by hydrogen nuclei as they rotate (process) about the earth's magnetic field after a field that aligned them is shut off. The tool measures how many hydrogen nuclei stay aligned long enough to be measured and how long it takes to align them.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The signal reflects all the hydrogen nuclei except</span><br /> </p><ul style='margin-left: 81pt'><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>those in water in intimate contact with surfaces. The tool does not see the fluid in a shale and does not see the irreducible water in a sand. Thus, the fluid it does see is called free fluid. In a clean carbonate, even a very fine-grained one, the tool sees all the fluid. <br /></span></div></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>those in oil more viscous than about 500 Cp at reservoir temperature. Oil heavier than l4</span><span style='font-family:Symbol'></span><span style='font-size:10pt'>-l8</span><span style='font-family:Symbol'></span><span style='font-size:10pt'> API is usually not seen except at high temperatures.</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Nuclear magnetic resonance can be used for various purposes.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Identification of Permeable Formations </em>The free fluid index (FFI) presented on the log represents. the portion of total pore fluids free to flow. FFI is thus zero except where fluids in pores flow in response to a pressure gradient.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Reflection of Permeability Differences </em>Measurements enable prediction of sandstone permeability. Several empirical relations have been shown to reflect how permeability increases with increasing FFI, and time alignment of hydrogen nuclei (Tl). Each permeability representation depends on parameters determined from comparisons with core-measured permeability.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Recognition of Zones with Heavy Oil Containing Movable Water </em>The signal from very viscous oil decays so rapidly that it is difficult to detect it. Thus, these tools show movable water only and can be used to predict the response to injected steam.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Measurement of Residual Oil </em>Chemicals can be added to the mud in order to cause rapid decay of the signal from mud filtrate. A recording after invasion of such mud filtrate measures accurately the residual oil target for tertiary recovery.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Measurement of Carbonate Porosity </em>Total porosity in clean carbonates independent of whether they are limestone or dolomite.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Simplification of Log Interpretation in Lithologies Where Other Logs are Ambiguous </em>Potentially, the magnetic resonance logging can simplify log interpretation in diatomites, chalks, and other special lithologies.</span><br /> </p><p><strong>Borehole Gravimeter (BHGM) <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>By measuring the acceleration due to gravity, G, at two different stations in a well, the density of the slab of rock between these stations can be calculated. Since the variations in G due to rock density are very small, a very sensitive device is required. The nominal value of G at the surface of the earth is 980 cm/sec</span><sup>2</sup><span style='font-size:10pt'> or 980 gal. To be of practical use, a BHGM tool needs to measure microgals. Assuming such measurements can be made in an accurate and repeatable fashion, the average density of a layer of rock between two points in a well can be calculated. <a href='javascript:figurewin('../../asp/graphic.asp?code=420&order=0','0')'>Figure 1</a> illustrates the principle.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The further apart the two measurements are made, the greater the accuracy of the result calculated. For example, if the difference in G between two stations, <span style='font-family:Symbol'></span>G, is measured to an accuracy of 7 microgals, then the corresponding accuracy for the calculated density of the layer of rock encompassed between those two stations is 0.028 gm/cc if the spacing is 10 ft, but 0.014 gm/cc if the spacing is 20 ft. This interplay of tool accuracy (sensitivity), station spacing, and detectable density variation is illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=420&order=1','1')'>Figure 2</a> .</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The volume of rock investigated by BHGM surveys is a function of the spacing between stations. Short spacing measurements investigate small rock volumes, longer measurements larger volumes. <a href='javascript:figurewin('../../asp/graphic.asp?code=420&order=2','2')'>Figure 3</a> illustrates this concept. If measurements are made at the top and bottom of a slab of formation 100 ft thick, 90% of the measured <span style='font-family:Symbol'></span>G effect will come from within an annulus round the borehole of 500 ft radius. For a 30 ft station difference, the 90% response is from within a radius of 150 ft. A rough rule of thumb is that the BHGM "reads out" to five times the spacing between stations.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>At all events the tool investigates a very large volume of rock compared to a conventional formation density tool, which reads a few inches at most into the formation.</span><br /> </p><p><span style='font-size:10pt'>There are currently two main applications for the BHGM:</span><br /> </p><ul style='margin-left: 81pt'><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>obtaining formation density in completed wells not logged with a modern logging suite <br /></span></div><p style='text-align: justify'><span style='font-family:Symbol'></span><span style='font-size:10pt'>detecting lithology, porosity, and fluid changes in the formation some distance from the borehole</span><br /> </p></li></ul><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>An example of the first application is the detection of gas zones in an old well that has only an electric log. At the time these wells were logged and completed, gas production was not an economic proposition. Now that it is, the question remains of how to distinguish high-resistivity zones seen on the old ES log that are gas-bearing from low-porosity tight zones that have the same high resistivity. A BHGM survey can determine formation density over 10 to 20 ft intervals. Gas-bearing zones are likely to show densities closer to 2.0 gm/cc than the 2.5 gm/cc or more shown in tight zones.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>An example of the second application is the detection of better porosity or gas some distance from an otherwise dry well. (The BHGM has been particularly successful in the Niagaran Reef plays in Michigan.) If the density distant from the borehole is calculated to be less than the density indicated by the conventional density log, then the well may be fractured over the more attractive gas-bearing or higher porosity zones.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Two tools are commercially available. They are the vibrating string type and the Lacoste-Romberg zero-length spring type. The Lacoste-Romberg device is the one used most frequently, due to its superior accuracy, repeatability, and temperature rating. <a href='javascript:figurewin('../../asp/graphic.asp?code=420&order=3','3')'>Figure 4</a> illustrates the principal components of this device.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=420&order=4','4')'><span style='font-size:10pt'>Figure 5</span></a><span style='font-size:10pt'> illustrates both an electric log and BHGM survey in a Gulf Coast Miocene sand/shale series. Of interest are the two high-resistivity kicks seen at 2735-2750 ft and 2765-2780 ft. Either could be hydrocarbon-bearing or tight. The BHGM survey successfully predicted gas production from the upper sand from the calculated density of 2.08 gm/cc in contrast to the 2.38 gm/cc density in the lower sand. The well was perforated in the upper sand for an absolute open-flow potential (AOF) of 1.7 MMscf/D.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=420&order=5','5')'><span style='font-size:10pt'>Figure 6</span></a><span style='font-size:10pt'> illustrates a carbonate well in which a featureless zone (6732-6750 ft) on the formation-density-compensated (FDC) log was successfully completed for 1.5 MMscf/D because of the disparity between the BHGM density of 2.58 gm/cc and the FDC density of 2.72 gm/cc.<br /></span></p><p style='text-align: justify'> <br /> </p><p><strong>Borehole Televiewer (BHTV) <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The BHTV is an acoustic device that scans the surface of the wellbore or casing by rotating an acoustic source (transducer) in the horizontal plane while the tool is moved vertically along the wellbore axis ( <a href='javascript:figurewin('../../asp/graphic.asp?code=421&order=0','0')'>Figure 1</a> ). The amplitude and/or travel time of the acoustic signal reflected from the borehole or casing wall is displayed as a photograph of the section logged. With the help of a flux gate compass, an oriented acoustic picture of the inside of the wellbore is provided as if it were split vertically along the north axis and laid flat.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The acoustic picture is presented in shades of gray and is a record of the amount of acoustic energy reflected from the borehole wall. A smooth surface reflects better than a rough one, a hard surface better than a soft, and a normal surface produces larger reflections than an oblique or slanted surface.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>When a smooth, normal borehole wall is scanned, maximum energy is reflected, and the resulting image is a series of bright lines. However, when a feature such as a fracture with its attendant discontinuities is surveyed, a minimum amount of energy is reflected, and the feature appears as a dark line (dark represents reduced reflected energy).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In addition to fractures, features such as vugs, bedding planes, and changes in lithology, as well as perforations, ruptures, or pits in casing can be seen on the televiewer log.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In openhole, the BHTV is used to detect and measure the dip of fractures and bedding planes. <a href='javascript:figurewin('../../asp/graphic.asp?code=421&order=1','1')'>Figure 2</a> is an isometric sketch of a wellbore intersected by a nonvertical fracture or bedding plane and a corresponding BHTV log. To determine dip, one merely finds the minimum of the sinusoid (indicated by the arrow) and reads the direction from the azimuth scale at the bottom of the log. Dip angle is determined by measuring the peak-to-peak amplitude, h, of the sinusoid and combining it with the diameter, d, of the wellbore:</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>dip angle = tan-1(h/d)</span><br /> </span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=421&order=2','2')'><span style='font-size:10pt'>Figure 3</span></a><span style='font-size:10pt'> is a view of a high-angle fracture or bedding plane intersecting the wellbore with north dip. If a high-angle fracture intersects the wellbore with west dip, the BHTV anomaly is a full sine wave with a minimum to the west and a maximum peak occurring to the east, as shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=421&order=3','3')'>Figure 4</a> . In the case of a fracture or bedding plane dipping to the east, the minimum would be to the east and the maximum to the west.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=421&order=4','4')'><span style='font-size:10pt'>Figure 5</span></a><span style='font-size:10pt'> is an isometric view of a vertical fracture intersecting the wellbore in an east-west direction and a corresponding BHTV log. The fracture appears as two vertical dark lines 1800 apart.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In a cased hole the BHTV may be used to detect perforations ( <a href='javascript:figurewin('../../asp/graphic.asp?code=421&order=5','5')'>Figure 6</a> ), or evaluate damaged casing ( <a href='javascript:figurewin('../../asp/graphic.asp?code=421&order=6','6')'>Figure 7</a> ).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The BHTV can be run in any gas-free liquid such as fresh water, saturated brine, crude oil, or drilling mud. Operating limits for various mud weights and hole sizes may be determined from published charts.</span><br /> </p><p style='text-align: justify'> <br /></p><p style='text-align: justify'><span style='font-size:10pt'>Prerequisites for a top-quality log are a centered tool in a round hole. The log shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=421&order=7','7')'>Figure 8</a> meets these requirements. There is a dark area on the left side of the log caused by the tool being slightly off center. Otherwise, the symmetrical intensity from left to right indicates a centered tool in a round hole.</span><br /> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-89293131881639116462008-11-20T22:02:00.001-08:002008-11-20T22:02:01.659-08:00Well Logging Tools & Techniques (Porosity Logs)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Porosity Logs <br /></span></h2></p><p><strong>Definitions of Porosity and Effective Porosity <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The porosity of a formation is defined as the volume of the pore space divided by the volume of the rock containing the pore space. This definition of porosity ignores the question of whether the pores are interconnected or not. Swiss cheese, though quite porous, is of very low permeability since the void spaces are not <em>interconnected. </em>Intergranular porosity is effective porosity. Pores blocked by clay particles, silt, and so<strong><br /> </strong>forth, are ineffective. Thus, a preferred definition gives total porosity (<span style='font-family:Symbol'><sub></sub></span> as the volume of the pores divided by the volume of rock, and effective porosity (<span style='font-family:Symbol'></span><sub>e</sub>) as the volume of the interconnected pores divided by the volume of rock. <a href='javascript:figurewin('../../asp/graphic.asp?code=409&order=0','0')'>Figure 1</a> illustrates this concept.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In a laboratory, porosity can be measured in a number of ways. One<strong><br /> </strong>of the simplest is to weigh a sample of rock when it is 100% saturated with water, then remove all the water and reweigh it. Provided the density of the rock matrix (or the volume of the rock sample) is known, the porosity can be found.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>On location, the density logging tool provides an in-situ bulk rock density measurement that, if properly rescaled, serves as a porosity trace.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>However, measurement of the density of a rock is not the only method available for determining formation porosity. Other methods include neutron and acoustic logging, which we will look at shortly. Whatever logging device is used, we should always remember that porosity devices are sensitive to both rock matrix and to the fluid filling the pore space. Thus, all porosity tool measurements reflect not only porosity, but also the type of rock, the clay content, and the fluid type. No tool has been invented to date that reads just porosity. This limitation of conventional porosity devices is a blessing in disguise, since it allows the analyst to derive more than just porosity from a combination of different porosity tools.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Clean (shale- and clay-free) water-bearing formations of known lithology represent the simplest environments for porosity determination, since the effects of mixed lithology, clay, and hydrocarbons do not confuse the issue. However, before discussing these analysis techniques, let us review the scales used on porosity logs and the procedures and techniques to be used in reading them.</span><br /> </p><p><span style='font-size:10pt'>Three things must be determined before reading the log:</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>the type of curve recorded, e.g., bulk density, r<sub>b</sub>, or apparent porosity, r<sub>D</sub> and, if it is a porosity curve, the lithology used for the porosity calculations <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>the scale, e.g., 45% to -15% or 60% to 0%, on a neutron log</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the actual lithology in the well and the nature of the fluid occupying the pore space</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Once all three are determined, true porosity can be found for those intervals where the particular porosity device under consideration can reasonably be expected to work. For instance, with a pad contact device such as the density tool, no readings should be attempted in washed-out zones.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Porosity is the volume fraction of pore space in the rock and is expressed as a fraction of the bulk volume of the rock. The normal convention in reservoir engineering is to express porosities in percentage units; e.g., a porosity of 0.3 is referred to as 30% porosity. However, another term frequently used is "porosity unit," or P.U. Using "unit" rather than percentage avoids a lot of confusion, as, for example, when comparing a 20 P.U. sandstone with a 25 P.U. sandstone. The latter is 5 P.U. higher than the former. This negates the confusion caused by saying one is 5% better than the other or 25% better than the other, depending on which way the difference is expressed.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Frequently a combination of porosity devices is available that can be run into the wellbore together. Such combination tools often can define porosity better than any single device. The most commonly available pair is the density/neutron combination.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>When working with well logs generated by such a tool combination, check the log scales carefully before jumping to conclusions. More confusion may exist about density/neutron combinations and their presentations than about any other log on the market today.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Formation Density Tool<br /></strong></p><p><strong>Density Log<br /></strong></p><p><span style='font-size:10pt'>Density is one of the most important pieces of data in formation evaluation. In the majority of the wells drilled, density is the primary indicator of porosity. In combination with other measurements, it may also be used to indicate lithology and formation fluid type. <br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A conventional compensated density log is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=0','0')'>Figure 1</a> , with the value of formation bulk density (<span style='font-family:Symbol'></span><sub>e</sub>)in tracks 2 and 3. The most frequently used scales are a range of 2.0 to 3.0 gm/cc or 1.95 to 2.95 gm/cc across two tracks. A correction curve, <span style='font-family:Symbol'></span> , is sometimes displayed in track 3 and less frequently in track 2. The gamma ray and caliper curves usually appear in track 1.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The tool can be used by itself or in combination with other tools, such as the compensated neutron tool. The formation density skid device ( <a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=1','1')'>Figure 2</a> ) carries a gamma ray source and two detectors, referred to as the short-spacing and long-spacing detectors. This tool is a pad-type tool; i.e., the skid device must ride against the side of the borehole to measure accurately.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The source continuously emits gamma rays. These pass through the mudcake and enter the formation, where they progressively lose energy until they are either completely absorbed by the rock matrix or they return to one or the other of the two gamma ray detectors in the tool. Dense formations absorb many gamma rays, while low-density formations absorb fewer. Thus, high count rates at the detectors indicate low-density formations, whereas low count rates at the detectors indicate high-density formations.</span><br /> </p><p><span style='font-size:10pt'>Gamma rays can react with matter in three distinct manners:</span><br /> </p><ul style='margin-left: 45pt'><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Photoelectric effect, where a gamma ray collides with an electron, is absorbed, and transfers all of its energy to the electron. In this case, the electron is ejected from the atom.</span><br /> </span></div></li></ul><p style='text-align: justify'><span style='font-size:10pt'><span style='font-family:Symbol'></span>Compton scattering, where a gamma ray collides with an electron orbiting some nucleus. In this case, the electron is ejected from its orbit and the</span><br /> <span style='font-size:10pt'>incident gamma ray loses energy.</span><br /> </p><p style='text-align: justify; margin-left: 36pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>Pair production, where a gamma ray interacts with an atom to produce an electron and positron. These will later recombine to form another gamma ray.</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>We have already seen that the photoelectric interaction can be monitored to find the lithology-related parameter, P<sub>e</sub>. For the conventional density measurement only the Compton scattering of gamma rays is of interest. (Conventional logging sources do not emit gamma rays with sufficient energies to induce pair production.)<br /></span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>Since the density of a mixture of components is a linear function of the densities of its individual constituents, it is a simple matter to calculate the porosity of a porous rock. Consider the bulk volume model of a clean formation with water-filled pore space ( <a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=2','2')'>Figure 3</a> ).<br /></span></p><p><span style='font-size:10pt'>Unit volume of porous rock consists of a fraction <span style='font-family:Symbol'></span>made up of water and a fraction (1 -<span style='font-family:Symbol'></span>) made up of solid rock matrix.</span><br /> </p><p><span style='font-size:10pt'>The bulk density of the sample can be written as:</span><br /> </p><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>b + </sub><span style='font-family:Symbol'></span><sub>ma</sub> (1 +<span style='font-family:Symbol'></span>) + <span style='font-family:Symbol'></span><sub>f </sub><span style='font-family:Symbol'></span></span><br /> </p><p><span style='font-size:10pt'>where <span style='font-family:Symbol'></span><sub>ma </sub>refers to the matrix density and<sub><br /> </sub><span style='font-family:Symbol'></span><sub>f</sub> refers to the fluid density. Simple rearrangement of the terms leads to an expression for porosity given by:</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Symbol'></span><sub>D = (</sub><span style='font-family:Symbol'></span><sub>ma - </sub><span style='font-family:Symbol'></span><sub>b)/(</sub><span style='font-family:Symbol'></span><sub>ma - </sub><span style='font-family:Symbol'></span><sub>f)</sub><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The same concept can be illustrated graphically as in<sub><br /> <a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=3','3')'/></sub>Figure 4 , where <span style='font-family:Symbol'></span><sub>b </sub>is plotted against porosity. Note that points falling on the line connecting the matrix point (<span style='font-family:Symbol'></span><sub>ma</sub>, <span style='font-family:Symbol'></span>= 0%) and the water point (<span style='font-family:Symbol'></span><sub>f</sub> ,<span style='font-family:Symbol'></span>= 100%) represent all possible cases extending from zero-porosity rock matrix to 100% porosity. Any intermediate value of <span style='font-family:Symbol'></span><sub>b</sub> corresponds to some porosity <span style='font-family:Symbol'></span>.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The matrix density in normal reservoir rocks varies between 2.87 gm/cc (dolomite) and 2.65 gm/cc (sandstone). The fluid density of normal brines ranges from 1 to 1.1 gm/cc and is controlled by the properties of the invading mud filtrate in permeable zones. Porosity derived from a density log is referred to as <span style='font-family:Symbol'></span><sub>D.</sub></span><br /> </p><p style='text-align: justify'><span style='font-size:14pt'><sub>The density log gives reliable porosity values, provided the borehole is smooth, the formation is shale-free, and the pore space does not contain gas. In shaly formations and/or gas-bearing zones, it is necessary to refine the interpretative model to make allowances for these additions or substitutions to the rock system.</sub><br /> </span></p><p><strong>Introduction</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The density of a formation is one of the most important pieces of data in formation evaluation. It is used in the majority of the wells drilled as the primary indicator of porosity. In combination with other measurements, it may also be used to indicate lithology and formation fluid type.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A conventional compensated density log is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=4','4')'>Figure 5</a> , with the value of formation bulk density (<span style='font-family:Symbol'></span><sub>b</sub>)in Tracks II and III. The most frequently used scales are a range of 2.0 to 3.0 gm/cc ore 1.95 to 2.95 gm/cc across two tracks. A correction curve,<sub><br /> </sub><span style='font-family:Symbol'></span> sometimes displayed in Track III, is less frequent in Track II. The gamma-ray and caliper curves, if run, are usually plotted in Track I.</span><br /> </p><p> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The tool can be used by itself or in combination with other tools, such as the compensated neutron tool. <a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=5','5')'>Figure 6</a> illustrates the articulated "skid" device; it carries a gamma ray source and two detectors. This tool is a pad-type tool; i.e., the skid is forced by the tool against the side of the borehole.</span><br /> </p><p><span style='font-family:Times'><strong>Operating Principle</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Gamma rays, continuously emitted from the source, pass through the mudcake and enter the formation. Here they progressively lose energy until they are either completely absorbed by the rock matrix or return to one of the two gamma ray detectors in the tool. Dense formations absorb many gamma rays, while low-density formations absorb fewer gamma rays. High count rates at the detectors indicate low-density formations, and vice versa. Fore example, in a thick anhydrite bed the detector count rates are very low, while in a highly washed-out zone of the hole, simulating an extremely low-density formation, the count rate at the detectors is extremely high.</span><br /> </p><p><span style='font-size:10pt'>Gamma rays can interact with matter via three distinct mechanisms:</span><br /> </p><p style='text-align: justify; margin-left: 36pt'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>1. Compton scattering: gamma rays collide with electrons orbiting some nucleus. Electrons are ejected from orbit and the incident gamma rays lose energy.</span><br /> </span></p><p style='text-align: justify; margin-left: 36pt'><span style='font-size:10pt'>2. Photoelectric effect: gamma rays collide with electrons and lose all energy. Electrons are ejected from the atom.</span><br /> </p><p style='text-align: justify; margin-left: 36pt'><span style='font-size:10pt'>3. Pair production: gamma rays interact with atoms to produce electrons and positrons; these later recombine to form two 0.511 MeV gamma rays, which depart in opposite directions.</span><br /> </p><p> <br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=6','6')'><span style='font-family:Arial Unicode MS; font-size:10pt'>Figure 7</span></a><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'> illustrates the concept of the mass absorption coefficient. If an incident beam of gamma rays strikes a target of thickness x, its intensity is reduced on passing through the target in such a way that:</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Iout = Iin e-µx</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>where µ is the mass absorption coefficient. This coefficient µ is a function of both the type of material in the target and the type of interaction that takes place.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=7','7')'><span style='font-size:10pt'>Figure 8</span></a><span style='font-size:10pt'> shows µ as a function of incident gamma ray energy fore all three types of interaction. The conventional gamma ray source used in logging tools is made of cesium and the emitted gamma rays have an energy of 0.661 MeV. Referring to <a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=7','7')'>Figure 8</a> , it is obviously highly unlikely that any form of pair production will occur, since this type of interaction only occurs at energies higher than 2 ore 3 MeV.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The detectors used in conventional density tools have a practical lower limit to the gamma ray energy level they can detect. This lower limit is about 0.2 MeV. Thus, the operating range, shown on <a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=7','7')'>Figure 8</a> , is between the two vertical lines marking the energy range between the gamma rays emitted from the source and the limit of detection by the detectors. Compton scattering therefore becomes the most probable form of interaction that conventional density tools can monitor.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The net effect of gamma ray Compton scattering and absorption is that the count rate seen at the detector is logarithmically proportional to the formation density ( <a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=8','8')'>Figure 9</a> ):</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>log (count rate) = A + B • (formation density)</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Both near- and far-spacing detectors behave in this way, so that a plot of far versus near count rates also produces a straight line (<a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=9','9')'> Figure 10</a> ). Note that formation density increases as count rates decrease.</span><br /> </p><p> <br /> </p><p><span style='font-family:Times'><strong>Compensation</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A mudcake with a density different from that of the formation changes both the near and far count rates. <a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=10','10')'>Figure 11</a> shows where a plotted point falls if a formation with a bulk density of 2.7 gm/cc has an ever-increasing amount of mudcake of density 1.5 gm/cc placed between it and the tool. In an extreme case of "infinite" mudcake thickness, both detectors "see" only mudcake and read a value of 1.5 gm/cc.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The arc describing the locus of the points is referred to as a <em>rib</em>. The zero mudcake line is referred to as a <em>spine</em>. A complete set of spine and ribs can be drawn fore various thicknesses and densities of mudcakes (<a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=11','11')'> Figure 12</a> ). Note that ribs also extend to the left of the spine fore mudcakes having a density greater than the formation density; e.g., in barite muds.</span><br /> </p><p style='text-align: justify'><br /> </p><p> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The surface equipment associated with the density tool computes the position of the point on the spine and ribs chart, then moves the point along the rib to intercept the spine. At this point, a corrected value of is recorded fore the log. The value of <span style='font-family:Symbol'></span> is calculated as the difference between <span style='font-family:Symbol'></span> from the long spacing and <span style='font-family:Symbol'></span><sub>cor. Thus, </sub><span style='font-family:Symbol'></span> is positive in light muds and negative in heavy muds.</span><br /> </p><p><span style='font-family:Times'><strong>Electron Density</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Since Compton scattering is an interaction between gamma rays and electrons, the density actually measured is the electron density, <span style='font-family:Symbol'></span><sub>e</sub>, not the bulk density, <span style='font-family:Symbol'></span><sub>b</sub></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Since <span style='font-family:Symbol'></span><sub>e</sub> is not exactly equal to <span style='font-family:Symbol'></span>b fore all elements, a special calibration makes the tool read correctly in fresh-water-filled limestone.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>As a result of the calibration technique used, not all substances commonly found in rock formations are read correctly by the density tool. <a href='javascript:figurewin('../../asp/graphic.asp?code=410&order=12','12')'>Table 1</a> gives a listing of density properties of various compounds frequently found in subsurface formations.</span><br /> </p><p><br /> </p><p style='text-align: justify'><strong>Density Log Corrections, Quality Control<br /></strong></p><p><strong>Density Log Quality Control<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Practical calibration of the density tool is accomplished by a series of standards. The primary standard is made by using laboratory formations. Since these cannot be easily transported, a set of secondary standards is available at logging service company bases in the form of aluminum, magnesium, and/ore sulfur blocks of accurately known density and geometry. These blocks, which weigh up to 400 pounds, are not easily transportable either. So a field calibrator containing two small gamma ray sources is used to reproduce the same count rates as those found in the blocks.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The wellsite calibration should be performed before and after each log is run; the shop calibration should be run at least every 60 days, and a copy of it attached to the main log. It is important to note that the field calibrator, the skid with the detectors, and the source form a matched set. If any of the three does not match the serial numbers on the master calibration, the log should be rejected.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Natural benchmarks fore checking the validity of a density log are salt, which has a <span style='font-family:Symbol'></span><sub>a</sub> of 2.032 gm/cc, and anhydrite, which has a <span style='font-family:Symbol'></span><sub>a</sub> of 2.977 gm/cc. These minerals may not appear in the wellbore being logged; even if they do, they may not be 100% pure, and should be used with caution. In general, density logs are either well calibrated (and therefore correct) or very noticeably bed.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Apart from the natural benchmarks already discussed, the next best quality check is a review of the <span style='font-family:Symbol'></span> curve. If the short-spacing detector fails, then the whole compensation mechanism is thrown out of kilter. So if <span style='font-family:Symbol'></span> is roughly within the limits of ± 0.05 gm/cc, the log may be assumed to be correct. If in light muds the <span style='font-family:Symbol'></span> is negative, however, something is wrong. Likewise, positive values for <span style='font-family:Symbol'></span> in heavy (barite) muds is a danger signal.<br /></span></p><p style='text-align: justify'><strong>Neutron Logs: Introduction<br /></strong></p><p><strong>Neutron Log<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Neutron porosity devices respond to the hydrogen content of the formation. In clean reservoirs, hydrogen is present in liquid-filled pore space. Neutron logs thus measure the amount of liquid-filled porosity. Neutron logging devices contain a neutron source that continuously emits energetic (fast) neutrons, and one or more detectors. Neutrons collide with formation nuclei, causing them to lose energy. After a sufficient number of collisions, the neutrons reach a lower energy state (epithermal) and continue to lose energy until they reach a still lower energy state (thermal), whereupon they are captured by formation nuclei.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>When a nucleus captures a thermal neutron, a gamma ray is emitted to dissipate the excess energy. Porosity (or hydrogen index) can be determined by measuring epithermal or thermal neutron populations or capturing gamma rays or any combination thereof. Neutron logs based on the detection of epithermal neutrons are referred to as sidewall neutron logs. The compensated neutron log, in widespread use today, uses two thermal neutron detectors to reduce borehole effects. Single thermal neutron detector tools, of poorer quality, are available in many areas of the world. Captured gamma rays are used for porosity determination and logs of this type are referred to as neutron-gamma tools. The responses of these devices are dependent upon such variables as porosity, lithology, hole size, hole rugosity, fluid type, and temperature. Compensated and sidewall logs have corrections included in the electronic panels to account for some of these variables, while neutron-gamma logs require corrections from departure curves.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The main applications for neutron tools are three: determination of porosity, formation fluid type, and (in combination with other devices) lithology.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Depending on the device, these applications may be made in either open or cased holes. <a href='javascript:figurewin('../../asp/graphic.asp?code=412&order=0','0')'>Figure 1</a> illustrates a generalized neutron logging tool. Historically, a number of devices have been used that rely on one portion or another of a neutron's progress from a chemical source to eventual capture by formation nuclei.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In addition to porosity, neutron tools respond to other formation parameters and certain borehole environmental effects. Parameters that affect neutron devices include lithology and formation fluid type (e.g., gas). Environmental factors that affect neutron logs include borehole fluid type, density and salinity, borehole size, mudcake, standoff, temperature, and pressure. Modern neutron tools incorporate corrections to some extent for many of these environmental factors, but older (neutron-gamma type) tools do not. Consult service company correction charts for each tool used to assess the magnitude of these effects.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Neutron gamma tools may infrequently be used for cased-hole correlation logging and perforation depth control. Sidewall neutron tools are still available from some service companies, but have mostly been replaced with compensated neutron tools. Compensated neutron tools are widely used and frequently run in combination with compensated density tools. Dual epithermal neutron tools are in the prototype stage and may become more widely available in the future.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Choice of neutron tool should be dictated by well conditions and compatibility with other required services.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=412&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> shows a schematic of a CNL tool eccentered in a borehole. There are two typical tool string arrangements, one (combined with density and gamma ray) for openhole and one (combined with a collar locator) for cased hole.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Compensated neutron tools are run on a matrix setting chosen by the logging engineer or the company witness. If the actual lithology coincides with the chosen matrix setting, porosities may be read directly from the log. However, this is seldom the case. If the matrix is something other than that used in running the log, the porosity reading from the log will not be correct. Also, in most instances, the lithology is not known prior to logging the well. Therefore, a standard matrix setting is normally used. <a href='javascript:figurewin('../../asp/graphic.asp?code=412&order=2','2')'>Figure 3</a> shows a combination compensated neutron/formation density log.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A convenient standard for the neutron is the <em>neutron porosity index (limestone). </em>This is the same value that the tool would have read had it been recorded on a limestone scale. <a href='javascript:figurewin('../../asp/graphic.asp?code=412&order=3','3')'>Figure 4</a> plots the porosity measured by the neutron tool using a limestone, water-filled matrix against the true porosity for the indicated lines of constant lithology. This chart can be used to determine the true porosity if the actual lithology is known. To obtain the true porosity, enter the measured porosity value on the x-axis, proceed vertically to the appropriate lithology line, then read the true porosity to the left, on the y-axis.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>As in the case of density logs, compensated neutron logs may be used as direct indicators of porosity only in clean, liquid-filled, porous formations. The response in shaly or gas-bearing formations calls for special handling.<br /></span></p><p><strong>Introduction<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The neutron is a fundamental particle found in the nucleus of all atoms except that of hydrogen, which contains only a proton. Neutrons have approximately the same mass as protons, but carry no electrical charge. Their small size and electrical neutrality make neutrons ideal projectiles for penetrating matter: they pass through brick walls and steel plates with great ease. It is logical that neutrons have found their niche in the logging tool arsenal. Over the years, a number of logging tools have appeared that rely on the neutron's interaction with matter. To fully understand these different tools, let us review certain aspects of nuclear physics.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Two categories of neutron sources are found in the logging industry: chemical sources and pulsed sources. chemical sources are composed of two elements in intimate contact that react together to continuously emit neutrons, usually plutonium/ beryllium ore americium/beryllium. Such sources need to be heavily shielded when not in use.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Pulsed sources incorporate a neutron accelerator and a target, and can be activated by simply switching on the accelerator. These are relatively harmless when not in use. Currently, the pulsed neutron sources are used for pulsed neutron logging and in tools that measure inelastic neutron collisions (carbon/ oxygen-type logs).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Near the chemical sources, "fast" neutrons are found with nearly all their initial energy of several ( ~ 4) MeV. These neutrons interact with the nuclei of other atoms and lose energy with each collision. Eventually, fast neutrons reach an intermediate energy level, where they have an energy of only a few (0.2 to 1.0) eV; in that state they are called epithermal neutrons. After yet more interaction, a neutron may be slowed down to a point at which it has the same energy as the surrounding matter; this energy level is directly dependent on the absolute temperature. Such neutrons are called thermal neutrons, and have energies in the range of 0.025 eV. When a neutron reaches thermal energy it is captured by a nucleus that emits a gamma ray. This gamma ray is called a capture gamma ray.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>All conventional neutron logging tools, with the exception of pulsed neutron tools, have operating principles based on the spatial distribution of the neutrons ore the capture gamma rays they produce. Pulsed neutron logs assess distribution as a function of time.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Early neutron tools, known as GNT-type tools, consisted of a chemical source and a single detector of neutron capture gamma rays. This tool, a qualitative indicator of porosity, was badly affected by hole size and the salinity of the borehole fluid and formation water.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In an attempt to cure these inherent problems, the sidewall neutron porosity (SNP) tool was introduced in the early 1960s. It relied on a single detector of epithermal neutrons. This tool overcame general salinity problems, but had its own unique problem in that mudcake could affect its readings, and estimation of the magnitude of the error was not always easy.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The compensated neutron log (CNL) was then introduced in the late 1960s with two detectors of thermal neutrons. It solved most of the defects of the previous tools, yet it, too, encountered problems with formations containing thermal neutron absorbers. The present state-of-the-art is a CNL-type tool with dual detectors of epithermal neutrons that may solve the problem of thermal neutron absorbers. <a href='javascript:figurewin('../../asp/graphic.asp?code=412&order=4','4')'>Figure 5</a> illustrates a generalized neutron logging tool.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The complete solution to the problem of neutron scattering and capture is extremely complex. The ability of a nucleus to slow down ore capture a neutron is measured by its cross section. Cross sections for slowing down or capturing neutrons vary with different elements and with neutron energy.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Two elements, hydrogen and chlorine, dominate the behavior of all neutron tools. Hydrogen, being the element with a single proton fore a nucleus, provides the best material for slowing down a neutron. Simple mechanics reveals that when two balls collide, the maximum energy loss occurs when the two balls are of equal mass. Thus, the equal mass of hydrogen's neutron and proton account for its prodigious power to slow down neutrons.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Chlorine has a large capture cross section for thermal neutrons, absorbing them a hundred times faster than most other elements. After accounting for the relative abundance of all the elements and their slowing down cross sections and capture cross sections, it transpires that a neutron need collide with a hydrogen nucleus an average of 18 times to reach thermal energy. Once a neutron does reach thermal energy, it is very likely to be absorbed by a chlorine nucleus.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>This explains why the original GNT tools had such a dependence on fluid salinity. A few parts per million of sodium chloride in the mud ore the formation water could alter their response dramatically. It also explains why the SNP was such an improvement over GNT. The tool was completely blind to capture gamma rays, since it only detected epithermal neutrons. The CNL tools theoretically are just as blind to salinity effects, since they, too, ignore the capture gamma rays from chlorine. But small additions of boron or cadmium in the formation can seriously affect the distribution of thermal neutrons.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Compensated Neutron Tool<br /></strong></p><p><span style='font-family:Arial Unicode MS'><strong>The Compensated Neutron Tool (CM)</strong><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>The compensated neutron tool measures a neutron porosity index which relates to the porosity of the formation only if the lithology and formation fluid content are known. Conventional stacking arrangements are shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=413&order=0','0')'>Figure 1</a> . The tool consists of a chemical neutron source and two detectors of thermal neutrons ( <a href='javascript:figurewin('../../asp/graphic.asp?code=413&order=1','1')'>Figure 2</a> ). It is run eccentered with the source, with detectors forced against the borehole wall by means of a bow spring.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Conventional compensated neutron tools can be run equally well in open ore cased, liquid-filled holes. In an empty hole (gasfilled), they do not work and epithermal neutron tools are required. It is normal practice to run these tools in combination with the density and gamma ray tools.</span><br /> </p><p style='text-align: justify'> <br /> </p><p><strong>CNL operating Principle</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>To properly understand the operation of the CNL logging tool, the distribution of thermal neutrons moving away from the source must be investigated. The thermal neutron flux is defined as the number of thermal neutrons crossing unit area in unit time. This flux is controlled by the hydrogen content of the formation. Hydrogen is found in the water molecules filling the pore space (assuming the formation to be water bearing). Thus the hydrogen content of the formation is a direct indication of its porosity.</span><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=413&order=2','2')'><span style='font-size:10pt'>Figure 3</span></a><span style='font-size:10pt'> shows a plot for three different values of porosity of the thermal neutron flux as a function of the distance from the source. Note that the lines intersect at some distance from the source. At points closer to the source than the intersection, high thermal neutron flux means high porosity, but at points farther from the source, high thermal neutron flux indicates low porosity.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The absolute count rate is a poor indication of porosity: too many factors affect it. The actual count rate seen at any detector spacing from the source is a function not only of porosity, but also of such environmental factors as hole size, mud weight, and casing size and weight. Therefore, the CNL reading must be normalized to correct fore unknown environmental effects. This is done by taking two readings of thermal neutron flux at different spacings and using them to define the slope of the response line. This slope is relatively unaltered by environmental effects, although the position of the response line on the graph may vary in the "y" direction substantially. <a href='javascript:figurewin('../../asp/graphic.asp?code=413&order=3','3')'>Figure 4</a> illustrates this concept.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The primary measurement of the CNL tool is thus a ratio of two count rates. A high ratio indicates high porosity. The conversion of the ratio to a porosity value is based on laboratory experiments conducted with rock samples of known porosity. <a href='javascript:figurewin('../../asp/graphic.asp?code=413&order=4','4')'>Figure 5</a> shows the results of such experiments.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>To record porosity directly, a technique must be developed to convert the ratio into porosity. Fore example, a ratio of 2.0 could mean less than 10% porosity in dolomite or more than 20% in sandstone. The surface controls of the CNL tool allow the operator to select the matrix for which a porosity is required. Thus, if the operator chooses to run the CNL on a limestone setting, the conversion of ratio to porosity follows the middle of the three response lines. If, subsequently, the operator finds that the actual matrix is not limestone, then it is necessary to convert the apparent limestone porosity to some other matrix porosity. Correction charts, such as the one shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=413&order=5','5')'>Figure 6</a> , make this an easy task. This chart shows that the relationship between apparent limestone porosity and the porosity values for dolomite and sandstone is fairly uniform, with the exception of the very high and the very low porosity values. In midrange apparent limestone porosity values, certain approximate rules of thumb can be used.</span><br /> </p><p><strong>Environmental Corrections</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Corrections fore environmental factors are generally small and can be estimated from wireline service company charts. Of all corrections, the temperature and borehole size corrections are the largest.</span><br /> </p><p><strong>Depth of Investigation</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The depth of investigation of the </span><span style='font-family:Symbol'></span><span style='font-size:7pt'><sub>CNL</sub></span><span style='font-size:10pt'> depends on both the formation porosity and the salinity of the mud filtrate (invading water) and formation water. It can be expressed in terms of a geometric factor, J:</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Symbol'></span><sub>CNL</sub> = J (<span style='font-family:Symbol'></span><sub>CNL</sub>) Invaded + (1 - J) (<span style='font-family:Symbol'></span><sub>CNL</sub>)Uninvaded<br /></p><p style='text-align: justify'><span style='font-size:10pt'>J is a function of the depth of invasion measured from the borehole wall. <a href='javascript:figurewin('../../asp/graphic.asp?code=413&order=6','6')'>Figure 7</a> shows a typical set of J curves fore the MSFL, the density, and the neutron tools. Other J curves apply fore a different salinity mud filtrate. In <a href='javascript:figurewin('../../asp/graphic.asp?code=413&order=6','6')'>Figure 7</a> we see that none of the three tools can penetrate very deeply into the formation, but that the CNL has the greatest depth of investigation. It obtains 90% of its response from the first 10 in. of formation, compared to 6 in. for the FDC tool. Finally, depth of penetration is also a function of the porosity and the formation fluid.<br /></span></p><p style='text-align: justify'><br /> </p><p><strong>Matrix Settings and Lithology Pore and Fluid Effects</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>when choosing a neutron logging scale and matrix setting, it is good practice to remain consistent with the standard operating procedure fore the particular lithology expected in the well.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Sand/Shale Sequences The log should be run with a sandstone matrix setting and with a porosity scale of 60% to 0% left to right across Tracks II and III. If a density log is also recorded, then it should be scaled as an apparent sandstone porosity on the same scale ( <a href='javascript:figurewin('../../asp/graphic.asp?code=413&order=7','7')'>Figure 8</a> ).</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Carbonates/Evaporites/Generally Unknown Lithology The log should be run on a limestone matrix setting with a porosity scale of 45% to -15% left to right across Tracks II and III. If a density log is also recorded, then a scale of 1.95 to 2.95 gm/cc is required. An example is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=413&order=8','8')'>Figure 9</a> .</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The advantages of the compatible sandstone scales are that (1) gas can be easily spotted (neutron reads less than density) and (2) shales can be distinguished from sands (neutron reads more than density).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The advantage of the compatible limestone scales is that both curves coincide in limestone, and the neutron reads less than the density in sands and more than the density in dolomite and shales.</span><br /> </p><p><strong>Gas Effects</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Liquid hydrocarbons have hydrogen indexes close to that of water. Gas, however, usually has a considerably lower hydrogen concentration which varies with temperature and pressure. When gas is present near enough to the borehole to be within the tool's zone of investigation, a neutron log reads too low a porosity. This characteristic allows the neutron log to be used with other porosity logs to detect gas zones and identify gas-liquid contacts.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In a manner entirely analogous to the approach taken with the density tool, the neutron tool response in gas-bearing formations may be written as</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Symbol'></span>N = <span style='font-family:Symbol'></span><sub>Nma</sub> (1 - <span style='font-family:Symbol'></span>) + <span style='font-family:Symbol'></span><sub>Nmf</sub><br /> <span style='font-family:Symbol'></span><sub>Sxo</sub> + <span style='font-family:Symbol'></span><sub>Nhy</sub> (1 - <sub>Sxo</sub>)<br /></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where:</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-family:Symbol'></span><sub>Nma</sub> is the response to matrix (usually considered equal to zero), <br /></p><p style='margin-left: 36pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>Nmf</sub> is the response to mud filtrate (usually considered equal to 1), and</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>Nhy</sub> is the response to hydrocarbon</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Rearrangement of the terms gives</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-size:14pt'><span style='font-family:Symbol'></span> = (<span style='font-family:Symbol'></span><sub>N - </sub><span style='font-family:Symbol'></span><sub>Nma</sub>) / (<span style='font-family:Symbol'></span><sub>Nhy</sub> - <span style='font-family:Symbol'></span><sub>Nma</sub> + <sub>Sxo</sub> (<span style='font-family:Symbol'></span><sub>Nmf</sub> - <span style='font-family:Symbol'></span><sub>Nhy</sub>))<br /></span></p><p>If it is assumed that <span style='font-family:Symbol'></span><sub>Nma</sub> and <span style='font-family:Symbol'></span><br /> <sub>Nhy</sub> are very small and <span style='font-family:Symbol'></span><sub>Nmf</sub> is equal to 1, then <br /></p><p style='margin-left: 36pt'><span style='font-size:14pt'><span style='font-family:Symbol'></span> = <span style='font-family:Symbol'></span><sub>N / </sub>S<sub>xo</sub><br /> </span></p><p><span style='font-size:14pt'><sub>Since Sxo is always less than 1, it follows that </sub><span style='font-family:Symbol'></span><sub>N in hydrocarbon-bearing formations is always less than </sub><span style='font-family:Symbol'></span>. <br /></span></p><p><strong>Shale Effects</strong><br /> </p><p><span style='font-size:10pt'>In general, response of the neutron may be written in the form</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:14pt'><span style='font-family:Symbol'></span><sub>N = </sub><span style='font-family:Symbol'></span><sub>T + Vsh</sub><br /> <span style='font-family:Symbol'></span><sub>Nsh</sub><span style='font-family:Arial Unicode MS'><br /> </span></span></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where:</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-size:16pt'><span style='font-family:Symbol'></span><sub>N is the log reading</sub><br /> </span></p><p style='margin-left: 36pt'><span style='font-family:Symbol'></span><span style='font-size:7pt'><sub>T</sub></span><span style='font-size:10pt'> is the true porosity</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>V</span><span style='font-size:7pt'><sub>sh</sub></span><span style='font-size:10pt'> is the bulk volume of shale, and</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Symbol'></span><sub><span style='font-size:7pt'>Nsh</span><br /> </sub><span style='font-size:10pt'>is the response of the neutron tool in pure shale.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Typical values of </span><span style='font-family:Symbol'></span><span style='font-size:7pt'><sub>Nsh</sub></span><span style='font-size:10pt'> for compensated neutron tools lie between 20% and 45%. The value of V</span><span style='font-size:7pt'><sub>sh</sub></span><span style='font-size:10pt'> can be estimated from the gamma ray, SP, or neutron/density combinations. A corrected porosity may thus be found using<br /></span></p><p style='margin-left: 36pt'><span style='font-size:14pt'><span style='font-family:Symbol'></span><sub>T = </sub><span style='font-family:Symbol'></span><sub>N - Vsh</sub><br /> <span style='font-family:Symbol'></span><sub>Nsh</sub><span style='font-family:Arial Unicode MS'><br /> </span></span></p><p><br /> </p><p><strong>CNL Calibration and Quality Control <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The compensated neutron tools are calibrated in a large water-filled tank. This shop calibration is carried out at 60-day intervals. Practical quality control can be monitored by the usual criteria for all curves plus two natural benchmarks, which are salt (</span><span style='font-family:Symbol'></span><span style='font-size:7pt'><sub>NML</sub></span><span style='font-size:10pt'> = -0.3%) and anhydrite </span><span style='font-family:Symbol'></span><span style='font-size:7pt'><sub>NML</sub></span><span style='font-size:10pt'>= 0.2%). Apparent neutron and density porosities should agree in clean, water-bearing zones where lithology is known.</span><br /> </p><p style='text-align: justify'><strong>Accoustic Measurement:: Introduction<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION … !<br /></span></p><p style='text-align: justify'><strong>Accoustic Logging Tools<br /></strong></p><p><strong>Acoustic Log<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Acoustic tools measure the speed of elastic waves in subsurface formations. These measurements are used to calculate, measure, detect and/or estimate porosity, lithology, integrated travel time, true time scales, fractures, synthetic seismogram, the bond between casing, cement, formation, and formation overpressure.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A typical acoustic log is illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=0','0')'>Figure 1</a> . Curves recorded on acoustic logs may include the interval transit time, , in microseconds/ft (the reciprocal of speed), caliper, gamma ray and/or SP, and integrated travel time.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Tools currently available for making this measurement include the borehole-compensated tool, a slim tool version that can be run through tubing; and the long-spacing sonic tool.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>These tools include transmitter transducers that convert electrical energy into mechanical energy and receiver transducers that do the reverse. In its simplest form, the measurement is made in an uncompensated mode (<a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=1','1')'> Figure 2</a> ). The transmitter emits a small acoustic wave at time 0 that travels through the mud to the borehole wall, where it is refracted through the formation. Part of the energy traveling through the formation in turn is refracted back into the mud column and finds its way to the first receiver at time T1, and to the second receiver at time T2. The difference in the two times is referred to as and represents the time a compressional wave takes to travel through the formation a distance equal to the spacing between the two receivers. If this distance is one ft, then the formation travel time, , is expressed in microseconds/ft.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>This early form of sonic tool relied on the fact that the travel paths to the two receivers were equal in the mud. This was true in the case of a smooth borehole of unchanging size, but was not true if the borehole was of varying size or if the sonde tilted with respect to the axis of the borehole.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>These difficulties were overcome by the introduction of the borehole-compensated sonic tool. <a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=2','2')'>Figure 3</a> illustrates the principle of the compensated sonic tool.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Multiple transmitters and receivers are employed and two values of are measured and averaged. The net result of this system is the elimination of errors in due to sonde tilt and hole size variation. Even so, there are practical limits to the working range of the tool (e.g., in large holes).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The long-spacing sonic tool was introduced in an attempt to overcome borehole environmental problems. For example, when a shale formation is drilled, the shales exposed to the mud frequently change their properties by absorption of water from the drilling mud. The travel time for elastic waves therefore changes too. In order to read the travel time in the undisturbed formation further from the borehole, a longer transmitter-receiver spacing is required. Typically, a long-spacing sonic tool has a transmitter-receiver spacing of 8, 10, or 12 ft.<br /></span></p><p><span style='font-size:10pt'>Lengthening the spacing on a sonic device achieves two ends:<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A more valid acoustic log may be recorded in a bigger hole with a long-spacing device than with a conventionally spaced tool.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The zone investigated by the tool is deeper into the formation with a long-spacing device than with a conventionally spaced tool.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The long-spacing tools make their measurements in a "depth-derived" mode; i.e., the borehole compensation is actually achieved by memorizing travel times measured when the tool is at one depth and combining those with travel times recorded at a shallower depth when an alternate combination of transmitters and receivers is activated.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The fact that compressional waves travel faster through solid matrix material than through fluid is the basis for the method used to determine formation porosity from sonic logs. <a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=3','3')'>Figure 4</a> gives a schematic in which the pore space and the solid matrix have been separated for the purposes of illustration. If f is the time taken to travel through the pore space and ma is the time taken to travel through the matrix, the total travel time measured will be , and the porosity will be given by<br /></span></p><p><span style='font-size:10pt'>total travel time measured will be , and the porosity will be given by<br /></span></p><p style='margin-left: 36pt'> <span style='font-size:10pt'>= + (1 ) ma<br /></span></p><p><span style='font-size:10pt'>or<br /></span></p><p style='margin-left: 36pt'> <span style='font-size:10pt'><br /> </span></p><p><span style='font-size:10pt'>This is known as the Wyllie time average equation. Note that it is not an exact solution for porosity, but an approximation.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Matrix travel time depends on the matrix itself. <a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=4','4')'>Table 1</a> gives a partial listing of common matrix materials and fluids.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Fluid travel time is a function of the temperature, pressure, and salinity of a solution. A commonly used default value for<br /></span></p><p style='margin-left: 36pt'> <span style='font-size:10pt'>f is 189 µsec/ft.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Unconsolidated formations exhibit longer travel times than can be accounted for by the Wyllie time average equation. This discrepancy can be handled in two ways: conventionally, and by the Hunt transform. The conventional method merely adapts the Wyllie time average equation by introducing the factor B</span>cp,<span style='font-size:10pt'> such that<br /></span></p><p style='margin-left: 36pt'> <span style='font-size:10pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>where Bcp is some number greater than 1. This can be done by estimating B</span>cp<span style='font-size:10pt'> from the transit time in shales adjacent to the formation of interest. Then<br /></span></p><p style='margin-left: 36pt'> <span style='font-size:10pt'>B</span>cp<span style='font-size:10pt'> - shale/l00<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Thus, if, in a shallow sand-shale sequence, log shale is 130 µsec/ft, then a B</span>cp<span style='font-size:10pt'> of 130/100, or 1.3, should be used. The Hunt transform is based on empirical observations from sonic logs and porosity determinations from other means. <a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=5','5')'>Figure 5</a> shows the generalized form of the Hunt-Raymer transform compared to the Wyllie formula, and plots against porosity for sandstone, limestone, and dolomite. An acceptable equation relating porosity to for this transform is given by:<br /></span></p><p style='margin-left: 36pt'> <span style='font-size:10pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Note that fluid does not appear as a term in this equation. The assumption is that the fluid is liquid (not gas) and is built into the coefficient 1/( - ). In sandstones this coefficient is very close to 5/8.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Compaction effects manifest themselves on sonic logs as a decrease of with depth. This is particularly evident in shales. The deeper a shale is buried the more compact it becomes and the shorter the . In cases where there is no escape for the water in the shale, compaction ceases and over-pressure results. The shale at that depth is so anomalously high that it becomes an indicator of formation pressure. Obtaining readings on a sonic log in shales only and plotting these sh values against depth yields a "normal" gradient. Departures from this gradient indicate overpressure.<br /></span></p><p><span style='font-size:10pt'>To summarize, porosity, in clean formations of known lithology, may be determined from all three common "porosity" tools. Complex cases, where mixed lithology, clays, and light hydrocarbons coexist, call for a more sophisticated approach.<br /></span></p><p><strong>Acoustic Logging Tools<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Acoustic logging tools measure the formation properties <span style='font-family:Symbol'></span>t</span><span style='font-size:7pt'>c</span><span style='font-size:10pt'> and <span style='font-family:Symbol'></span>t</span><span style='font-size:7pt'>s</span><span style='font-size:10pt'> by the use of apparatus suspended in the mud column. Borehole compensation, long-spacing tools, and waveform recording may assist in this task.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A typical acoustic log is illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=6','6')'>Figure 6</a> . Curves recorded on this log are the interval transit time, <span style='font-family:Symbol'></span>t , in microseconds/ft (the reciprocal of speed), caliper, gamma ray and/or SP, and integrated travel time.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Tools available to make the measurement include borehole-compensated (BHC) tools, slimmer tool versions that can be run through tubing, and long-spacing acoustic tools. In seismic data gathering, a disturbance is made at the surface by explosives, for example, ore by use of an air gun in water. In acoustic logging, an acoustic pulse--produced by alternate expansions and contractions of a transducer--is emitted by a transmitter. A typical pulse of this sort is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=7','7')'>Figure 7</a> .<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>This transmitter pulse generates a compressional wave through the mud. Part of the acoustic energy traverses the mud, impinges on the borehole wall at the critical angle of incidence, passes along the formation close to the borehole wall, reenters the mud, and arrives at a receiver, where it is converted into an electrical signal ( <a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=8','8')'>Figure 8</a> ).<br /></span></p><p><br /> </p><p><br /> </p><p><strong>Operating Principle<br /></strong></p><p><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In its simplest form, measurement is ma e in an uncompensated mode (<a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=9','9')'> Figure 9</a> ). The transmitter emits compressional wave at time 0 that travels through the mud to the borehole wall, where it is refracted through the formation. Part of the energy traveling through the formation, in turn, is refracted back into the mud column and finds its way to the first receiver at time T</span><span style='font-family:Symbol; font-size:7pt'></span><span style='font-size:10pt'>, and to the second receiver at time T</span><span style='font-size:7pt'>2</span><span style='font-size:10pt'>. The difference in the two times is referred to as <span style='font-family:Symbol'></span>t and represents the time taken for a compressional wave to travel through the formation a distance equal to the spacing between the two receivers.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>This early form of acoustic tool relied on the fact that the travel paths to the two receivers were equal in the mud. This was true in the case of a smooth borehole of unchanging size, but was not true if the borehole was of varying size ore if the sonde tilted with respect to the axis of the borehole. These difficulties were partially overcome by the introduction of the BHC (borehole-compensated) acoustic tool. <a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=10','10')'>Figure 10</a> illustrates the principle of the BHC acoustic tool.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Schlumberger uses two transmitters and four receivers, and two values of <span style='font-family:Symbol'></span>t are measured and averaged. The net result of this system is the reduction of errors in <span style='font-family:Symbol'></span>t that are caused by sonde tilt and hole size variation. Even so, there are practical limits to the working range of the tool (e.g., hole size). In large boreholes, the time taken fore a compressional wave to travel from the transmitter to the formation, through the formation, and back through the mud to a receiver may exceed the time taken fore a direct transmission from the transmitter to the receiver through the mud. The critical factors in determining when this condition exists are the transmitter-receiver spacing, the hole size, and the travel time in the formation. With conventional borehole-compensated acoustic tools with a 3-ft spacing, the highest <span style='font-family:Symbol'></span>t formation that can be measured is 175 µs/ft in a 12-1/4 in. hole and 165 µs/ft in a 14-in. hole. This limitation is not serious if the formation is a reservoir rock with a <span style='font-family:Symbol'></span>t in the normal range of 40 to 140 µs/ft. It does become a serious defect if the rock is a shale of long transit time and the purpose of the log is to compute integrated travel time fore geophysical purposes.<br /></span></p><p><strong>Long-Spacing Acoustic Tool<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The long-spacing acoustic tool was introduced in an attempt to overcome environmental problems. When a shale formation is drilled, the shales exposed to the mud frequently change their properties by absorption of water from the drilling mud, so the travel time for elastic waves changes, too. In order to read the travel time in the undisturbed formation away from the borehole, a longer transmitter-receiver spacing is required. Typically, a long-spacing acoustic tool will have transmitter-receiver spacings of 8, 10, or 12 ft. <a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=11','11')'>Figure 11</a> shows a comparison of a conventional borehole-compensated acoustic log with a long-spacing acoustic log.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Lengthening the spacing on a acoustic device achieves two ends:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>A valid acoustic log may be recorded in a bigger hole with a long-spacing device than with a conventionally spaced tool.<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>The zone investigated by the tool is deeper into the formation with a long-spacing device than with a conventionally spaced tool.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Deeper investigation into the formation is of great value when logging through intervals of shale that have had their properties altered by the drilling process. Provided <span style='font-family:Symbol'></span>t of the formation in the undisturbed state is less than <span style='font-family:Symbol'></span>t of the formation in the altered state, the quickest route for a compressional wave is via the undisturbed formation, or "deep" in the formation. <a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=12','12')'>Figure 12</a> illustrates this effect.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The long-spacing tools make their measurements in a "depth-derived" mode; i.e., the borehole compensation is actually achieved by memorizing travel times measured when the tool is at one depth and combining those with travel times recorded at a shallower depth when an alternate combination of transmitters and receivers is activated. (The long-spaced sonde would be too long if used in the same configuration as the BHC tool.) Two transmitters spaced 2 ft apart are located 8 ft below a pair of receivers that are also 2 ft apart (<a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=13','13')'> Figure 13</a> ).<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Memorizing the first <span style='font-family:Symbol'></span>t reading and combining it with a second <span style='font-family:Symbol'></span>t reading (measured after the sonde has been pulled the appropriate distance farther along the borehole) compensates for the hole size changes.<br /></span></p><p><strong>Cycle Skipping and Noise<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The actual travel time measurement is determined at the first arrival peak. However, the tool's internal trigger mechanism for detecting this peak is subject to some errors. <a href='javascript:figurewin('../../asp/graphic.asp?code=415&order=14','14')'>Figure 14</a> illustrates two common problems. In the first, the bias level is set too high and the travel time is triggered by a later peak, causing an erroneously long time to be measured (this is known as cycle skipping). In the second, the bias is set too low and the travel time is triggered by noise, causing an erroneously short travel time.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In the BHC mode, it is not always possible to distinguish between cycle skipping and noise, since two measurements are effectively averaged by the tool.<br /></span></p><p><br /> </p><p><br /> </p><p><strong>Log Quality Control<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Acoustic logs are subject to very easily detected errors, such as cycle skips and noise. More subtle errors can be pinned down if the log is run through such marker beds as a salt (<span style='font-family:Symbol'></span>t=67 µsec/ft) anhydrite (<span style='font-family:Symbol'></span>t= 50 µsec/ft) ore into the casing. In the casing, it should read 56 µsec/ft, the travel time in steel, provided the casing is not bonded to a formation of high interval velocity such as a tight limestone.<br /></span></p><p style='text-align: justify'><strong>Accoustic Measurement: - Special Application<br /></strong></p><p><strong>Waveform Recording<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Waveforms may be recorded fore processing using the long-spaced acoustic tool. The longer spacing allows a larger time separation fore the compressional and shear wave arrivals.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The various transmitter-receiver combinations permit four waveforms to be recorded at 6-in. intervals. <a href='javascript:figurewin('../../asp/graphic.asp?code=416&order=0','0')'>Figure 1</a> illustrates composite waveforms received at the near and fare receivers when the upper transmitter is fired.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Digitization of the waveforms is normally made at a 5 <span style='font-family:Symbol'></span> sec sample interval for 512 samples, i.e., 2560 microseconds. A delay of 200 to 500 microseconds is an input parameter selected by the logging engineer.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Waveform recording considerably extends the range of applications of acoustic logging both in open holes and cased holes. The principal benefit is determination of the shear wave velocity of the formation.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The objective of waveform processing is to distinguish between the compressional and shear wave arrivals and to measure their interval transit times. Furthermore, in cased holes formation arrivals are usually distinct from casing arrivals, thereby permitting a viable acoustic measurement where previous acoustic devices would have been ineffective.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Data-processing methods used to extract shear wave arrival times are somewhat complex, and mirror seismic-processing methods; i.e., multiple waveforms are "stacked." Yet it is quite common to "see" shear arrivals on variable density displays of the sort shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=416&order=1','1')'>Figure 2</a> .<br /></span></p><p><br /> </p><p><br /> </p><p><strong>Vertical Seismic Profile (VSP)<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Another seismic application related to the acoustic log is the vertical seismic profile (VSP). By suspending a geophone in the wellbore and actuating an energy source at surface, reflections of compressional waves may be recorded. Some of these arrive at the geophone after being reflected from beds below the bottom of the well. Thus the VSP affords a method of looking ahead of the drill bit. A schematic of the setup to make a VSP survey is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=416&order=2','2')'>Figure 3</a> , and an example of the results in <a href='javascript:figurewin('../../asp/graphic.asp?code=416&order=3','3')'>Figure 4</a> .<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Exercise 1.<br /></strong></span></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>In a dolomite formation in which</span><br /> </span></p><p><span style='font-family:Symbol'></span><sub>ma = 2.87</sub><br /> </p><p><span style='font-family:Symbol'></span><sub>b = 2.44</sub><br /> </p><p><span style='font-family:Symbol'></span><sub>f = 1.0 (fresh water)</sub><br /> </p><p><sub>Find </sub><span style='font-family:Symbol'></span><sub>D.</sub><br /> </p><p><span style='font-size:10pt'>Solution 1:<br /></span></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The equation we use is</span><br /> </span></p><p style='margin-left: 36pt'><br /> </p><p><span style='font-size:10pt'>Rearranging to solve for <span style='font-family:Symbol'></span></span><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='margin-left: 36pt'><br /> </p><p><br /> </p><p><span style='font-size:10pt'>or</span><br /> </p><p><span style='font-size:10pt'>(to get rid of negatives)</span><br /> </p><p><span style='font-size:10pt'>Substituting values for <span style='font-family:Symbol'></span><sub>ma</sub><br /> <span style='font-family:Symbol'></span><sub>f</sub> and <span style='font-family:Symbol'><sub></sub></span></span><br /> </p><p><br /> </p><p><span style='font-size:10pt'>The solution is </span><br /> </p><p><span style='font-size:10pt'><strong>Exercise 2.<br /></strong></span></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>In a sandstone formation in which</span><br /> </span></p><p><span style='font-family:Symbol'></span><sub>ma = 2.65</sub><br /> </p><p><span style='font-family:Symbol'></span><sub>b = 2.40</sub><br /> </p><p><span style='font-family:Symbol'></span><sub>f = 1.1 (salt mud filtrate)</sub><br /> </p><p><sub>Find </sub><span style='font-family:Symbol'></span><sub>D.</sub><br /> </p><p><span style='font-size:10pt'>Solution 2:<br /></span></p><p><span style='font-size:10pt'>Using the equation computed in the previous exercise,<br /></span></p><p><span style='font-size:10pt'><br /> </span></p><p><span style='font-size:10pt'><br /> </span></p><p><span style='font-size:10pt'><br /> </span></p><p><span style='font-size:10pt'>=0.16<br /></span></p><p><span style='font-size:10pt'>The solution is <br /></span></p><p><span style='font-size:10pt'><strong>Exercise 3.<br /></strong></span></p><p><span style='font-size:10pt'>In a gas-bearing sandstone, at 10,000 ft the density log reads 1.99 gm/cc or 40% apparent sandstone porosity. Estimate the true porosity, given that R<sub>mf</sub> at formation temperature is 0.2 ohm-m and R<sub>xo</sub> is 20 ohm-m. Assume <span style='font-family:Symbol'></span><sub>mf</sub></span><sub><br /> </sub><span style='font-size:10pt'>is 1.0 gm/cc.<br /></span></p><p><span style='font-size:10pt'>Solution 3:<br /></span></p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:61px'/><col style='width:84px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>ma</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 2.65</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span>b</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 1.99</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>mf</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 0.2</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>xo</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 20</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>depth</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 10,000</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>mf</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 1.0</span></p></td></tr></tbody></table></div><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Volumetrically, the tool response is as follows:</span><br /> </span></p><p><span style='font-size:10pt'><span style='font-family:Symbol'></span>B = <span style='font-family:Symbol'></span>ma (1 - <span style='font-family:Symbol'></span>) + <span style='font-family:Symbol'></span>mf (Sxo)<span style='font-family:Symbol'></span> + <span style='font-family:Symbol'></span>g(1 - Sxo)<span style='font-family:Symbol'></span></span><br /> </p><p><span style='font-size:10pt'>According to Archie,</span><br /> </p><p><br /> </p><p><span style='font-size:10pt'>A simple F, relation is </span><br /> </p><p><span style='font-size:10pt'>So,</span><br /> </p><p><br /> </p><p><br /> </p><p><span style='font-size:10pt'> </span><br /> <span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>g</sub> can be approximated by</span><br /> <br/><span style='font-size:10pt'> </span><br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:61px'/><col style='width:217px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>g</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 0.l8/[(7644/depth) + 0.22]</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 0.18/[(7644/10,000) + 0.22]</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 0.18/(76 + 0.22)</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 0.18/0.98</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 0.184</span></p></td></tr></tbody></table></div><p><span style='font-size:10pt'>Then,</span><br /> <br/><br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:61px'/><col style='width:216px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>g</sub> cor</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 1.325 <span style='font-family:Symbol'></span><sub>g</sub> - 0.188</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 0.243 - 0.188</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= 0.055</span></p></td></tr></tbody></table></div><p><span style='font-size:10pt'>So,</span><br /> <br/><span style='font-size:10pt'> </span><br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:63px'/><col style='width:358px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span>b</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= <span style='font-family:Symbol'></span>ma(1 <span style='font-family:Symbol'></span>) + <span style='font-family:Symbol'></span>mf(Sxo)<span style='font-family:Symbol'></span> + Sxo)<span style='font-family:Symbol'></span>g(1 </span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>= <span style='font-family:Symbol'></span>ma <span style='font-family:Symbol'></span>ma <span style='font-family:Symbol'></span> + <span style='font-family:Symbol'></span>mf(Sxo)<span style='font-family:Symbol'></span> + <span style='font-family:Symbol'></span>g <span style='font-family:Symbol'></span><br /> <span style='font-family:Symbol'></span>g(Sxo)<span style='font-family:Symbol'></span></span></p></td></tr></tbody></table></div><p><span style='font-size:10pt'>Substituting</span><br /> </p><p><span style='font-size:10pt'>for Sxo<span style='font-family:Symbol'></span></span><br /> </p><p><br /> </p><p><span style='font-size:10pt'>and substituting in values,</span><br /> </p><p><span style='font-size:10pt'>1.99 = 2.65 - 2.65 = 1(0.1) + 0.055 - 0.055(0.1)</span><br /> </p><p><span style='font-size:10pt'>1.99 = 2.65 - 2.65 + (0.1) + 0.055 - 0.0055</span><br /> </p><p><span style='font-size:10pt'>2.65 = 2.65 - 1.99 + 0.1 + 0.055 - 0.0055</span><br /> </p><p><span style='font-size:10pt'>2.65 = 0.810</span><br /> </p><p><span style='font-size:10pt'>=</span><br /> </p><p><span style='font-size:10pt'>= 0.306</span><br /> </p><p><span style='font-size:10pt'>The solution is = 30.6%.</span><br /> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-6441902403987259622008-11-20T22:01:00.001-08:002008-11-20T22:01:21.304-08:00Well Logging Tools & Techniques (Lithology Logs)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Lithology Logs<br /></span></h2></p><p><strong>Spontaneous Potential (SP) Log <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Spontaneous potential (SP) was one of the first logging measurements ever made. It was discovered by accident, appearing as a DC potential in the borehole that caused perturbations to the old electric logging systems. Its usefulness was soon realized and it is one of the few well log measurements to have been in continuous use for over fifty years.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The SP has a number of useful functions, which include correlation; lithology, porosity and permeability indications; and a measurement of R<sub>w</sub> (hence formation water salinity).</span><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=404&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> shows a typical SP log. It is represented (in track 1) on the left as a solid curve and shows departures to the left from a base-line or shale-line reading on the right, to a sand line on the left in the "cleanest" nonshale zones. The scale of the log is in millivolts, abbreviated mV. Notice that there is no absolute scale in mV, only a relative scale of so many mV per division.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The SP can be recorded very simply by suspending a single electrode in the borehole and measuring the voltage difference between the electrode and a "ground" electrode that usually takes the form of a "fish," making electrical contact with the earth at the surface. A generalized illustration of the SP recording system is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=404&order=1','1')'>Figure 2</a> . Such SP electrodes are built into many logging tools. For example, the SP can be recorded together with an induction log, a laterolog, a sonic log, and a sidewall core gun, once there is a conductive mud in the hole.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>When mud filtrate salinities are lower than connate water salinities (i.e., R<sub>mf</sub> is > R<sub>w</sub>), the SP deflects to the <em>left </em>(the SP potential is <em>negative). </em>This is called a <em>normal SP. </em>When the salinities are reversed (i.e., salty mud and fresh formation water, R<sub>mf</sub> < R<sub>w</sub>), the SP deflects to the <em>right. </em>This is called a <em>reverse SP. </em>Other things being equal, there is no SP at all when R<sub>mf</sub> = R<sub>w</sub>. </span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>It is quite common to find fresh water in shallow sands and increasingly saline water as depth increases. Such a progression is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=404&order=2','2')'>Figure 3</a> , where the SP appears to be deflecting to the left deep in the well but is reversed nearer the surface.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In sand A, R<sub>w</sub> is less than R<sub>mf</sub><strong>;</strong> i.e., formation water is saltier than the mud filtrate. In sand B, the SP deflection is less than in sand A and thus a fresher formation water is indicated. In sand C, the SP is reversed, indicating that formation water is fresher than the mud filtrate and thus R<sub>w</sub> is greater than R<sub>mf</sub>. Somewhere in the region of 7000 ft it may be guessed that R<sub>mf</sub> and R<sub>w</sub> are equal.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Quite apart from water salinity variations, SP deflections also respond to depositional changes. Characteristic SP shapes are produced in channels, bars, and other depositional sequences where sorting, grain size, or cementation changes with depth. These shapes are also called "bells" or "funnels." <a href='javascript:figurewin('../../asp/graphic.asp?code=404&order=3','3')'>Figure 4</a> illustrates some of these patterns.</span><br /> </p><p style='text-align: justify'><br /> </p><p><strong>Introduction</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The spontaneous potential (SP) curve is a recording of naturally occurring physical phenomena in in-situ rocks. The SP curve records the electrical potential (voltage) produced by the interaction of formation connate water, conductive drilling fluid, and shale. Although relatively simple in concept, the SP curve is quite useful and informative. Among its uses are that it</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>differentiates porous and permeable rocks from clays and shales</span><br /> </span></li></ul><p><span style='font-size:10pt'><span style='font-family:Symbol'></span>gives a qualitative indication of bed shaliness</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>aids in lithology identification</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>determines R<sub>w</sub> (formation water resistivity)</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the log in <a href='javascript:figurewin('../../asp/graphic.asp?code=404&order=4','4')'>Figure 5</a> , the SP is recorded in track one. opposite shales, the SP curve usually defines a more-or-less straight line on the log, called the shale baseline. opposite permeable formations, the curve shows excursion from the shale baseline; in thick beds, the excursions tend to reach an essentially constant deflection called the sand line. The SP log is measured in millivolts (mV).<br /></span></p><p style='text-align: justify'><br /> </p><p><strong>Recording the SP</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The SP can be recorded very simply by suspending a single electrode in the borehole and measuring the voltage difference between the electrode and a ground electrode (usually taking the name and the form of a "fish"), making electrical contact with the earth at the surface. A generalized illustration of the SP recording system is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=404&order=5','5')'>Figure 6</a> . Such SP electrodes are built into many logging tools. The SP cannot be recorded in oil-base muds, which allow no conductive path.</span><br /> </p><p style='text-align: justify'> <br /> </p><p><strong>The Source of the SP</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The SP is an indicator of formation water salinity. To understand how the SP can be used to find R</span><sub>w</sub><span style='font-size:10pt'>, let us discuss its origin.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>When two sodium chloride solutions of differing concentration are brought into contact, ions from the solution with a higher concentration tend to migrate toward the solution of lower concentration until equilibrium occurs (<a href='javascript:figurewin('../../asp/graphic.asp?code=404&order=6','6')'> Figure 7</a> ). However, since C1</span><span style='font-size:7pt'>-</span><span style='font-size:10pt'> ions move faster than Na</span><span style='font-size:7pt'>+</span><span style='font-size:10pt'> ions, a conventional current flows from the less concentrated solution to the more concentrated solution. The electrical current resulting from the combined sodium and chlorine ion movement is known as the liquid junction effect.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In terms of the solutions present in a formation, mud filtrate can be substituted for the less concentrated solution and formation water for the more concentrated solution. The potential is referred to as the liquid junction potential (E</span><span style='font-size:7pt'>lj</span><span style='font-size:10pt'>). The greater the contrast in salinity between mud filtrate and formation water, the larger this potential ( <a href='javascript:figurewin('../../asp/graphic.asp?code=404&order=7','7')'>Figure 8</a> ).</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Another "battery" that exists in the formation arises from the molecular construction of shale beds. Shales are permeable to Na</span><span style='font-size:7pt'>+</span><span style='font-size:10pt'> ions, but not so permeable to C1</span><span style='font-size:7pt'>-</span><span style='font-size:10pt'> ions. A shale thus acts as an ionic sieve. This phenomenon occurs because of the crystalline structure of clay minerals. Their exterior surfaces exchange sites where cations may cling temporarily. This same surface conductance effect manifests itself in the electrical behavior of shaly sands.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Since Na</span><span style='font-size:7pt'>+</span><span style='font-size:10pt'> ions effectively manage to penetrate through the shale from the saline formation water to the less saline mud column, a potential is set up known as the membrane potential (E</span><span style='font-size:7pt'><sub>m</sub></span><span style='font-size:10pt'>). <a href='javascript:figurewin('../../asp/graphic.asp?code=404&order=8','8')'>Figure 9</a> indicates the process.</span><br /> </p><p><span style='font-size:10pt'>The total SP (<a href='javascript:figurewin('../../asp/graphic.asp?code=404&order=9','9')'> Figure 10</a> ) can now be appreciated as the sum of the two components:</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>E</span><span style='font-size:7pt'><sub>total</sub></span><span style='font-size:10pt'> = E</span><span style='font-size:7pt'><sub>lj</sub></span><span style='font-size:10pt'> + E</span><span style='font-size:7pt'><sub>m</sub></span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The total potential, measurable in the borehole by an electrode, is also referred to as the electrochemical component of the SP.</span><br /> </span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>When mud filtrate salinities are lower than connate water salinities (i.e., R</span><sub>mf</sub><span style='font-size:10pt'> > R</span><sub>w</sub><span style='font-size:10pt'>) the SP deflects to the left (the SP potential is negative). This is called a normal SP. When the salinities are reversed (i.e., salty mud and fresh formation water, R</span><sub>mf</sub><span style='font-size:10pt'> < R</span><sub>w</sub><span style='font-size:10pt'>) the SP deflects to the right. This is called a reverse SP. Other things being equal, there will be no SP at all when R</span><sub>mf</sub><span style='font-size:10pt'> = R</span><sub>w</sub><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>It is quite common to find fresh water in shallow sands and increasingly saline water as depth increases. Such a progression is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=404&order=10','10')'>Figure 11</a> , where the SP appears deflecting to the left deep in the well but is reversed nearer the surface.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In sand A, R</span><sub>w</sub><span style='font-size:10pt'> is less than R</span><sub>mf</sub><span style='font-size:10pt'>; i.e., formation water is saltier than the mud filtrate. In sand B, the SP deflection is less than in sand A, indicating a fresher formation water. In sand C, the SP is reversed, indicating formation water that is fresher than the mud filtrate (R</span><sub>w</sub><span style='font-size:10pt'> > R</span><sub>mf</sub><span style='font-size:10pt'>). We may guess that, at about 7000 ft, R</span><sub>mf</sub><span style='font-size:7pt'><br /> </span><span style='font-size:10pt'>and R</span><sub>w</sub><span style='font-size:10pt'> are equal.</span><br /> </p><p style='text-align: justify'><strong>Spontaneous Potential: Rw Determination<br /></strong></p><p><strong>R<sub>w</sub> from the SP <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>In order to perform quantitative analysis of the SP, the relationship between the SP and the resistivities of the mud filtrate and the formation water must be determined. It can be shown that</span><br /> </p><p style='margin-left: 36pt'>SP = -K log (R<sub>mf</sub>/R<sub>w</sub>)<br /></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>where SP is measured in millivolts and K is a constant that depends on temperature. By inspection, R<sub>w</sub> can be found if SP, K, and R<sub>mf</sub> are known. <br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The SP should be read in a water-bearing sand, provided it is clean (no shale is present) and sufficiently thick to allow for full development of the potential. K can be estimated from the temperature of the formation. A good approximation is</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>where T is the formation temperature in </span><span style='font-family:Symbol'></span><span style='font-size:10pt'>F.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>mf</sub></span><span style='font-size:10pt'> can be estimated from direct measurement on a sample of mud filtrate prepared by placing a circulated mud sample in a mud press. This data is usually entered on the log heading. Care should be taken when using these values, however, since logging engineers have been known to take shortcuts and quote R</span><span style='font-size:7pt'><sub>mf</sub></span><span style='font-size:10pt'> as some fraction of R<sub>m</sub> usually 0.75 R</span><span style='font-size:7pt'><sub>m</sub></span><span style='font-size:10pt'> This may be a fair estimate, but is not necessarily correct.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Likewise, circulated mud samples are not always collected by rig personnel in the correct manner. Even when properly collected, samples are not always representative of the mud in the hole at the time a particular formation was drilled.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Experiments of the sort reported by Williams and Dunlap (1984), where R</span><span style='font-size:7pt'><sub>m</sub></span><span style='font-size:10pt'> and R</span><span style='font-size:7pt'><sub>mf</sub></span><span style='font-size:10pt'> were measured on a daily basis as a well was drilled, tend to support the contention that R</span><span style='font-size:7pt'><sub>mf</sub></span><span style='font-size:10pt'> is the least well-defined parameter in SP log analysis. A comparison between the values of R</span><span style='font-size:7pt'><sub>m</sub></span><span style='font-size:10pt'> and R</span><span style='font-size:7pt'><sub>mf</sub><br /> </span><span style='font-size:10pt'>, as reported on log headings with the actual values measured on a daily basis, shows some alarmingly large differences. In <a href='javascript:figurewin('../../asp/graphic.asp?code=405&order=0','0')'>Figure 1</a> , we see that both the R</span><span style='font-size:7pt'><sub>m</sub></span><span style='font-size:10pt'> and R</span><span style='font-size:7pt'><sub>mf</sub></span><span style='font-size:10pt'> reported on the log heading for this well were low by a substantial factor.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the absence of any reported value for R</span><span style='font-size:7pt'><sub>mf</sub></span><span style='font-size:10pt'>, a value can be estimated from <a href='javascript:figurewin('../../asp/graphic.asp?code=405&order=1','1')'>Figure 2</a> , which also serves for estimation of R</span><span style='font-size:7pt'><sub>mc</sub></span><span style='font-size:10pt'>. A fit of this empirical chart gives</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>mf</sub></span><span style='font-size:10pt'> = (R</span><span style='font-size:7pt'><sub>m</sub></span><span style='font-size:10pt'>)</span><span style='font-size:7pt'>1.065</span><span style='font-size:10pt'> x 10((9 - W)/13)</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>mc</sub></span><span style='font-size:10pt'> = (R</span><span style='font-size:7pt'><sub>m</sub></span><span style='font-size:10pt'>)</span><span style='font-size:7pt'>0.88</span><span style='font-size:10pt'> x 10((W - 10.4)/7.6)</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where W is the mud weight in lb/gallon.</span><br /> </span></p><p><span style='font-size:10pt'>Mother statistical approximation for predominantly NaCl muds is</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS; font-size:10pt'>R<sub>mf</sub> = 0.75 Rm <br /></span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>R<sub>mc</sub> = 1.5 Rm<br /></span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>In all cases, direct measurement on a sample of mud filtrate is preferred. Even after determining values for SP, K, and R<sub>mf</sub>, there are still minor problems to be solved. The equation <br /></span></p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS; font-size:10pt'>SP = -K log (R<sub>mf</sub>/R<sub>w</sub>)<br /></span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>does not explain adequately the true electrochemical behavior of salt solutions. The actual SP development is controlled by the relative activity of the formation water and mud filtrate solutions. Thus the SP equation should read <br /></span></p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS; font-size:10pt'>SP = -K Log (A<sub>w</sub>/A<sub>mf</sub>)<br /></span></p><p><span style='font-family:Arial Unicode MS; font-size:10pt'>where Aw and Amf are the activities of the connate water and the mud filtrate, respectively. <br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The resistivity of a solution is roughly proportional to the reciprocal of its activity at low salt concentrations, but at high concentrations there is a marked departure from this rule. A way to compensate for this departure is to define "effective" or "equivalent" resistivities for salt solutions that are, by definition, inversely proportional to the activities (R</span><span style='font-size:7pt'><sub>we</sub></span><span style='font-size:10pt'> = 0.075/A</span><span style='font-size:7pt'><sub>w</sub></span><span style='font-size:10pt'> at 77 </span><span style='font-family:Symbol'></span><span style='font-size:10pt'>F). A conversion chart is then used to go from an equivalent resistivity (R</span><span style='font-size:7pt'><sub>we</sub></span><span style='font-size:10pt'>) to an actual resistivity (R</span><span style='font-size:7pt'><sub>w</sub></span><span style='font-size:10pt'>). The SP equation can then be rewritten to the strictly accurate formula</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS; font-size:10pt'>SP = -K log (R<sub>mfe</sub>/R<sub>we</sub>)<br /></span></p><p style='text-align: justify'><strong>Spontaneous Potential: Influencing Factors<br /></strong></p><p><span style='font-family:Times'><strong>Factors Affecting the SP</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>SP readings are usually accurately and easily measured. However, there are some circumstances where SP readings need careful handling.</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Symbol'></span><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Oil-base muds completely lack an electrical path through the mud column, hence no SP can be generated.</span><br /> <br/></span><span style='font-family:Symbol'></span><span style='font-family:Arial Unicode MS; font-size:10pt'>Shaly formations reduce the measured SP. This phenomenon permits the formation shaliness to be determined if a clean sand with the same water salinity is available for a legitimate comparison.</span><br /> <br/><span style='font-family:Symbol'></span><span style='font-family:Arial Unicode MS; font-size:10pt'>Hydrocarbon saturation reduces SP measurements. Thus, only water-bearing sands should be selected for Rw determination from the SP. </span><span style='font-family:Symbol'><br/></span><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Unbalanced mud columns, with differential pressure into the formation, can cause "streaming" potentials that augment the SP. This effect, known as electrokinetic SP, is noticeable in depleted reservoirs, and is impossible to handle quantitatively.</span><br /> </span></p><p style='text-align: justify; margin-left: 36pt'><span style='font-family:Symbol'></span><span style='font-family:Arial Unicode MS; font-size:10pt'>Resistivities may be very high in hard formations, except in the permeable zones and in the shales. These high resistivities affect the distribution of the SP currents, hence the shape of the SP curve.As illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=406&order=0','0')'>Figure 1</a> , the SP currents flowing from shale bed Shl toward permeable bed P2 are largely confined to the borehole between Shl and P2 because of the very high resistivity of the formation in this interval. Accordingly, the intensity of the SP current in the borehole in this interval remains constant. Assuming the hole diameter is constant, the potential drop per foot is constant and the SPcurve is a straight line. <br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-family:Symbol'></span><span style='font-size:10pt'>In these formations, SP current can leave or enter the borehole only opposite permeable beds or shales, and the SP curve shows a succession of straight portions with a change of slope opposite every permeable interval (with the concave side of the SP curve toward the shale line) and opposite every shale bed (with the convex side of the SP curve toward the shale line). The boundaries of the permeable beds cannot be located with accuracy by use of the SP in such highly resistive formations.</span><br /> <br/><span style='font-family:Symbol'></span><span style='font-size:10pt'>Bed thickness can affect the SP measurement quite dramatically. In thin beds, the SP does not fully develop. <a href='javascript:figurewin('../../asp/graphic.asp?code=406&order=1','1')'>Figure 2</a> illustrates the factors involved in SP reduction.<br /></span></p><p style='text-align: justify'><span style='font-family:Symbol'></span><span style='font-size:10pt'>In the terminology used here SP refers to the observed SP deflection on the log and SSP (static SP) to the value it would have had all disturbing influences been removed. Among the disturbing factors may be bed thickness, diameter of invasion, R</span><span style='font-size:7pt'>xo</span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'>m</span><span style='font-size:10pt'> ratio, neighboring shale resistivity (R</span><span style='font-size:7pt'>sh</span><span style='font-size:10pt'>), hole diameter (d</span><span style='font-size:7pt'>h</span><span style='font-size:10pt'>), and mud resistivity (R</span><span style='font-size:7pt'>m</span><span style='font-size:10pt'>). In general, the SP reduction is greatest in thin beds, where R</span><span style='font-size:7pt'>xo</span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'>m</span><span style='font-size:10pt'> is high and where invasion is deep.</span><br /> </p><p style='text-align: justify'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Many SP correction charts are available in the literature, some more complex than others. It is virtually impossible to include on one chart all the variables involved in making necessary corrections. <a href='javascript:figurewin('../../asp/graphic.asp?code=406&order=2','2')'>Figure 3</a> shows a practicable chart, with most of the required variables (d</span><span style='font-size:7pt'>i</span><span style='font-size:10pt'>, R</span><span style='font-size:7pt'>xo</span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'>m </span><span style='font-size:10pt'>, and h) known or estimated.<br /></span></p><p style='text-align: justify'><span style='font-family:Symbol'></span><span style='font-size:10pt'>The use of non-NaCl muds (such as KCl) affects the derivation of R</span><span style='font-size:7pt'>w</span><span style='font-size:10pt'> from the SP. Cox and Raymer (1976) cover the subject matter in detail. A quick solution in the case of a KCl mud problem is simply to take the observed SP deflection, subtract 25 mV, and then treat it as a NaC1 mud case. The Rmf to Rmfe relationship is slightly different for KCl filtrates than for NaCl filtrates. Again a quick rule of thumb is to add 30% to the measured Rmf and treat it as an NaCl filtrate.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p><strong>The SP as a Shale Indicator <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The presence of shale in art otherwise "clean" sand tends to reduce the SP. This effect can be used in estimating the shale content of a formation. If SPsand is the value observed in a clean, water-bearing sand and SPshale is the value observed in a shale, then any intermediate value of the SP may be converted into a value for the shale volume (V</span><span style='font-size:7pt'><sub>sh</sub></span><span style='font-size:10pt'>) by the relationship</span><br /> </p><p style='text-align: justify'> <br /></p><p><br /> </p><p><br /> </p><p><strong>Gamma Ray Measurement<br /></strong></p><p><strong>Natural and Spectral Gamma Ray (GR) <br /></strong></p><p><span style='font-size:10pt'>Logs Gamma ray logs are used for four main purposes:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>correlation and bed boundary determination<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>evaluation of the shale content of a formation<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>mineral analysis<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>perforating depth control and the tracing of radioactive fluid movement<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>GR logs measure the natural gamma ray emissions from subsurface formations. Because gamma rays can pass through steel casing, measurements can be made in both open and cased holes. In applications not pertinent here, such as pulsed neutron logging, induced gamma rays are measured.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=407&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> shows a typical GR log. It is always presented in track 1 on a linear grid and is scaled in API units. Gamma ray activity increases from left to right. Gamma ray tools consist of a detector and the associated electronics for passing the gamma ray count rate to the surface. These tools are in the form of double-ended subs that can be sandwiched into practically any logging tool string; thus, the GR log can be run with practically any tool available.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Gamma rays originate from three sources in nature: the radioactive elements in the uranium and thorium groups, and potassium. Uranium 235, uranium 238, and thorium 232 all decay, via a long chain of daughter products, to stable lead isotopes. An isotope of potassium, K40, decays to argon.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>An "average" shale contains 6 ppm uranium, 12 ppm thorium, and 2% potassium. Since the various gamma ray sources are not all equally effective, it is more informative to consider potassium equivalents (i.e., the amount of potassium that would produce the same number of gamma rays per unit of time). Reduced to a common denominator, the average shale contains uranium equivalent to 4.3% potassium, thorium equivalent to 3.5% potassium, and 2% potassium.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>But an average shale is hard to find. Since a shale is a mixture of clay minerals, sand, silts, and other extraneous materials, there can be no standard gamma ray activity for shale. Indeed, the main clay minerals vary enormously in their natural radioactivity. Kaolinite and chlorite have no potassium, whereas illite contains between 4% and 8% potassium. Montmorillonite contains less than 1% potassium. Occasionally, natural radioactivity may be due to the presence of dissolved potassium or other salts in the water contained in the pores of the shale.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Each radioactive decay produces a gamma ray that is unique. These various gamma rays have characteristic energy levels and occur in characteristic abundance, as expressed in counts per time period. Counting how many gamma rays a formation produces can be carried a step further to counting how many from each gamma ray energy group it produces. If the number of occurrences is plotted against the energy group, a spectrum will be produced that is characteristic of the formation logged. The relationship between gamma ray energy and frequency of occurrence, shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=407&order=1','1')'>Figure 2</a> , is used as the standard for measurement in the natural gamma spectroscopy tools.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=407&order=2','2')'><span style='font-size:10pt'>Figure 3</span></a><span style='font-size:10pt'> shows such a spectrum, where energies from 0 to approximately 3 Mev have been split into 256 specific energy "bins." The number of gamma rays in each bin is plotted on the Y-axis. This spectrum can be thought of as a mixture of the three individual spectra belonging to uranium, thorium, and potassium. Some unique mixture of these three radioactive "families" would have the same spectrum as the observed one. The trick is to find a quick and easy method of discovering that unique mixture. Fortunately, on-board computers in logging trucks are capable of quickly finding a "best fit" and producing continuous curves showing the concentration of U, Th, and K.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In a gamma ray spectral log note that in track 1 both total gamma ray activity (SGR) and a "uranium-free" (CGR) version of the total activity are displayed. Units are API. In tracks 2 and 3, the concentration of U, Th, and K are displayed. Depending on the logging service company the units may be in counts/sec, ppm, or %.<br /></span></p><p><strong>Introduction<br /></strong></p><p><span style='font-size:10pt'>Gamma ray logs are used for three Main purposes:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>correlation<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>evaluation of the shale content of a formation<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>mineral analysis<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Gamma ray logging tools measure the natural gamma ray emissions from subsurface formations. Since gamma rays can pass through steel casing, measurements can be made in both open and cased holes. Other applications, measuring induced gamma rays (e.g., in pulsed neutron logging), are not discussed here.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=407&order=3','3')'><span style='font-size:10pt'>Figure 4</span></a><span style='font-size:10pt'> shows a typical gamma ray log. It is normally presented in Track I on a linear grid and is scaled in API units, defined below. Gamma ray activity increases from left to right. Gamma ray tools consist of a gamma ray detector and the associated electronics for passing the gamma ray count rate to the surface. Shaped like double-ended subs that can be sandwiched into practically any logging tool string, they can be run with practically any tool available.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'> <br /> </p><p><strong>Origin of Natural Gamma Rays<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Gamma rays originate from three Main sources in nature: the radioactive elements in the uranium group, the thorium group, and potassium. Uranium 235, uranium 238, and thorium 232 all decay, via a long chain of daughter products, to stable lead isotopes.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>An isotope of potassium, K</span><span style='font-size:7pt'>40</span><span style='font-size:10pt'>, decays to argon, giving off a gamma ray. It should be noted that each type of decay is characterized by a gamma ray of a specific energy (wavelength) and that the frequency of occurrence for each decay energy is different. <a href='javascript:figurewin('../../asp/graphic.asp?code=407&order=4','4')'>Figure 5</a> shows this relationship between gamma ray energy and frequency of occurrence. This is an important concept, since it is used as the basis for measurement in the natural gamma spectroscopy tools.<br /></span></p><p><strong>Naturally Occurring Radioactive Minerals<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>An "average" shale contains 6 ppm uranium, 12 ppm thorium, and 2% potassium. Since the various gamma ray sources are not all equally effective, it is more informative to consider this mix of radioactive Materials on a common basis, e.g., by reference to potassium equivalents (i.e., the amount of potassium that produces the same number of gamma rays per unit of time). Reduced to a common denominator, the average shale contains uranium equivalent to 4.3% potassium, thorium equivalent to 3.5% potassium, and 2% potassium. An average shale is hard to find. Shale, being a mixture of clay minerals, sand, silts, and other extraneous Materials, exhibits no "standard" gamma ray activity. Indeed, the main clay minerals vary enormously in their natural radioactivity: kaolinite has no potassium, illite between 4% and 8%, montmorillonite less than 1%. occasionally, natural radioactivity may be due to the presence of dissolved potassium or other salts in shale pore water.<br /></span></p><p><strong>Operating Principle of Gamma Ray Tools<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Traditionally, two types of gamma ray detectors have been used in the logging industry: Geiger-Mueller and scintillation detectors. Today, practically all gamma ray tools use scintillation detectors containing a sodium iodide crystal ( <a href='javascript:figurewin('../../asp/graphic.asp?code=407&order=5','5')'>Figure 6</a> ). when a gamma ray strikes the crystal, a single photon of light is emitted. This tiny flash of light then strikes a photo cathode made from cesium-antimony or silver-Magnesium.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Each photon, upon hitting the photocathode, releases a spray of electrons. These, in turn, are accelerated in an electric field to strike another electrode, producing an even bigger "shower" of electrons. This process is repeated through a number of stages until a final electrode conducts a small current through a measure resistor to give a voltage pulse signaling that a gamma ray has struck the sodium iodide crystal. The system has a very short "dead time" and can register Many counts per second without becoming swamped by numerous signals.<br /></span></p><p><strong>Calibration of Gamma Ray Detectors and Logs<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>One problem of gamma ray logging is choosing a standard calibration system, since all logging companies use a variety of counters encased in different steel housings of various sizes and shapes. On very old logs, the scale might be quoted in micrograms of radium equivalents/ton of formation. For Many reasons this method was found to be unsatisfactory to calibrate for gamma ray logs, so an API standard was devised. A test pit (installed at the university of Houston) contains an "artificial shale" ( <a href='javascript:figurewin('../../asp/graphic.asp?code=407&order=6','6')'>Figure 7</a> ). A cylinder 24 ft long and 4 ft in diameter contains a central 8-ft section consisting of cement mixed with 13 ppm uranium, 24 ppm thorium, and 4% potassium. On either side, completing the sandwich, are 8-ft sections of neat Portland cement cased with 5-1/2 in. J55 casing. The API standard defines the difference in radioactivity between the neat cement and the radioactively doped cement as 200 API units. Any logging service company May place its tool in this pit to make a calibration.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Field calibration is performed using a portable jig that contains a radioactive "pill." Placed over the center of the gamma ray detector, the jig produces an increase over the back-ground count rate equivalent to a known number of API units, depending on the tool type and size and the counter it encloses.<br /></span></p><p><strong>Time Constants<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>All radioactive processes are subject to statistical variations. For example, if a source of gamma rays emits an average of 100 gamma rays each second over a period of hours, the source will emit 360,000 gamma rays per hour (100/sec. x 60 seconds x 60 minutes). If the count is measured for 1 second, however, the actual count might be more or less than 100, thus forcing a choice. A relatively quick gamma ray count gives a poor estimate of the real count rate, while a long count yields a more accurate estimate of the count rate at the expense of much time. The logger must choose between various time constants, according to the radioactivity level measured. The lower the count rate, the longer the time constant required for adequate averaging of the variations.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In the logging environment, gamma rays can be counted for a short period of time (e.g., one second) with the recognition that during that time period, the detector will have moved past the formation whose activity is being measured. Thus, the logging speed and the time interval used to average count rates are interrelated. The following rules of thumb are generally recognized.<br /></span></p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:126px'/><col style='width:121px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Logging Speed</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Time Constant</strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>3600 ft/hr</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>1 sec</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>1800 ft/hr</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>2 sec</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>1200 ft/hr</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>3 sec</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>900 ft/hr</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>4 sec</span></p></td></tr></tbody></table></div><p style='text-align: justify'><span style='font-size:10pt'>In the future, when the efficiency of gamma ray detectors and their associated electronics improves by one or two orders of Magnitude, the use of a time constant will be obsolete except in the cases of extremely inactive formations with intrinsically low gamma ray count rates.<br /></span></p><p><span style='font-size:10pt'><strong>Perturbing Affects on Gamma Ray Logs<br /></strong></span></p><p><span style='font-size:10pt'>Gamma ray logs are subject to a number of perturbing effects, including<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>sonde position in the hole (centered/eccentered)<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>hole size<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>mud weight<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>casing size and weight<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>cement thickness<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Since there are innumerable combinations of these effects, an arbitrary standard set of conditions is defined as a 3-5/8 in. OD tool eccentered in an 8-in. hole filled with 10-lb mud. A series of charts exists for Making the appropriate corrections. Note that if a gamma ray log is run in combination with a neutron density tool, it is run eccentrically. If run with a laterolog or an induction log, it is usually centered.<br /></span></p><p><strong>Gamma Ray Spectroscopy<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Each radioactive decay produces a gamma ray that is unique in terms of energy level and abundance, expressed in counts per time period. The simple method of counting how Many gamma rays a formation produces can be carried a step further to count how Many from each gamma ray energy group it produces. If the number of occurrences is plotted against the energy group, a spectrum is produced that is characteristic of the formation logged.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=407&order=7','7')'><span style='font-size:10pt'>Figure 8</span></a><span style='font-size:10pt'> shows such a spectrum, where energies from 0 to approximately 3 MeV have been split into 256 specific energy "bins." The number of gamma rays in each bin is plotted on the Y-axis. This spectrum can be thought of as a mixture of the three individual spectra belonging to uranium, thorium, and potassium. A unique mixture of these three radioactive "families" has the same spectrum as the observed one. The trick is to find a quick and easy method of discovering that unique mixture. Fortunately, on-board computers in logging trucks are capable of quickly finding a "best fit" and producing continuous curves showing the concentration of U, Th, and K.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=407&order=8','8')'><span style='font-size:10pt'>Figure 9</span></a><span style='font-size:10pt'> illustrates a gamma ray spectral log. Note that in Track I both total gamma ray activity (SGR) and a "uranium free" version of the total activity are displayed (units are API). In Tracks II and III the concentrations of U, Th, and K are displayed. Depending on the logging service company, the units may be in counts/sec, ppm, or percentage.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Lithodensity Tool<br /></strong></p><p><span style='font-family:Arial Unicode MS'><strong>Photoelectric Factor (P<sub>e</sub>) Log</strong><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>This P<sub>e</sub>or lithodensity log, run with the lithodensity tool (LDT), is another version of the standard formation density log. In addition to the bulk density (<span style='font-family:Symbol'></span><sub>b</sub>), the tool also measures the photoelectric absorption index (P<sub>e</sub>) of the formation. This new parameter enables a lithological interpretation to be made without prior knowledge of porosity.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The physical principle upon which the P<sub>e</sub> log is based is that gamma rays interact with matter in various ways, depending upon their energy. However, only two reactions are of interest when dealing with relatively low energy gamma rays originating from the chemical sources currently used in logging tools. These reactions are the Compton scattering of gamma rays by electrons, and the photoelectric absorption of gamma rays by electrons.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The photoelectric effect occurs when a gamma ray collides with an electron and is absorbed in the process, so that all of its energy is transferred to the electron. The probability of this reaction taking place depends upon the energy of the incident gamma rays and the type of atom. The photoelectric absorption index of an atom increases as its atomic number, Z, increases.</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>Pe = (0.1 Z<sub>eff</sub>)3.6</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The Compton effect occurs over a wide energy range, whereas the photoelectric effect only occurs when lower energy gamma rays are involved.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>The lithodensity tool is similar to a conventional density logging device, and uses a skid containing a gamma ray source and two gamma ray detectors held against the borehole wall by a spring-actuated arm ( <a href='javascript:figurewin('../../asp/graphic.asp?code=408&order=0','0')'>Figure 1</a> ). Gamma rays are emitted from the tool and are scattered by the formation, losing energy until they are absorbed through the photoelectric effect.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>At a finite distance from the source, a gamma ray energy spectrum exists such as that shown for a rock of density p in <a href='javascript:figurewin('../../asp/graphic.asp?code=408&order=1','1')'>Figure 2</a> . This figure also shows that an increase in the formation density (<span style='font-family:Symbol'></span><sub>2</sub> > <span style='font-family:Symbol'></span><sub>1</sub>) results in a decrease in the number of gamma rays detected over the whole spectrum.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>For formations of constant density but different photoelectric absorption coefficients, the gamma ray spectrum is only altered at lower energies, as indicated in <a href='javascript:figurewin('../../asp/graphic.asp?code=408&order=2','2')'>Figure 3</a> . Observing the gamma ray spectrum, we notice that region H only supplies information relating to the density of the formation, whereas region L provides data relating to both the electron density and the Pe value. By comparing the counts in the energy windows H and L, the Pe can be measured. The gamma ray spectrum at the short spacing detector is only analyzed for a density measurement, which is used to correct the formation density determined from the long spacing spectrum for effects of mud-cake and rugosity.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The lithodensity tool skid and detector system produces greater counting rates than those obtained with the conventional density tools, resulting in lower statistical variations and better repeatability of the measurements. The geometry of the skid is such that the density reading has a sharper vertical resolution than that of the conventional density measurement. The P<sub>e</sub> measurement also has this high resolution, which has applications in identifying fractures and laminar formations.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The photoelectric absorption coefficient is virtually independent of porosity, there being only a slight decrease in the coefficient as the porosity increases. Similarly, the fluid content of the formation has little effect. Simple lithologies, such as pure sandstone and anhydrite, can be read directly from logs using Pe curves. Look for the following readings in the most commonly occurring reservoir rocks and evaporites.</span><br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:103px'/><col style='width:78px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Material</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>P<sub>e</sub></strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sand</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>1.81</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Shale</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>3-4</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limestone</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>5.08</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Dolomite</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>3.14</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Salt</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>4.65</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Anhydrite</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>5.05</span></p></td></tr></tbody></table></div><p style='text-align: justify'><span style='font-size:10pt'>Although there is a degree of variation in the log readings due to impurities, we can identify four main lithologies in this example: sandstone up to 265 m, anhydrite from 255 to 210 m, dolomite from 210 to 185 m, and halite above 185 m. In some ambiguous cases, we must also refer to the density or neutron porosity readings.<strong><br /> </strong></span></p><p><span style='font-family:Times; font-size:13pt'><strong>Lithologic Density</strong></span><br /> </p><p><span style='font-size:10pt'>The lithodensity logs are improved and expanded versions of the standard formation density log. In addition to the bulk density ( b), these tools measure the photoelectric absorption index (P<sub>e</sub>) of the formation. This parameter enables a lithological interpretation to be made without prior knowledge of porosity.</span><br /> </p><p><strong>Physical Principle</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Gamma rays interact with matter in various ways, depending upon their energy. However, only two interactions are of interest when dealing with relatively low-energy gamma rays originating from the chemical sources currently used in logging tools. These interactions are the Compton scattering of gamma rays by electrons, and the photoelectric absorption of gamma rays by electrons. Compton scattering has already been discussed in the context of the conventional density tool measurements.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The photoelectric effect occurs when a gamma ray collides with an electron and is absorbed in the process, so that all of its energy is transferred to the electron. The probability of this reaction taking place depends upon the energy of the incident gamma rays and the type of atom. The photoelectric absorption index of an atom increases with increasing atomic number, Z.</span><br /> </p><p><span style='font-size:10pt'>P<sub>e</sub> = (0.1 x Z<sub>eff</sub>)3.6</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>While the Compton effect occurs over a wide energy range, the photoelectric effect results only with lower-energy gamma rays. <a href='javascript:figurewin('../../asp/graphic.asp?code=408&order=3','3')'>Figure 4</a> plots the mass absorption coefficient, µ, against the gamma ray energy and also shows that the photoelectric effect, unlike Compton scattering, is dependent on the formation type.</span><br /> </p><p style='text-align: justify'> <br /> </p><p><strong>Measurement Theory</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The lithodensity tool, similar to a conventional compensated density device, uses a skid containing a gamma ray source and two gamma ray detectors held against the borehole wall by a spring-actuated arm ( <a href='javascript:figurewin('../../asp/graphic.asp?code=408&order=4','4')'>Figure 5</a> ). Gamma rays, emitted from the tool with an energy of 662 keV, are scattered by the formation, losing energy until they are absorbed through the photoelectric effect.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>At a finite distance from the source, a gamma ray energy spectrum exists (<a href='javascript:figurewin('../../asp/graphic.asp?code=408&order=5','5')'> Figure 6</a> ). This figure also shows that an increase in the formation density results in a decrease in the number of gamma rays detected over the whole spectrum. Fore formations of constant density but different photoelectric absorption coefficients, the gamma ray spectrum is altered only at lower energies. In the gamma ray spectrum in <a href='javascript:figurewin('../../asp/graphic.asp?code=408&order=6','6')'>Figure 7</a> , region H only supplies information relating to the density of the formation, whereas region L provides data relating to both the electron density and the photoelectric absorption index.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>By comparing the counts in the energy windows H and L, one may measure the photoelectric absorption index. The gamma ray spectrum at the short-spacing detector is analyzed only fore a density measurement, which is used to correct the formation density determined from the long-spacing spectrum for effects of mudcake and rugosity.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The lithodensity tool skid and detector system produces greater counting rates than are obtained with the conventional density tools, resulting in lower statistical variations and better repeatability of the measurements. The geometry of the skid is such that the density reading has a sharper vertical resolution than that of the conventional density measurement. The P<sub>e</sub> measurement, also with high resolution, has applications in identifying fractures and laminar formations.</span><br /> </p><p><strong>Interpretation of the P<sub>e </sub>Curve</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The photoelectric absorption coefficient is virtually independent of porosity and fluid content, decreasing only slightly as porosity increases. Simple lithologies, such as puree sandstone and anhydrite, can be read directly from logs using the P<sub>e</sub> curve (PEF, or photoelectric factor) alone. Look for the following readings in the most commonly occurring reservoir rocks and evaporites.</span><br /> <br/><br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:103px'/><col style='width:84px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Material</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Pe</strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sand</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>1.81</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limestone</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>5.08</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Dolomite</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>3.14</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Salt</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>4.65</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Anhydrite</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>5.05</span></p></td></tr></tbody></table></div><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=408&order=7','7')'><span style='font-size:10pt'>Figure 8</span></a><span style='font-size:10pt'> illustrates an example of these logs . Although there is a degree of variation in the log readings, caused by impurities, four main lithologies can be identified in this example: sandstone up to 265 m, anhydrite from 255 to 210 m, dolomite from 210 to 185 m, and halite above 185 m. In some ambiguous cases, the density or neutron porosity readings must also be referenced.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Exercise 1.<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>On the log shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=1573&order=0','0')'>Figure 1</a> , read the maximum SP deflection from the shale line to the sand line.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-size:10pt'>Sokution 1:<br /></span></p><p><span style='font-size:10pt'>The scale in <a href='javascript:figurewin('../../asp/graphic.asp?code=1573&order=0','0')'>Figure 1</a> is 200 millivolts (mV) across the track or, for a track divided into 10 divisions, 20 millivolts per division.<br /></span></p><p><span style='font-size:10pt'>Since the deflection is 7 divisions, the deflection is equal to 20 x 7 = 140 millivolts.<br /></span></p><p><span style='font-size:10pt'>The solution is 140 mV.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><strong>Exercise 2.<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>In the example shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=1574&order=1','1')'>Figure 1</a> , determine which element is responsible for the high activity seen on the total gamma ray intensity curve at the point marked A.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Solution 2:<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Through Section A, the only element that increases notably is uranium, hence uranium is responsible for the increased GR activity in that shale.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Exercise 3.<br /></strong></span></p><p><span style='font-size:10pt'>The SP deflects 25 mV from the base line in a 4-ft-thick sand. R<sub>i</sub>/R<sub>m</sub> = 50 and d<sub>i </sub>= 30 in.<br /></span></p><p><span style='font-size:10pt'>a. Find by what percentage the SP has been reduced.<br /></span></p><p><span style='font-size:10pt'>b. Compute the corrected value for the SP.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Solution 3:<br /></span></p><p><span style='font-size:10pt'>In <a href='javascript:figurewin('../../asp/graphic.asp?code=1575&order=0','0')'>Figure 1</a> (SP correction for bed thickness) we see that the SP has been reduced 60%, or by a factor of 1.67. The theoretical value of SSP (static SP) should be<br /></span></p><p><span style='font-size:10pt'>(25 mV) (1.67) = 41.67 42 mV<br /></span></p><p><span style='font-size:10pt'>The solutions are<br /></span></p><p><span style='font-size:10pt'>a. The SP is reduced by 60%<br /></span></p><p><span style='font-size:10pt'>b. SSP = 25/0.6 = 41.7 mV<br /></span></p><p style='text-align: justify'> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-72799241321476147572008-11-20T22:00:00.001-08:002008-11-20T22:00:32.608-08:00Well Logging Tools & Techniques (Dielectric Logs)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Dielectric Logs <br /></span></h2></p><p><strong>Operating/Interpretation Principles<br /></strong></p><p><strong>Introduction <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The dielectric constant of a material affects the way in which an electromagnetic wave passes through it. Since the dielectric constants of oil and water are different, the behavior of electromagnetic waves in reservoir rocks is of interest to well loggers. Two classes of tools are available for measuring the formation dielectric constant: low-frequency tools use coils on a mandrel and operate at tens of megahertz; high-frequency tools use microwave antennae on a pad contact device. These two types will be considered separately.</span><br /> </p><p><span style='font-family:Times'><strong>EPT</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The high-frequency tool is known as the electromagnetic propagation tool (EPT). Its basic measurements are of propagation time and the attenuation of a 1.1 GHz electromagnetic wave as it passes through a specific interval of formation. As the propagation time in water is substantially higher than that in hydrocarbons, the EPT measurement is affected primarily by the water-filled porosity. Since, moreover, the propagation time in water is practically constant for most salinities, saturation estimations can be made without prior knowledge of the resistivity of the formation water. When other openhole log data are available, it is possible to distinguish between oil, gas, and water in reservoirs with unknown or changing R</span><sub>w</sub><span style='font-size:10pt'>.</span><br /> </p><p><span style='font-family:Times'><strong>Physical Principle</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>There has long been a need for a method to determine water saturation that is less dependent on knowledge of water salinity. One such method is the measurement of dielectric permittivity. Except for water, most materials in sedimentary rocks have low values (less than 8); therefore, the measured dielectric permittivity is primarily a function of the water-filled porosity. Although the dielectric permittivity of water is influenced by salinity and temperature, its range is relatively modest and very much smaller than its range of resistivity.</span><br /> </p><p><span style='font-family:Times'><strong>Measurement Principle</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The electromagnetic propagation tool is a pad-type tool ( <a href='javascript:figurewin('../../asp/graphic.asp?code=403&order=0','0')'>Figure 1</a> ) with an antenna pad attached to the body of the tool. A backup arm has the dual purpose of pressing the pad against the borehole wall and providing a caliper measurement. A standard microlog pad is also attached to the main arm allowing a resistivity measurement to be made with a similar vertical resolution to the electromagnetic measurement. A smaller arm, exerting less force, is mounted on the same side of the tool as the pad and is used to detect rugosity of the borehole. The borehole diameter is the sum of the measurements from these two independent arms.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Two microwave transmitters and two receivers are mounted in the antenna pad assembly in a borehole-compensation array that minimizes the effects of borehole rugosity and tool tilt ( <a href='javascript:figurewin('../../asp/graphic.asp?code=403&order=1','1')'>Figure 2</a> ).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The transmitter-receiver spacings of 8 cm and 12 cm are chosen to provide an optimum between several competing criteria: depth of investigation, determination of signal attenuation between receivers, and determination of phase difference in receiver signals ( <a href='javascript:figurewin('../../asp/graphic.asp?code=403&order=2','2')'>Figure 3</a> ).</span><br /> </p><p> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A 1.1 GHz electromagnetic wave is sent sequentially from each of the two transmitters, and at each of the receivers the amplitude and phase shift of the wave are measured ( <a href='javascript:figurewin('../../asp/graphic.asp?code=403&order=3','3')'>Figure 4</a> ).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The absolute values of the amplitude and phase shift are found by comparison with an accurately known reference signal generated in the tool. The phase shift, the propagation time for the wave, t</span><span style='font-size:7pt'><sub>pl</sub></span><span style='font-size:10pt'>, and the attenuation A, over the receiver-receiver spacing, are calculated from the individual measurements. In each case, an average is taken of the measurements derived from the two transmitters. A complete borehole-compensated measurement is made sixty times per second; measurements are accumulated and averaged over an interval of either 2 or 6 in. of formation prior to recording on film and tape.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Due to the close proximity of the receivers to the transmitters, spherical waves are measured; therefore, a correction factor is applied to the measured attenuation so that the plane wave th cry may be used. The increased attenuation due to the spherical spreading of the wave is compensated for by applying a spherical loss correction factor SL. The corrected attenuation, A</span><span style='font-size:7pt'>c</span><span style='font-size:10pt'>, is given by A</span><span style='font-size:7pt'>c</span><span style='font-size:10pt'> = A - SL. In air, SL has a value of about 50 db, but, because the term is porosity dependent, a more exact approach can be taken when correcting downhole measurements:</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>SL = 45.0 + 1.3 t</span><span style='font-size:7pt'><sub>pl</sub></span><span style='font-size:10pt'> + 0.18t</span><span style='font-size:7pt'><sub>pl</sub></span><span style='font-size:10pt'>2</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The formation dielectric parameters can then be obtained from the log data, since the attenuation factor, a, is directly proportional to the recorded attenuation, A, and the phase shift, b, is proportional to the propagation time</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>T</span><span style='font-size:7pt'><sub>pl</sub></span><span style='font-size:10pt'> (<span style='font-family:Symbol'><strong></strong></span>= t</span><span style='font-size:7pt'><sub>pl</sub></span><span style='font-size:10pt'>).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The basic data available from the EPT sensors are T</span><span style='font-size:7pt'><sub>pl</sub></span><span style='font-size:10pt'> and A. A separate tool section provides microlog and caliper measurements. A standard log presentation is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=403&order=4','4')'>Figure 5</a> over an interval containing two sandstones (168-179 m and 202-207 m) separated by shale. Track 1 contains the borehole diameter (HD) and the micronormal (MNOR). The microinverse (MINV) resistivity curves, electromagnetic wave attenuation (EATT), and propagation time (TPL) are recorded in Tracks II and III. The measurement of the smaller caliper arm (SA) can be displayed to monitor the borehole rugosity, and hence the quality of the EPT data.<strong><br /> </strong></span></p><p><br /> </p><p><br /> </p><p><strong>Interpretation Methods</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The EPT measurement responds more to the water of a formation than to the matrix or any other fluid. The water present in a formation can be the original connate water, mud filtrate, or bound water associated with shales. Because of the shallow depth of investigation of the tool (1 to 6 in.), it can usually be assumed that only the flushed zone is influencing the measurement, hence the free water is filtrate.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Under normal circumstances, if fresh muds are used, the propagation time of the electromagnetic waves is essentially unaffected by the water salinity ( <a href='javascript:figurewin('../../asp/graphic.asp?code=403&order=5','5')'>Figure 6</a> ). An increase in salinity increases the loss factor </span><span style='font-family:Symbol'></span><span style='font-size:10pt'>" and decreases the permittivity</span><span style='font-family:Symbol'></span><span style='font-size:10pt'>", but the effects tend to cancel each other out. If salt-saturated fluids are encountered, the loss factor increases to the extent that the electromagnetic waves are highly attenuated, and therefore measurements are more prone to error.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The EPT measurements are unaffected by mudcake up to a thickness of about 0.4 in., but rugosity can result in spurious readings as mud comes between the antenna pad and the formation. The situation deteriorates further in boreholes filled with air or oil, where even a thin film of the fluid results in the tool responding only to the fluid and not to the formation. The tool works well, however, in emulsion and inverse emulsion muds.</span><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><strong><span style='font-family:Times'>Porosity from Travel Time (</span>t<sub>po</sub><span style='font-family:Times'> Method)</span></strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The most-used relationship to convert travel time to porosity is a weight-average relationship similar to that used in density logging.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Travel time of microwaves in clean, porous media is given by the sum of the travel times through the component parts:</span><br /> </p><p style='margin-left: 36pt'>t<sub>po</sub>2 = t<sub>pl</sub>2 - Ac2/3604 <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='margin-left: 36pt'>t<sub>po</sub> = t<sub>pf</sub> + (1 - ) t<sub>pm</sub><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Solving for the porosity,</span><br /> </span></p><p style='margin-left: 36pt'>= (t<sub>po</sub> - t<sub>pm</sub>) / (t<sub>pf</sub> - t<sub>pm</sub>)<br /></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where:</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS; font-size:10pt'>Ac = the attenuation corrected for spreading loss <br /></span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>t</span><span style='font-size:7pt'><sub>po</sub></span><span style='font-size:10pt'> = the loss-free travel time of the medium, ns/m</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>t</span><span style='font-size:7pt'><sub>pl</sub><br /> </span><span style='font-size:10pt'>= the measured travel time of the medium, ns/m</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>t</span><span style='font-size:7pt'><sub>pm</sub></span><span style='font-size:10pt'> = the travel time of the rock matrix, ns/m</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>t</span><span style='font-size:7pt'><sub>pf</sub><br /> </span><span style='font-size:10pt'>= the travel time of the fluid in the pores, ns/m</span><br /> </p><p><span style='font-family:Arial Unicode MS; font-size:10pt'>The t<sub>pl</sub> is measured by the tool, then the following may be calculated: <br /></span></p><p style='margin-left: 36pt'>t<sub>po</sub>2 = t<sub>pl</sub>2 - Ac2/3604<br /></p><p>Once t<sub>po</sub> is determined, the rest of the equations can be computed to obtain porosity (<span style='font-family:Symbol'></span>). <br /></p><p style='text-align: justify'><span style='font-size:10pt'>At the wellsite, a computation program computes the water volume from the EPT measurement using the t</span><span style='font-size:7pt'><sub>po</sub></span><span style='font-size:10pt'> method and gives the amount of moved hydrocarbon.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Another method compares the EPT porosity with the total porosity measured by the neutron, density, and acoustic tools. This allows a quick-look determination of the water saturation in the flushed zone. <a href='javascript:figurewin('../../asp/graphic.asp?code=403&order=6','6')'>Figure 7</a> is an example comparing the sonic porosity with the EPT porosity.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The sonic porosity (SPHI) and EPT porosity (EMCP) are displayed in Tracks II and III, and the computed gamma ray (CGR) and total gamma ray (SGR) are recorded in Track I. There is a change of lithology at 245 m, with a limestone above this depth and a sandstone with calcareous cement below. The limestone and lower section of the sandstone are water bearing, and the hydrocarbon content of the upper section of the sand is clearly indicated by the separation of the two porosity curves. The original oil/water contact is at 267 m, while the present contact is at 261 m. Generally, the EPT porosity reads the same as a nuclear-derived porosity in water-bearing zones and shales, but in hydrocarbon-bearing intervals the EPT porosity is less than either the total porosity or the density porosity. In gas zones, the separation between the neutron porosity and the EPT porosity is not so apparent.</span><br /> </p><p><span style='font-family:Times'><strong>Dielectric Constant Log (DCL)</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In contrast to the EPT, other dielectric logging devices ( <a href='javascript:figurewin('../../asp/graphic.asp?code=403&order=7','7')'>Figure 8</a> ) use a lower operating frequency (approximately 10 to 50 MHz) and a much longer spacing between transmitter and receiver (on the order of 3 ft). Since the tool measures formation properties beyond the invaded zone, it can be used for monitoring enhanced recovery projects where plastic pipe has been set. <a href='javascript:figurewin('../../asp/graphic.asp?code=403&order=8','8')'>Figure 9</a> shows the progress of a waterflood through repeat logs on different dates.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p><strong>Propagation of Electromagnetic Waves in Rocks</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The dielectric constant of a material affects the way in which an electromagnetic wave passes through it. Since the dielectric constants of oil and water are different, the behavior of electromagnetic waves in reservoir rocks is of interest. Based on dielectric measurements, two classes of tools currently exist: very high and not-so-high frequency tools. Several such tools are</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>electromagnetic propagation tool (EPT) (Schlumberger) <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>dielectric constant log (DCL) (Gearhart)</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>deep propagation tool (DPT) (Schlumberger)</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The first of these is a very high frequency tool, the other two not so high. They all use small antenna arrays to send electromagnetic waves through the formation.</span><br /> </span></p><p style='text-align: justify'><h2><span style='font-size:10pt'>Traditionally, the measurement of the conductivity or resistivity of a formation has been one of the main surveys performed in a borehole, primarily to determine water saturation. However, a second electrical characteristic of the formation can be measured--the dielectric permittivity. Dielectric logging devices can be used to determine formation saturations from data dependent on the dielectric permittivity. The basic measurements are of the propagation time and the attenuation of an electromagnetic wave as it passes through a specific interval of formation. As the propagation time in water is substantially higher than in the hydrocarbons or minerals, the measurement is affected primarily by the fluid-filled pore space of the rock. This is in contrast to the nuclear porosity tools, which are influenced by the total porosity. In addition, for a wide range of salinities, the propagation time in water is practically constant and so saturation estimations can be made without prior knowledge of the resistivity of the formation water. When other openhole log data are available it is possible to distinguish between oil, gas, and water in reservoirs with unknown or changing R</span><sub>w</sub><span style='font-size:10pt'>.</span><br /> </h2></p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-51664873522378469922008-11-20T21:59:00.001-08:002008-11-20T21:59:31.404-08:00Well Logging Tools & Techniques (Resistivity Logs)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Resistivity Logs<em><br /> </em></span></h2></p><p><strong>Definitions of Resistivity and Dielectric Constant <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The first logging device ever designed measured formation resistivity. It was a modification of a method previously used to detect underground resistivity anomalies associated with either geologic features or concentrations of metallic ores. <a href='javascript:figurewin('../../asp/graphic.asp?code=392&order=0','0')'>Figure 1</a> illustrates this old surface surveying method.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A voltage source sent a current through the ground between two widely spaced electrodes. The voltage drop between two other more closely spaced electrodes was used as a measure of the ground resistivity. By moving the whole electrode array across the countryside, it was possible to "map" underground features, as shown in</span><strong><br /> <a href='javascript:figurewin('../../asp/graphic.asp?code=392&order=1','1')'/></strong><span style='font-size:10pt'>Figure 2 . By rotating the whole setup through a 90</span><span style='font-family:Symbol'></span><span style='font-size:10pt'> angle and lowering it into a borehole, the electric log was born.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Since those early days, a series of improvements have resulted in five main families of resistivity tools--electric logs, induction logs, laterologs, microresistivity devices, and dielectric logs.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p><strong>Responses of Resistivity Logs</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Although the original electric logging principles were sound, their practical embodiment left much to be desired. Efforts to improve the measurement of formation resistivity have been busily pursued for the last fifty years at least. As a result, three main branches of resistivity logging have evolved: focused electric logs, induction logs, and microwave devices.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Focused electric logs </em>were a logical step up from the early (unfocused) electric logs. By adding focusing electrodes to the basic four-electrode array, the current could be "steered" in the right direction. Its modern descendant, the laterolog, uses a multiplicity of focusing electrodes both to direct current into the formation and to eliminate most of the detrimental borehole effects on electric logs. Spherical focused logs also rely on focusing electrodes.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Induction logs </em>broke the tradition of using current and voltage electrodes by introducing a system of focused coils that induce the flow of currents in the formation away from the disturbing influence of the borehole and the invaded zone.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>More recently, <em>microwave devices </em>have been built to measure the dielectric constant of the formation. Strictly speaking, they do not measure formation resistivity; however, they are usually classified as resistivity devices since their end use is the same as for resistivity devices, i.e., determination of formation fluid saturation.</span><br /> </p><p><strong>Surface Surveys</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The first logging device ever designed was used to measure formation resistivity. It was a modification of a method for detecting underground resistivity anomalies associated with either geologic features or concentrations of metallic ores.</span><br /> </p><p><strong>Borehole Measurements</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>By rotating the whole setup 90</span><span style='font-family:Symbol'></span><span style='font-size:10pt'> and lowering it into a borehole, the electric log was born. The first electric log ever run was in the pechelbronn field in France in 1927.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Since those early days, continued improvements have resulted in the development of five main families of resistivity tools:</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>electric logs <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>induction logs</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>laterologs</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>microresistivity devices</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>dielectric logs</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In addition to these, a multitude of other sensors have been developed to measure and record formation porosity, fluid content, and other physical properties of the formation.<br /></span></p><p><span style='font-family:Times; font-size:13pt'><strong>Conventional Resistivity Measurements</strong></span><br /> </p><p><span style='font-family:Times'><strong>Conventional Resistivity (ES)</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>During the first thirty years of well logging, the only resistivity logs available were the conventional electrical surveys (sometimes called old E-logs). Thousands of them were run each year in holes drilled all over the world. Currents were passed through the formation by means of current electrodes, and voltages were measured between measure electrodes.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The measured voltages provided the resistivity determinations for each device, as follows: In <a href='javascript:figurewin('../../asp/graphic.asp?code=392&order=2','2')'>Figure 3</a> , a current I flows between electrode A and electrode N in a homogeneous, isotropic medium. The corresponding equipotential surfaces surrounding the current emitting electrode A would be spheres. The voltage on electrode N situated on one of these spheres is proportional to the resistivity of the formation, and the measured voltage can be scaled in resistivity units.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Although the original electric logging principles were sound, their practical embodiments left much to be desired. Efforts to improve the measurement of formation resistivity have been busily pursued for over 60 years. As a result, three main branches of resistivity logging have evolved. They <em>are focused electric logs, induction logs, and microwave devices</em>.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Focused Electric Logs</em> The responses of conventional electrical logging systems can be greatly affected by the borehole and adjacent formations. These influences are minimized by a family of resistivity tools that use focusing currents to control the path taken by the measure current. These currents are emitted from special electrodes on the sondes.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The focusing electrode tools include the laterolog and spherically focused devices (SFL). These tools are much superior to the conventional electrical logs (ES) because they eliminate many of the detrimental borehole effects. They are also better for resolution of thin beds. Focusing electrode systems are available with deep, medium, and shallow depths of investigation.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Induction Logs</em> The induction logging tool was originally developed to measure formation resistivity in boreholes containing oil-base muds and in airdrilled boreholes. Electrode devices did not work in nonconductive muds.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Experience soon demonstrated that the induction log had many advantages over the conventional ES log when used for logging wells drilled with water-base muds. Designed for deep investigation, induction logs can be focused in order to minimize the influences of the borehole, the surrounding formations, and the invaded zone.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Microwave Devices</em> Recently, microwave devices (also called electromagnetic propagation logging) have been designed to measure the dielectric constant and the conductivity of the formation. Strictly speaking, they do not measure formation resistivity. However, they are sometimes classified as resistivity devices since the end use of their measurement is the same as for resistivity tools, i.e., determination of formation-fluid saturation.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Unfocused Electric Logs</em> The original conventional electrical logs are still used occasionally for special applications.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Spontaneous Potential</em> Very early in the development of electric logging, the spontaneous potential (SP) was discovered and put to good use.</span><br /> </p><p style='text-align: justify'><strong>Tool Response<br /></strong></p><p><strong>Philosophy of Measuring Formation Resistivity <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Whatever device is used to measure formation resistivity, there are common factors that conspire to confound these efforts. Although modern resistivity-measuring devices represent a considerable improvement over the original unfocused electric log (commonly called the old E-log), there is still plenty of room for improvement. In addition to measuring the resistivity of the undisturbed zone, R<sub>t</sub>, the tool, by its design, is influenced by the resistivities of the mud in the borehole, the adjacent beds, and the invaded zone ( <a href='javascript:figurewin('../../asp/graphic.asp?code=393&order=0','0')'>Figure 1</a> ). Thus, we cannot assume that the reading from a resistivity log represents R<sub>t</sub>. Depending on the device used, the particular circumstances of the well, and the formations logged, the actual reading nay be greater or less than R<sub>t</sub>.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>We discuss below how to recognize those cases where resistivity measurements depart radically from R<sub>t</sub>. For now, use this rule: a big contrast between the resistivity of the bed of interest and the resistivity of either the mud column or the adjacent bed is a danger signal that calls for the use of correction charts. In this context, "big" means a factor of 10 or more. Of particular note are conditions where the bed of interest is thin (say, 15 ft or less) and/or invasion is deep ( d<sub>i</sub> greater than 40 in).</span><br /> </p><p><span style='font-size:10pt'>To summarize, assume that a deep-resistivity device measures R<sub>t</sub> unless</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>R<sub>t</sub>/R<sub>m</sub> is greater than 10</span><br /> </span></li></ul><p><span style='font-size:10pt'><span style='font-family:Symbol'></span>R<sub>t</sub>/R<sub>s</sub> is greater than 10</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>hole size is greater than 12 in.</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>the bed is thinner than 15 ft</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>invasion is greater than 40 in.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>If any of these adverse conditions exists, refer to the appropriate correction chart. As will become apparent, induction logs and focused electric logs (laterologs) behave differently when faced with these problems; in many cases, what may adversely affect an induction tool can be an advantage to a laterolog, and vice versa.<br /></span></p><p><br /> </p><p><br /> </p><p><strong>Philosophy of Measuring Formation Resistivity</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Whatever device is used to measure the resistivity of the undisturbed zone (R<sub>t</sub>), three elements, individually or collectively, make measurement more difficult. They are the borehole itself, the adjacent beds, and mud filtrate invasion.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Although modern resistivity-measuring devices represent a considerable improvement over the original unfocused electric log, there is still plenty of room for improvement. When using a resistivity log, the analyst must remember that the device is not perfect, and the measurement displayed is a composite of the four items in <a href='javascript:figurewin('../../asp/graphic.asp?code=393&order=1','1')'>Figure 2</a> .</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Note that in addition to R<sub>t</sub>, the resistivity of the undisturbed zone (which is what we are trying to measure), the tool, by its design, is influenced by the resistivity of the mud in the borehole, the adjacent beds, and the invaded zone, if present.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>It is unwise to assume that the reading from a resistivity log represents R<sub>t</sub>. Depending on the device used, the particular circumstances of the well, and the formations logged, the actual reading may be greater or less than R<sub>t</sub>. In the sections that follow, we shall learn how to recognize those cases where resistivity measurements depart radically from R<sub>t</sub>. As a rule of thumb, a large contrast between the resistivity of the bed of interest and that of the mud column or the adjacent bed is a danger signal that calls for the use of correction charts. In this context a "large" contrast could be classified as a factor of 10 or more. Of particular note are conditions where the bed of interest is thin (say, 15 ft or less) and/or invasion is deep (di is greater than 40 in.).</span><br /> </p><p><span style='font-size:10pt'>By way of summary, assume that a deep resistivity device measures R<sub>t</sub> unless:</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>R<sub>t</sub>/R<sub>m</sub> is greater than 10</span><br /> </span></li></ul><p><span style='font-size:10pt'><span style='font-family:Symbol'></span>R<sub>t</sub>/R<sub>s</sub> is greater than 10</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>hole size is greater than 12 in.</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>the bed is thinner than 15 ft</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>invasion is greater than 40 in.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>If any of these adverse conditions exists, then the appropriate correction chart is called for. As will become apparent later, induction logs and focused electric logs (laterologs) behave differently when faced with these problems. What is poison to an induction tool is often an advantage to a laterolog, and vice versa.<br /></span></p><p style='text-align: justify'><strong>Tool Spacing<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION … !<br /></span></p><p><strong>Conventional Electric Logs<br /></strong></p><p><strong>Introduction<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The basic electric logging system consists of two current electrodes A and B (the ground return) and two voltage measuring electrodes M and N. These can be arranged in a variety of configurations and spacings to suit particular requirements, such as bed resolution or deep investigation. Some of these arrangements became industry standards, such as the normal and the lateral electrode spacings.<br /></span></p><p><span style='font-family:Times'><strong>Normal Devices<br /></strong></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=395&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> illustrates a normal device. Constant current is passed between electrodes A and B. The measure voltage appears between electrodes N and N. The distance AN is called the spacing. Thus, the 16-in. short-normal device has electrode A separated from electrode M by 16 in.<br /></span></p><p style='text-align: justify'> <br /> </p><p><span style='font-family:Times'><strong>Lateral Devices<br /></strong></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=395&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> illustrates a lateral device. A constant current is sent between the A and B electrodes and the measure voltage appears between the M and N electrodes.<br /></span></p><p><span style='font-family:Times'><strong>Shortcomings of conventional Devices<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>All of these old electric devices, though used for many years, were plagued with inherent shortcomings related to borehole and adjacent bed effects. Their idiosyncrasies are numerous. Students requiring further details to complete a study of old electric logs are directed to the References section at the back of the manual.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The only survivors from the early electric log are the microlog and a device known as the ULSEL, the ultra-long spacing electric log, which is a normal device with AM spacings from 100 to 1000 ft. It is used for remote sensing of one borehole from another (blowout control) or for remote sensing of resistive anomalies such as salt domes.<br /></span></p><p><strong>Laterolog: General Description<br /></strong></p><p><strong>Introduction <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>In the 1920s, Conrad Schlumberger put forward the idea of a "guarded electrode" in an attempt to improve on the electrical logs of the time that had undesirable borehole effects. His idea was not put into practice until H. G. Doll designed a working guard electrode system. From this starting point, laterologs evolved in a number of ways. The laterolog 7, which used small guard electrodes, operated on the same principle of a constant survey current (io) being "forced" into the information by bucking currents from the guard electrodes. By monitoring the voltage required to maintain the fixed current io, the formation resistivity was measured. later the laterolog 3, which used long guard electrodes, was placed in service. It was known as the conductivity laterolog, and maintained a constant voltage on the measure electrode so that current variations monitored the formation conductivity.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Today, the laterolog tool most commonly used is the simultaneous dual laterolog. It is neither a conductivity nor a resistivity laterolog, but rather a hybrid using a constant product of current and voltage (constant power). The design of this tool solved many problems associated with earlier laterologs and it is now the standard basic resistivity log for salt mud environments.</span><br /> </p><p><strong>When to Use a Laterolog</strong><br /> </p><p><span style='font-size:10pt'>laterologs should be used when the following conditions exist:</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>There is seawater or brine mud in the hole. <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>The R</span><span style='font-size:7pt'><sub>mf</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>w</sub></span><span style='font-size:10pt'> ratio is less than 3.</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Hole size is less than 16 in.</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>Furthermore, the laterolog is superior to the induction log when Rt exceeds 150 Wm2/m. It also gives a better estimate of R<sub>t</sub> than the induction log when bed thickness is less than 10 ft. <a href='javascript:figurewin('../../asp/graphic.asp?code=396&order=0','0')'>Figure 1</a> provides specifics about when to run a laterolog. This figure shows a plot of the R<sub>mf</sub> /R<sub>w</sub> ratio versus porosity (f). The laterolog is preferred for use when the crossplot of R<sub>mf</sub> /R<sub>w</sub> versus f falls on the left side of the chart. <br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Laterolog: Dual Laterolog Tool<br /></strong></p><p><strong>The Dual Laterolog Tool <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The dual laterolog tool makes two resistivity measurements: the laterolog deep (LLd) and the laterolog shallow (LLs). A microspherically focused log (MSFL) may be run in conjunction with the laterolog measurements. In addition to these resistivity measurements, auxiliary curves, such as caliper, gamma ray, and spontaneous potential curves, may be recorded. The resistivity curves are presented on a standard four-decade logarithmic scale (<a href='javascript:figurewin('../../asp/graphic.asp?code=397&order=0','0')'> Figure 1</a> ).</span><br /> </p><p style='text-align: justify'> <br /> </p><p><a href='javascript:figurewin('../../asp/graphic.asp?code=397&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> shows one version of the tool with its associated measure electrodes.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The mechanics of measuring both a deep and shallow laterolog from a single set of electrodes are handled by circuitry inside the tool. <a href='javascript:figurewin('../../asp/graphic.asp?code=397&order=2','2')'>Figure 3</a> shows the respective current paths for the lid and LLs devices. The lid uses long-focusing electrodes and a distant return electrode, while the shallow laterolog uses short focusing electrodes and a near return electrode.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=397&order=3','3')'><span style='font-size:10pt'>Figure 4</span></a><span style='font-size:10pt'> shows the current paths for the MSFL, which has five rectangular electrodes mounted on a pad carried on one of the caliper arms.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Under the normal conditions found when using a dual laterolog, the radial profile of resistivities is as shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=397&order=4','4')'>Figure 5</a> ; i.e., R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'> > R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'> > R</span><span style='font-size:7pt'><sub>m</sub></span><span style='font-size:10pt'>. Between the invaded zone and the undisturbed formation is a transition zone with a resistivity value between R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'> and R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>If a horizontal slice were made through the tool and its surrounding formation and examined in plan view, the image in <a href='javascript:figurewin('../../asp/graphic.asp?code=397&order=5','5')'>Figure 6</a> would be seen. Here the current is flowing radially outward from the tool and has to pass through the mud, the invaded zone, and the undisturbed formation before arriving at the return electrode. The current, if held constant, thus develops a series of voltage drops across each zone encountered. The relationship between these voltages may be simplistically expressed as</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:14pt'>V<sub>total</sub> = V<sub>mud</sub> + V<sub>invaded</sub> + V<sub>undisturbed</sub><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Each voltage drop is proportional to the product of the current, the resistivity of the zone, and some geometrical constant, depending on the size of the zone.<br /></span></p><p style='text-align: justify'><br /> </p><p><br /> </p><p><strong>Dual Laterolog "Fingerprints"</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The characteristic behavior of the DLL tool in zones with movable hydrocarbons makes quick-look interpretation very simple. The golden rule is that the pattern in which R</span><span style='font-size:7pt'><sub>LLD</sub></span><span style='font-size:10pt'> > R</span><span style='font-size:7pt'><sub>LLS</sub></span><span style='font-size:10pt'> > R</span><span style='font-size:7pt'><sub>MSFL</sub><br /> </span><span style='font-size:10pt'>is a good indication that hydrocarbons are present, and conversely, the pattern in which R</span><span style='font-size:7pt'><sub>MSFL</sub></span><span style='font-size:10pt'> > R</span><span style='font-size:7pt'><sub>LLS</sub></span><span style='font-size:10pt'> > R</span><span style='font-size:7pt'><sub>LLD</sub></span><span style='font-size:10pt'> is a good indication that the zone is wet ( <a href='javascript:figurewin('../../asp/graphic.asp?code=397&order=6','6')'>Figure 7</a> )</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Any relative ordering of the curves other than the two cases above suggests little or no invasion and indicates that the zone is impermeable ( <a href='javascript:figurewin('../../asp/graphic.asp?code=397&order=7','7')'>Figure 8</a> ).</span><br /> </p><p style='text-align: justify'><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><strong>Log Quality Control</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Deep and shallow laterolog curves should read the same in impermeable formations (shales and evaporites). In porous and permeable zones, some separation between the two laterolog curves is to be expected, depending on the invasion diameter and the ratio of R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'> to R</span><span style='font-size:7pt'><sub>t</sub><br /> </span><span style='font-size:10pt'>.<br /></span></p><p style='text-align: justify'><strong>Laterolog Corrections</strong><br /> </p><p><strong>Borehole and Invasion Corrections <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Borehole corrections to the raw data may be necessary. Charts are available from wireline service companies to make such corrections.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The MSFL, a pad contact device, is sensitive to mudcake thickness (h</span><span style='font-size:7pt'>mc</span><span style='font-size:10pt'>) and mudcake resistivity (R</span><span style='font-size:7pt'>mc</span><span style='font-size:10pt'>).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the range of normal interest, when laterolog readings lie in the range of 10 < (R</span><span style='font-size:7pt'><sub>LL</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'>m</span><span style='font-size:10pt'>) < 100, all corrections are within ±10%. where hole diameters are large, however, the LLs correction can become intolerably large.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Once raw log readings have been corrected for borehole effects, they may be corrected for invasion effects, using what is commonly known as a "butterfly chart" ( <a href='javascript:figurewin('../../asp/graphic.asp?code=398&order=0','0')'>Figure 1</a> ). This chart plots the ratio of R</span><span style='font-size:7pt'><sub>LLD</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>LLS</sub></span><span style='font-size:10pt'> against the ratio of R</span><span style='font-size:7pt'><sub>LLD</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>. There are three families of lines on the chart. They are constant values of R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>LLD</sub></span><span style='font-size:10pt'> constant values of R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>, and constant values of d<sub>i</sub>.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In order to use the chart, it is first assumed that (R<sub>MSFL</sub>)</span><span style='font-size:7pt'><sub>cor</sub></span><span style='font-size:10pt'> is equal to R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>. A point is then located on the chart at the coordinates R</span><span style='font-size:7pt'>LLD</span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'>LLS</span><span style='font-size:10pt'> and R</span><span style='font-size:7pt'>LLD</span><span style='font-size:10pt'>/R<sub>MSFL</sub>. This point uniquely defines the three unknowns: R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'>, R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>, and d</span><span style='font-size:7pt'><sub>i</sub></span><span style='font-size:10pt'>.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The lower left portion of the chart corresponds to the invasion pattern R<sub>MSFL</sub> > R</span><span style='font-size:7pt'>LLS</span><span style='font-size:10pt'> > R</span><span style='font-size:7pt'>LLD</span><span style='font-size:10pt'> , which usually occurs in water-saturated zones where R</span><span style='font-size:7pt'><sub>mf</sub><br /> </span><span style='font-size:10pt'>> R</span><span style='font-size:7pt'><sub>w</sub></span><span style='font-size:10pt'>.</span><br /> </p><p style='text-align: justify'><strong>Laterologs Anomalies<br /></strong></p><p><strong>Anomalous Laterolog Behavior <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>The early laterologs were prone to various types of anomalous behavior, which are chronicled here to give some insight into the few anomalies that can still occur, even with the dual laterolog.</span><br /> </p><p><span style='font-family:Times'><strong>The Delaware Effect</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the early 1950s in the Permian basin, logging engineers found that laterologs behaved anomalously when approaching a thick resistive bed, such as the massive anhydrite and salt that overlies the Delaware sand. <em>The effect manifested itself by a gradual increase in apparent resistivity, starting when the bridle entered the highly resistive bed.</em> Apparent resistivities would climb to as much as 10 times the value of R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'> before the sonde itself entered the highly resistive bed. The solution for the laterolog 7 was to place the B return electrode at the surface. For the conductivity laterolog, the solution was not so easy, since these devices were using a 280 Hz survey current generated in the cartridge. Having the return at the surface did not solve the problem, since skin effect restricted the return current to a sheath around the borehole, thus resulting in the effective return electrode as the lower part of the cable ( <a href='javascript:figurewin('../../asp/graphic.asp?code=399&order=0','0')'>Figure 1</a> ).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Compensation for this effect with the Laterolog 3 involved a messy setup, with two sondes, one on each side of a cartridge, and a B return electrode on the bottom for Delaware situations. However, for all practical purposes, the laterolog 3 remains susceptible to the Delaware effect.</span><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>The Anti-Delaware Effect</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In an attempt to improve on the situation and provide a dual spacing laterolog, a tool was introduced with both deep and shallow devices. However, this device also behaved anomalously beneath highly resistive beds. <em>The deep laterolog showed a gradient of decreasing resistivity, the exact opposite of the Delaware effect.</em> With the B electrode at surface (effectively at zero potential), the N electrode acted as the takeoff point of a potential divider formed by the borehole below and above N; thus the approaching sonde, at some positive potential, would cause N to raise its potential. The anti-Delaware effect would at worst cause a 50% reduction in the deep laterolog and would only be noticeable within 35 ft of the resistive bed. In fact, the effect had been present on the earlier B electrode at surface, Delaware-free laterologs, but it had not been noticed since there was no shallow laterolog with which to compare the deep laterolog.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The dual laterologs in use today have incorporated features that assure virtual freedom from Delaware and anti-Delaware effects. However, a new effect has been observed on the dual laterolog, again associated with highly resistive beds.</span><br /> </p><p><span style='font-family:Times'><strong>The Groningen Effect</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The Groningen effect, first observed in the course of logging gas wells in Holland, manifests itself as the lid reading too high when the N electrode enters a highly resistive bed. From <em>a distance of AN below the bed boundary (about 102 ft), the LLd will rise over a short distance to an anomalously high value, which it will then maintain until the bed is entered.</em> Experiments have indicated that the effect depends on the operating frequency, and is only trouble-some in low-resistivity formations immediately below a massive salt or anhydrite bed. Modern laterolog devices can detect and correct for the Groningen effect.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The Groningen effect appears (if at all) within 102 ft (31 m) of a resistive bed and will be of interpretive importance only where R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'> in the underlying bed is less than 10 <span style='font-family:Symbol'></span>m</span><span style='font-size:7pt'>2</span><span style='font-size:10pt'>/m. It can appear even if casing is set to the bottom of the resistive bed.</span><br /> </p><p><span style='font-family:Times'><strong>Dual Laterolog "Normal" Anomalies</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Dual laterologs experience environmental effects, even if resistive bed effects do not occur. A tool has not yet been designed that is entirely free of the disturbing effects of the borehole and adjacent beds, although progress has been made in reducing these effects. For interpretive work, these environmental effects must be taken into account. The hole size and invasion effects have already been covered in the previous discussions, and another set of corrections is worth noting.</span><br /> </p><p><span style='font-family:Times'><strong>Shoulder Bed Corrections--Squeeze and Antisqueeze</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>When the sonde is in front of a bed with a resistive shoulder on either side, current tends to concentrate in the least resistive path; in other words, it is "squeezed" between the resistive shoulders into the formation of interest. Charts are available to correct for this effect. The correction factor to be applied to the borehole corrected log reading is a function of bed thickness and the contrast between the apparent reading and the shoulder resistivity R</span><span style='font-size:7pt'><sub>a</sub><br /> </span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>s</sub></span><span style='font-size:10pt'>. where this factor is less than one, a squeeze situation exists and the apparent log reading is too high. where R</span><span style='font-size:7pt'><sub>a</sub><br /> </span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>s</sub></span><span style='font-size:10pt'> is greater than one, the bed is surrounded by a <em>conductive</em> shoulder and the current tends to fan out into the path of least resistance--the conductive shoulders. Since this is the reverse of "squeezed," it is called "antisqueeze." The apparent log readings are too low in this situation.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The LLd is much more affected by squeeze and antisqueeze than is the LLs even in what might be considered thick beds (50 ft or more). When making detailed interpretations, one should use the Shoulder Bed Correction Charts for lid after borehole correction and before any other step.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Invasion corrections may then be made. A word of caution is in order. In general, an <em>ideal</em> laterolog has a depth of investigation response that behaves logarithmically with respect to invasion diameter, but it is also a function of the contrast between R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'> and R</span><span style='font-size:7pt'><sub>t</sub><br /> </span><span style='font-size:10pt'>.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Furthermore, the effect of a hole larger than 8 in. (20.32 cm) is to replace part of the R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'> zone by mud, thus changing the effective position of the origin on the invasion correction chart.</span><br /> </p><p style='text-align: justify'><strong>Induction Tools: Introduction<br /></strong></p><p><strong>Introduction<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Logging systems used before the introduction of induction logging depended on the presence of an electrically conductive fluid in the borehole to transmit electric current to the formation. In most rotary drilled wells, the drilling fluid is a water-base mud that conducts electricity. However, some wells are drilled with nonconductive fluids, such as oil-base muds, air, and gas. Under such conditions, it is impossible to obtain a satisfactory electrical log using conventional electric logging tools.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Induction logging does not depend upon physical contact between the walls of the wellbore and the logging tool. The induction logging tool acts like a transformer: the transmitter coil is energized with alternating current, which induces in the formation a secondary current that is proportional to the electrical conductivity of the formation and to the cross-sectional area affected by the energizing coil. The higher the conductivity of the formation, the lower the resistivity, and the larger the formation current will be. This current in turn induces a signal into a receiver coil, the intensity of which is proportional to the formation current and conductivity. The signal detected by the receiver coil is amplified and recorded at the surface.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The direct measurement is therefore one of conductivity. Both the conductivity and reciprocated conductivity (resistivity) curves are shown on the log. The deflections of these curves are proportional to formation conductivity. Formations having resistivities of 10, 100, or 1000 ohm-m would have conductivities of 100, 10, and 1 mmho/m, respectively.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Induction logging equipment provides a record of the formation conductivity over a wide range. The accuracy is excellent for conductivity values higher than 20 mmho/m (resistivity values less than 50 ohm-m) and is acceptable in lower conductivity ranges (down to 5 mmho/m). Beyond this limit, the induction log continues to respond to formation conductivity variations, but with diminished accuracy. There is a small uncertainty of about ±1 mmho/m on the zero of the present equipment.<br /></span></p><p><strong>When to Use an Induction Log<br /></strong></p><p><span style='font-size:10pt'>Induction logs are recommended for use when:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the hole to be logged is filled with fresh water or oil-base mud<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the hole to be logged was air drilled<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the Rmf/Rw ratio is greater than 3<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the Rt is less than 150 ½m2/m<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The induction log is the only resistivity device that works in oil-base mud (where oil is the continuous phase) or air-filled holes. The laterolog measurement is preferred when Rmf/Rw falls to the left of the vertical dashed line and to the left of the solid line for the appropriate value of Rw ( <a href='javascript:figurewin('../../asp/graphic.asp?code=400&order=0','0')'>Figure 1</a> ). The induction log is preferred above the appropriate Rw line. To the right of the dashed line and below the appropriate Rw curve, either or both logs may be required for an accurate interpretation.<br /></span></p><p style='text-align: justify'> <br /> </p><p><span style='font-family:Times; font-size:13pt'><strong>Tool Types<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Two commonly used induction tools are the single- and dual-induction devices. Each of these tools can be combined with the other sensors, thereby allowing both porosity and resistivity logs to be recorded simultaneously. <a href='javascript:figurewin('../../asp/graphic.asp?code=400&order=1','1')'>Figure 2</a> shows a typical tool string.<br /></span></p><p><span style='font-family:Times; font-size:13pt'><strong>Presentations and Scales<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Induction logs and combination induction logs are recorded on a variety of scales and presentations. The primary measurements of conductivity are always recorded on a linear scale when presented. In contrast, resistivity can be plotted on a linear or logarithmic scale. when porosity data are presented, a split grid is usually employed. <a href='javascript:figurewin('../../asp/graphic.asp?code=400&order=2','2')'>Figure 3</a> , <a href='javascript:figurewin('../../asp/graphic.asp?code=400&order=3','3')'>Figure 4</a> , and <a href='javascript:figurewin('../../asp/graphic.asp?code=400&order=4','4')'>Figure 5</a> illustrate the various possibilities.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Induction Tools: Operating Principles<br /></strong></p><p><span style='font-family:Times; font-size:13pt'><strong>Theory of Induction Devices<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Today's induction tools have many transmitter and receiver coils. The principle can be understood clearly by considering a sonde with only one transmitter coil and one receiver coil ( <a href='javascript:figurewin('../../asp/graphic.asp?code=401&order=0','0')'>Figure 1</a> ).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A high-frequency alternating current of constant intensity is sent through a transmitter coil. The alternating magnetic field created induces currents into the formation surrounding the borehole. These currents flow in circular ground loops coaxial with the transmitter coil and create, in turn, a magnetic field that induces a voltage in the receiver coil.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Because the alternating current in the transmitter coil is of constant frequency and amplitude, the ground loop currents are directly proportional to the formation conductivity. The voltage induced in the receiver coil is proportional to the ground loop currents and, therefore, to the conductivity of the formation.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The induction tool works best when the borehole fluid is an insulator, such as air or gas. The tool also works well when the borehole contains conductive mud, unless the mud is too salty, the formation too resistive (above 150 ohm-m), or the borehole diameter too large.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Calibration of the system is a two-step process. First, the tool is suspended high off the ground away from any conductive materials. Since the tool is in a zero-conductivity environment, it is adjusted to read zero conductivity (infinite resistivity). Second, a circular loop or ring of a known conductivity (known resistivity of either 1 or 2 ohm-m) is placed on the tool. The tool response is now adjusted to measure this "calibration" value.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Now, with the two end points defined and measured (the high end simulated by the tool in air and the low end simulated by the test loop), the tool is capable of measuring most normally encountered oilfield resistivity or conductivity values.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Of course, when the tool is at the bottom of a l0,000-ft well, there is no way a test loop can be placed around the sonde, so an internal calibrator is included in the tool. The calibrator will have a nominal value of 1 or 2 ohm-m; its precise value is determined monthly by reference to the test loop. These internal calibrators shift with age but behave reasonably well under normal use. A check of the zero conductivity point when the tool is in the hole is accomplished by simply opening the receiving coil. Any extraneous signal is canceled out by a zero adjustment.<br /></span></p><p><span style='font-family:Times; font-size:13pt'><strong>Skin Effect<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Linkage of each ground loop with its own magnetic field (a ground loop has self-inductance), and with the magnetic fields of the other nearby ground loops creates a cross-coupled system and the resultant eddy currents will not be quite as predictable on the basis of the theory already discussed. That is, it cannot be assumed that the individual ground loops are independent of one another. It can be predicted that, with increasing distance from the source (i.e., transmitter coil), there will be attenuation in the amount of transmitted power because<br /></span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>1. The dissipation of energy by the flow of eddy currents in the region near the source decreases the energy available for transmission to regions farther out.<br /></span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>2. Regions far from the source are shielded from the magnetic field of the transmitter coil by the annulling effect of magnetic fields of opposite sign from the eddy currents in the conductive medium closer to the transmitter. In a sense, the "shielding" of the outer regions is equivalent to a reflection of the energy back toward the source.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>As a consequence of these interactions, there is a reduction in the receiver-coil signal; i.e., a reduction in high conductivity. This reduction is commonly called a "skin effect."<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Thus, if </span><span style='font-family:Symbol'></span><span style='font-size:10pt'>g is the conductivity reading observable in a given configuration of media without skin effect and </span><span style='font-family:Symbol'></span><span style='font-size:10pt'>a is the conductivity actually observed, then the difference, </span><span style='font-family:Symbol'></span><span style='font-size:10pt'>s, is the "skin effect."<br /></span></p><p style='margin-left: 36pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>s = </span><span style='font-family:Symbol'></span><span style='font-size:10pt'>g - </span><span style='font-family:Symbol'></span><span style='font-size:10pt'>a<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>An amount </span><span style='font-family:Symbol'></span><span style='font-size:10pt'>s is added to the observed reading by means of a skin effect compensating network. It is nonlinear and can best be illustrated by <a href='javascript:figurewin('../../asp/graphic.asp?code=401&order=1','1')'>Figure 2</a> . In practical terms, the tool reads a resistivity that is too high unless the skin effect compensation is working properly.<br /></span></p><p><strong>Environmental Effects<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>In addition to the transmitting and receiving coils of the simple two-coil device ( <a href='javascript:figurewin('../../asp/graphic.asp?code=401&order=0','0')'>Figure 1</a> ), a practical field tool also includes additional focusing coils ( <a href='javascript:figurewin('../../asp/graphic.asp?code=401&order=2','2')'>Figure 3</a> ). These focusing coils make the current ground loop flow as far away from the borehole as possible to eliminate borehole and drilling-mud-filtrate invasion effects.<br /></span></p><p style='text-align: justify'><br /> </p><p><strong>Bed Thickness Corrections<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Unfortunately, a tradeoff has to be made when designing an induction tool. Good bed resolution can only be obtained with closely spaced transmitter-receiver coil arrangements, but this close spacing results in a relatively shallow radial depth of investigation. Conventional induction devices, designed for deep investigation, have poor vertical bed resolution. Effectively, the signal received is a mixture of signals from points both above and below the horizon being measured.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The surface control equipment offsets the poor bed resolution characteristic by emphasizing the zone of interest and playing down the measurement made on either side of the horizon ( <a href='javascript:figurewin('../../asp/graphic.asp?code=401&order=3','3')'>Figure 4</a> ).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The electronic circuitry used in this tool can manipulate three measurements in such a way that the reading recorded on the log is equal to a "weight" value A times the value of the interval being measured plus B times the values at points 78 inches above and below the point being measured. The values for A and B should be chosen so that A - 2B = 1. This is logical: in a homogeneous formation where all three measurements are the same, the net effect is similar to the gross effect. This scheme assists in correcting the log for the effects of adjacent beds.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The more modern phaser processing of the induction tool signals allows for enhanced bed thickness response.<br /></span></p><p><strong>Induction Current Paths<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Current loops flow around the borehole in a horizontal plane. The measured signal includes signals from the mud, the filtrate invaded zone, and the undisturbed zone. The tool "sees" three resistances in parallel ( <a href='javascript:figurewin('../../asp/graphic.asp?code=401&order=4','4')'>Figure 5</a> ).<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times; font-size:13pt'><strong>Hole Size Corrections<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The borehole effects due to the current loop in the mud can be corrected by using a special chart. The size of the correction is insignificant in fresh, resistive muds, but quite significant in salty, conductive muds.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>If an SFL</span><span style='font-size:7pt'><br /> </span><span style='font-size:10pt'>(spherically focused log) is run in conjunction</span><span style='font-size:7pt'><br /> </span><span style='font-size:10pt'>with an induction</span><span style='font-size:7pt'><br /> </span><span style='font-size:10pt'>log, a hole size correction is also needed. <a href='javascript:figurewin('../../asp/graphic.asp?code=401&order=5','5')'>Figure 6</a> is provided for this purpose. The R</span><sub>SFL</sub><span style='font-size:10pt'>/R</span><sub>m</sub><span style='font-size:10pt'> ratio is plotted against the ratio of (R</span><sub>SFL</sub><span style='font-size:10pt'>)cor to R</span><sub>SFL</sub><span style='font-size:10pt'>. The lines on the chart are for different hole sizes.<br /></span></p><p><span style='font-size:18pt'><strong><sub>Invasion Affects<br /></sub></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The radial response of the induction tool is described by the "integrated radial geometric factor," or "G." The G factor reveals which fraction of the measured signal comes from which radial distance from the tool. Mathematically, it can be described by the equation<br /></span></p><p><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>If d</span><sub>i</sub><span style='font-size:10pt'> (the diameter of invasion) is small, then G is small and all the signal comes from the undisturbed zone; in this case, R</span><sub>ID </sub><span style='font-size:10pt'>is equal to R</span><sub>t</sub><span style='font-size:10pt'>. If d</span><sub>i</sub><span style='font-size:10pt'> is large, then G also is large and a large pert of the total signal comes from the filtrate invaded zone. In this case, R</span><sub>ID</sub><span style='font-size:10pt'> reads somewhere between R</span><sub>t</sub><span style='font-size:10pt'> and R<sub>xo</sub>.<br /></span></p><p><a href='javascript:figurewin('../../asp/graphic.asp?code=401&order=6','6')'><span style='font-size:10pt'>Figure 7</span></a><span style='font-size:10pt'> shows G as a function of d</span><span style='font-size:7pt'>i</span><span style='font-size:10pt'> for the deep induction tool. This plot can be used to solve the following case. Suppose d</span><span style='font-size:7pt'>i</span><span style='font-size:10pt'> is 80 in., R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'> = 20, and Rt = 10. what will the induction tool read? From <a href='javascript:figurewin('../../asp/graphic.asp?code=401&order=6','6')'>Figure 7</a> , G for a d</span><span style='font-size:7pt'>i</span><span style='font-size:10pt'> of 80 in. is 0.4.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-size:10pt'>Therefore, the equation given above can be written as: <br /></span></p><p><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>R</span><span style='font-size:7pt'>ID</span><span style='font-size:10pt'> = 1/0.08 = 12.5<br /></span></p><p><span style='font-size:10pt'>Thus, R</span><sub>ID</sub><span style='font-size:10pt'> reads greater than R</span><sub>t</sub><span style='font-size:10pt'>.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=401&order=7','7')'><span style='font-size:10pt'>Figure 8</span></a><span style='font-size:10pt'> illustrates a typical invasion pattern with high filtrate saturation in the invaded zone and low connate water saturation in the undisturbed zone.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>We should realized that this treatment of the invasion problem is the reverse of what is encountered in the field; i.e., in practice R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>, R</span><sub>t</sub><span style='font-size:10pt'>, and d</span><span style='font-size:7pt'>i</span><span style='font-size:10pt'> are not known in advance. The objective is to find R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>, R</span><span style='font-size:7pt'>t</span><span style='font-size:10pt'>, and d</span><sub>i</sub><span style='font-size:10pt'> from the measured log values. In fact, if only the value of R</span><span style='font-size:7pt'>ID</span><span style='font-size:10pt'> is known, there is no solution to the problem. If three unknowns exist, then three known quantities are needed to solve the problem. The solution is to use the dual induction </span><sub>SFL</sub><span style='font-size:10pt'> combination logging tool. Since the geometric factor for the medium induction log (G') is different from the geometric factor for the deep induction log (G) at the same d</span><sub>i</sub><span style='font-size:10pt'>, the following three equations can be solved simultaneously:<br /></span></p><p style='margin-left: 36pt'><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>R</span><sub>SFL</sub><span style='font-size:10pt'> = f (R</span><sub>xo</sub><span style='font-size:10pt'>)<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times; font-size:13pt'><strong>Tool Calibration<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Induction tool calibration can be performed on land at any time. The sonde is placed in a zero conductivity environment. This is normally done by raising the sonde up in the air well away from metallic objects. This defines a zero point. A calibration loop is then placed around the sonde to give a known conductivity signal, usually 500 mmhos. This calibration is performed monthly. It is almost impossible to perform on an offshore rig because of the surrounding metal structure. In cases where it is not possible to set the zero point under controlled conditions at the surface, it is permissible to set it with the tool in the hole opposite a thick, very highly resistive zone (salt, anhydrite, dense low-porosity carbonate, etc.) if one exists. The sonde and its associated electronic cartridge form a matched set and should always be used together.<br /></span></p><p><span style='font-family:Times; font-size:13pt'><strong>The High-Resolution Induction<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Because of the design limitations of conventional induction tools the resulting measurements of formation resistivity are distorted by the adjacent beds, by the invaded zone, and to some extent by the borehole. Recent (mid 1980s) advances in signal processing have led to improved output from the standard dual induction hardware. These "new". induction tools are referred to as the high-resolution induction (HRI) and the phasor induction. These improvements stem from the use of both the conventional (indirect) EMF's induced in the receiver coil and the directly coupled, out of phase, ones known as the "X signals."<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The result of the additional data is a measurement of formation resistivity, which is less affected by adjacent beds and allows far better precision in correcting for invasion effects. Modern software routines allow real-time deconvolution in the logging truck and hence output of R</span><sub>t</sub><span style='font-size:10pt'>, R<sub>xo</sub> and di directly on the log.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=401&order=8','8')'><span style='font-size:10pt'>Figure 9</span></a><span style='font-size:10pt'> shows the same formation logged with (a) a conventional dual induction and (b) an HRI log. Note the improvement in bed resolution between (a) and (b).<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Microresistivity Tools<br /></strong></p><p><span style='font-family:Times; font-size:13pt'><strong>Introduction</strong></span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Microresistivity tools make measurements that have a variety of applications in well-to-well correlation, and are used to determine the following:</span><span style='font-size:7pt'><br /> </span></p><ul style='margin-left: 72pt'><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>flushed zone saturation, S<sub>xo</sub></span><span style='font-size:7pt'><br /> </span><span style='font-size:10pt'>S<sub>xo</sub></span><span style='font-size:7pt'><br /> </span><span style='font-size:10pt'><br /> </span></span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>residual oil saturation, (ROS)</span><span style='font-size:7pt'><br /> </span><span style='font-size:10pt'><br /> </span></span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>hydrocarbon movability</span><span style='font-size:7pt'><br /> </span><span style='font-size:10pt'><br /> </span></span></li><li><span style='font-size:10pt'><span style='font-family:Arial Unicode MS'>hydrocarbon density,</span><br /> <span style='font-family:Symbol'></span><span style='font-family:Arial Unicode MS'>hy</span></span><span style='font-size:7pt'><br /> </span><span style='font-family:Symbol; font-size:10pt'><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>invasion diameter, di</span><span style='font-size:7pt'><br /> </span><span style='font-size:10pt'><br /> </span></span></li><li><span style='font-family:Arial Unicode MS; font-size:10pt'>invasion corrections to deep resistivity devices<br /></span></li></ul><p><span style='font-family:Times; font-size:13pt'><strong>Microresistivity Tools</strong></span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>A variety of tools, old and new, are available. Each tool has its own special characteristics. The following list covers the majority of the microresistivity devices that are now, or have been, used extensively. These tools can be divided into two main groups: the mandrel tools and the pad contact tools.</span><span style='font-size:7pt'><br /> </span></p><p><span style='font-size:10pt'>Mandrel Tools:</span><span style='font-size:7pt'><br /> </span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>16-in. SN Short Normal</span><span style='font-size:7pt'><br /> </span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>LL8 Laterolog 8</span><span style='font-size:7pt'><br /> </span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>SFL Spherically Focused Log<br /></span></p><p><span style='font-size:10pt'>Pad Contact Tools:</span><span style='font-size:7pt'><br /> </span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>MLL Microlaterolog</span><span style='font-size:7pt'><br /> </span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>PL Proximity Log</span><span style='font-size:7pt'><br /> </span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>MSFL Microspherically Focused Log</span><span style='font-size:7pt'><br /> </span></p><p style='margin-left: 72pt'><span style='font-size:10pt'>ML Microlog<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The mandrel tools have electrodes placed on a cylindrical mandrel. Such tools do not require physical contact with the formation. In contrast, the pad contact tools have their electrodes embedded in an insulating pad carried on a caliper arm that is forced against the borehole wall.</span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>The microlog is worthy of special mention as an underrated device that should be run more frequently than it is. It was one of the first microresistivity devices on the market and has had a spectacular career. Originally, it was used as a pseudo-porosity device. When that function was improved with modern porosity devices, the microlog was relegated to the pile of has-beens by many people in the logging industry. It is still a valuable tool because it offers a superb visual identification of porous and permeable zones. <a href='javascript:figurewin('../../asp/graphic.asp?code=402&order=0','0')'>Figure 1</a> shows a microlog and proximity log presentation. The presence of permeability is indicated wherever the microinverse curve reads higher than the microinverse curve, and the microinverse curve reads close to R</span><sub>mc</sub><span style='font-size:10pt'>.</span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>The microlog records two resistivity curves with shallow depths of investigation. The microlog looks for a resistivity contrast between the mudcake and the flushed zone. If no porosity or permeability are present in the formation, there is no filtrate invasion, and thus no mudcake buildup. Hence, there is no positive separation between the two resistivity curves.</span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times; font-size:13pt'><strong>Depth of Investigation</strong></span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Each microresistivity tool has its characteristic depth of investigation. It is important to know these values for each of the tools in order to select the one with the right characteristics for the job. A tool with a shallow depth of investigation is needed if invasion is shallow and the tool is to read R<sub>xo</sub> without undue influence from Rt. Conversely, in situations where deep invasion exists, a deep investigation tool will ensure a reading of R<sub>xo</sub> free from any effects of R</span><sub>mc</sub><span style='font-size:10pt'>.</span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>As with other tools, no single value for the depth of investigation can be used. Rather, a pseudogeometric factor must be used. This factor indicates how much of the total tool signal is received from an annular formation volume represented by distances (expressed in inches) from the borehole wall ( <a href='javascript:figurewin('../../asp/graphic.asp?code=402&order=1','1')'>Figure 2</a> ).<br /></span></p><p style='text-align: justify'> <br /> </p><p><span style='font-family:Times; font-size:13pt'><strong>Bed Resolution</strong></span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Just as each of the microresistivity tools has its characteristic depth of investigation, so too does each tool have its own characteristic bed resolution; i.e., some tools are better than others at distinguishing thin beds. Tools with coarse bed resolution values are "blind" to thin shale and/or sandstone layers. For example, 3-in. shale streaks will not be "seen" by a short normal log but may easily be delineated by a microlog. By way of contrast, a shallow-focused log, depending on its electrode spacing, may be able to resolve beds 1 or 2 ft thick at best.</span><span style='font-size:7pt'><br /> </span></p><p><span style='font-family:Times; font-size:13pt'><strong>Environmental Corrections</strong></span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Microresistivity devices of the mandrel type are subject to aberrations caused by the size of the wellbore. These effects can be quite severe. The pad contact tools, however, are only affected by excessive mudcake buildup, hole rugosity, and fractures.</span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>The mudcake corrections can be made by using appropriate charts, available from the wireline service companies, that relate a correction factor to the mudcake thickness and resistivity.</span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>The mudcake thickness is calculated as half the difference between the bit size and the measured caliper reading when the caliper reads less than bit size.</span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>The mandrel-type tool corrections can be made by use of service company charts that relate the log reading, the mud resistivity (Rm), and the hole size.</span><span style='font-size:7pt'><br /> </span></p><p><span style='font-family:Times; font-size:13pt'><strong>S<sub>xo</sub> and Hydrocarbon Movability</strong></span><span style='font-size:7pt'><br /> </span></p><p><span style='font-size:10pt'>The water (filtrate) saturation in the flushed zone (S<sub>xo</sub>) may be estimated by using Archie's equation</span><span style='font-size:7pt'><br /> </span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>(S<sub>xo</sub>)n = F R</span><sub>mf</sub><span style='font-size:10pt'>/R<sub>xo <br /></sub></span></p><p><span style='font-size:10pt'>where</span><span style='font-size:7pt'> ;<br /></span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>F = a/ <span style='font-family:Symbol'></span>m<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>To solve this equation, the values of a, m, n, , R</span><sub>mf</sub><span style='font-size:10pt'>, and R<sub>xo</sub> must be known. R</span><sub>mf</sub><span style='font-size:10pt'> should be corrected for formation temperature.</span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>The value of S<sub>xo</sub> may not reveal much about the amount of oil in place, but it will reveal a great deal about whether the oil that is in place is likely to flow or not. The invasion process acts like a miniature waterflood. Invading filtrate displaces not only connate water, but also any movable hydrocarbons. In the undisturbed state at initial reservoir conditions, the fractional pore volume occupied by oil is (1 - S</span><sub>w</sub><span style='font-size:10pt'>). After filtrate invasion has taken place, the fractional pore volume occupied by oil is (l - S<sub>xo</sub>). The difference between these two values is the fractional pore volume that contained movable oil. <a href='javascript:figurewin('../../asp/graphic.asp?code=402&order=2','2')'>Figure 3</a> shows this process.</span><span style='font-size:7pt'><br /> </span><span style='font-size:10pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>The pore volume fraction of movable oil is determined by the relationship (S<sub>xo</sub> - Sw). The fraction of the original oil in place that has moved is determined by</span><span style='font-size:7pt'><br /> </span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>(S<sub>xo</sub> - S</span><sub>w</sub><span style='font-size:10pt'>) / (1 - S</span><sub>w</sub><span style='font-size:10pt'>)<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>This index can then be used as a measure of the quality of the pay. In formations where the relative permeability to oil is low, S<sub>xo</sub> is likely to be close to S</span><sub>w</sub><span style='font-size:10pt'> and the index will be low. This same formation will not be as productive as another with the same value of S</span><sub>w</sub><span style='font-size:10pt'> but better relative permeability to oil and hence a higher value of S<sub>xo</sub></span><span style='font-size:7pt'><br /> </span></p><p><span style='font-family:Times; font-size:13pt'><strong>Hydrocarbon Density</strong></span><span style='font-size:7pt'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>The computation of the hydrocarbon density in a pay zone can be critical when there is doubt about the type of hydrocarbon present; i.e., does the formation contain oil, light oil, condensate, or gas? Since the porosity tools make their measurements in the flushed zone, they "see" a bulk volume of hydrocarbon equal to (1 - S<sub>xo</sub>). This leads to the interesting paradox that where hydrocarbons are movable they will have been flushed away from the zone where they can be seen. Thus large hydrocarbon effects on porosity tools may be misleading and really only indicate large volumes of residual hydrocarbons. lack of pronounced hydrocarbon effects could mean either that movable hydrocarbons are present or the formation is wet. Either way, a good value of S<sub>xo</sub> is essential for correct prediction of hydrocarbon density and hence the type of hydrocarbon present in the formation.</span><span style='font-size:7pt'><br /> </span></p><p><span style='font-family:Times; font-size:13pt'><strong>Quality Control</strong></span><span style='font-size:7pt'><br /> </span></p><p><span style='font-size:10pt'>Quality control for these devices can be summarized by the following maxims:</span><span style='font-size:7pt'><br /> </span></p><ul style='margin-left: 72pt'><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Beware of washed-out holes because (a) pad contact tools lose contact with the formation and "float" in the mud column and (b) mandrel tools give severely inaccurate readings.</span><span style='font-size:7pt'><br /> </span><span style='font-size:10pt'><br /> </span></span></div></li><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Beware of thick mudcakes because pad contact tools require large corrections.</span><span style='font-size:7pt'><br /> </span><span style='font-size:10pt'><br /> </span></span></div></li><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>If hole conditions are bad, forget about trying to measure R<sub>xo</sub>, because either the tool will stick or the pad will tear up. Either way, no usable log reading will be obtained.<br /></span></div></li></ul><p style='text-align: justify'><span style='font-size:10pt'>It should also be noted that pad contact resistivity devices do not measure accurately in oil-base <br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><strong>Exercise 1.<br /></strong></span></p><p><span style='font-size:10pt'>a. Convert 5 ohm-m (ohm-m2/m) to millimhos.<br /></span></p><p><span style='font-size:10pt'>b. Convert 2000 millimhos to ohm-m.<br /></span></p><p><span style='font-size:10pt'>Solution 1:<br /></span></p><p><span style='font-size:10pt'>To convert from ohm-m to millimhos, divide 1000 by the resistivity value you wish to convert. For example,<br /></span></p><p><span style='font-size:10pt'>1000/5 ohm-m = 200 millimhos<br /></span></p><p><span style='font-size:10pt'>To convert from millimhos to ohm-m, divide 1000 by the millimhos value you wish to convert. For example,<br /></span></p><p><span style='font-size:10pt'>1000/2000 milimhos = 0.5 ohm-m<br /></span></p><p><span style='font-size:10pt'>The solutions are<br /></span></p><p><span style='font-size:10pt'>a. 200 millimhos/m<br /></span></p><p><span style='font-size:10pt'>b. 0.5 ohm-m<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><strong>Exercise 2.<br /></strong></span></p><p><span style='font-size:10pt'>If<br /></span></p><p><span style='font-size:10pt'>R<sub>LLD</sub> = 33 ohm-n<br /></span></p><p><span style='font-size:10pt'>R<sub>LLS </sub>= 11 ohm-n<br /></span></p><p><span style='font-size:10pt'>R<sub>MSFL</sub> = 3 ohm-n<br /></span></p><p><span style='font-size:10pt'>a. What is R<sub>t</sub>?<br /></span></p><p><span style='font-size:10pt'>b. What is d<sub>i</sub>?<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Solution 2:<br /></span></p><p><br /> </p><p><span style='font-family:Arial Unicode MS; font-size:10pt'>R<sub>LLD</sub> = 33 ohm-m <br /></span></p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>LLS</sub></span><span style='font-size:10pt'> = 11 ohm-m</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'>M<sub>SFL</sub></span><span style='font-size:10pt'> = 3 ohm-m</span><br /> </p><p><span style='font-size:10pt'>Using <a href='javascript:figurewin('../../asp/graphic.asp?code=1567&order=0','0')'>Figure 1</a> and R</span><span style='font-size:7pt'>M<sub>SFL</sub></span><span style='font-size:10pt'> = R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>,</span><br /> </p><p><br /> </p><p><br /> </p><p><br /> </p><p><span style='font-size:10pt'>Crossplot 3 and 11 to find</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'> = 15</span><br /> </p><p><span style='font-size:10pt'>d</span><span style='font-size:7pt'><sub>i</sub></span><span style='font-size:10pt'> = 40 in.</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>LLD</sub></span><span style='font-size:10pt'> = 1.4</span><br /> </p><p><span style='font-size:10pt'>Therefore,</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>LLD</sub></span><span style='font-size:10pt'> = 1.4</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'> = 1.4 R</span><span style='font-size:7pt'><sub>LLD</sub></span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'> = 1.4 (33) = 46.2 ohm-m</span><br /> </p><p><span style='font-size:10pt'>The solutions are</span><br /> </p><p><span style='font-size:10pt'>a. R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'> = 46.2 ohm-m</span><br /> </p><p><span style='font-size:10pt'>b. d</span><span style='font-size:7pt'><sub>i</sub></span><span style='font-size:10pt'> = 40 in.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Exercise 3.<br /></strong></span></p><p><span style='font-size:10pt'>If<br /></span></p><p><span style='font-size:10pt'>R<sub>ID</sub> (log reading) = 20 ohm-m<br /></span></p><p><span style='font-size:10pt'>R<sub>m</sub> = 0.1 ohm-m<br /></span></p><p><span style='font-size:10pt'>S<sub>O</sub> (Standoff) = 1.5 in.<br /></span></p><p><span style='font-size:10pt'>hole diameter (caliper) = 12 1/4 in.<br /></span></p><p><span style='font-size:10pt'>Find (R<sub>ID</sub>)<sub>cor</sub>.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Solution 3:<br /></span></p><p><span style='font-family:Arial Unicode MS; font-size:10pt'>Using <a href='javascript:figurewin('../../asp/graphic.asp?code=1568&order=0','0')'>Figure 1</a> , crossplot hole diameter versus the 1.5 standoff and find borehole geometrical factor at 0.0004, since R<sub>m</sub> = 0.1 ohm-m (10,000 millimhos). (R<sub>a</sub> = apparent resistivity.) <br /></span></p><p><span style='font-size:10pt'>10,000 0.0004 = 4 millimhos = hole signal</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>a</sub></span><span style='font-size:10pt'> = 20 ohm-m = 50 millimhos</span><br /> </p><p><span style='font-size:10pt'>50 millimhos - 4 millimhos = 46 millimhos</span><br /> </p><p><span style='font-size:10pt'>46 millimhos = 21.7 ohm-m</span><br /> </p><p><span style='font-size:10pt'>The solution is (R</span><span style='font-size:7pt'>ID</span><span style='font-size:10pt'>)</span><span style='font-size:7pt'>cor</span><span style='font-size:10pt'> = 21.7 ohm-m.</span><br /> </p><p><span style='font-size:10pt'>The hole-signal effect reduces the actual reading from 21.7 ohm-m to 20 ohm-m on the log.</span><br /> </p><p><br /> </p><p><span style='font-size:10pt'><strong>Exercise 4.<br /></strong></span></p><p><span style='font-size:10pt'>If<br /></span></p><p><span style='font-size:10pt'>R<sub>SFL</sub> = 20 ohm-m<br /></span></p><p><span style='font-size:10pt'>R<sub>m</sub> = 0.2 ohm-m<br /></span></p><p><span style='font-size:10pt'>hole size = 14 in.<br /></span></p><p><span style='font-size:10pt'>What is (R<sub>SFL</sub>)<sub>cor</sub>?<br /></span></p><p><span style='font-size:10pt'>Solution 4:<br /></span></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Using <a href='javascript:figurewin('../../asp/graphic.asp?code=1569&order=0','0')'>Figure 1</a> :</span><br /> </span></p><p><span style='font-size:10pt'>Plot R</span><span style='font-size:7pt'><sub>SFL</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>m</sub></span><span style='font-size:10pt'> = 20 versus hole size of 14 to find (R</span><span style='font-size:7pt'>SLL</span><span style='font-size:10pt'>) </span><span style='font-size:7pt'>cor</span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'>SFL</span><span style='font-size:10pt'> at 1.17.</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>SFL</sub> cor</span><br /> <span style='font-size:10pt'>= 1.17 R</span><span style='font-size:7pt'><sub>SFL</sub></span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'>= 1.17 (20)</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'>= 23.4 ohm-m</span><br /> </p><p><span style='font-size:10pt'>The solution is 23.4 ohm-m.<br /></span></p><p><br /> </p><p><span style='font-size:10pt'><strong>Exercise 5.<br /></strong></span></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Use <a href='javascript:figurewin('../../asp/graphic.asp?code=1570&order=0','0')'>Figure 1</a> to solve the following case:</span><br /> </span></p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'>ID</span><span style='font-size:10pt'> = 10.0 ohm-m</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'>IM</span><span style='font-size:10pt'> = 13.8 ohm-n</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>SFL</sub></span><span style='font-size:10pt'> = 65.0 ohm-m</span><br /> </p><p><span style='font-size:10pt'>Find the values for R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'>, R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>, and d</span><span style='font-size:7pt'><sub>i</sub></span><span style='font-size:10pt'>.</span><br /> </p><p><br /> </p><p><span style='font-size:10pt'>Solution 5:<br /></span></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Using <a href='javascript:figurewin('../../asp/graphic.asp?code=1570&order=0','0')'>Figure 1</a> ,</span><br /> </span></p><p><br /> </p><p><span style='font-size:10pt'>We plot 1.38 versus 6.5 and find that</span><br /> </p><p><span style='font-size:10pt'>d</span><span style='font-size:7pt'><sub>i</sub></span><span style='font-size:10pt'> = 50</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'> = 10</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'>ID</span><span style='font-size:10pt'> = 0.9</span><br /> </p><p><span style='font-size:10pt'>Therefore,</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>t</sub></span><br /> <span style='font-size:10pt'>= 0.9 (R</span><span style='font-size:7pt'>ID</span><span style='font-size:10pt'>)</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'>= 0.9 (10)</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'>=9</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'> = 9 ohm-m</span><br /> </p><p><span style='font-size:10pt'>Further,</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>/R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'> = 10</span><br /> </p><p><span style='font-size:10pt'>Therefore,</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>/9 = 10</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'> = (9) (10)</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'> = 90</span><br /> </p><p><span style='font-size:10pt'>The solutions are:</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>t</sub></span><span style='font-size:10pt'> = 9 ohm-m</span><br /> </p><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'> = 90 ohm-m</span><br /> </p><p><span style='font-size:10pt'>d</span><span style='font-size:7pt'><sub>i</sub></span><span style='font-size:10pt'> = 50 in.</span><br /> </p><p><span style='font-size:10pt'><strong>Exercise 6.<br /></strong></span></p><p><span style='font-size:10pt'>Apply Archie's equation to the following case to find S<sub>xo</sub>:<br /></span></p><p><span style='font-size:10pt'>R<sub>mf</sub> = 0.5 ohm-m @ 75<span style='font-family:Symbol'></span> F<br /></span></p><p><span style='font-size:10pt'>T<sub>Form</sub> = 175<span style='font-family:Symbol'></span> F<br /></span></p><p><span style='font-size:10pt'>R<sub>xo</sub> = 10 ohm-m<br /></span></p><p><span style='font-size:10pt'>F = 25<br /></span></p><p><span style='font-size:10pt'>Find S<sub>xo</sub> in %, assuming that n = 2.<br /></span></p><p><span style='font-size:10pt'>Solution 6:<br /></span></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Archie's basic formula is</span><br /> </span></p><p><br /> </p><p><span style='font-size:10pt'>Step 1: Correct R</span><sub>m<span style='font-size:7pt'>f</span></sub><span style='font-size:10pt'> for formation temperature, using the Arps formula.</span><br /> </p><p><br /> </p><p><span style='font-size:10pt'>(Where: T</span><span style='font-size:7pt'><sub>1</sub></span><span style='font-size:10pt'> = 75, T</span><span style='font-size:7pt'><sub>2</sub></span><span style='font-size:10pt'><sub><br /> </sub>= 175, and R</span><span style='font-size:7pt'><sub>1</sub></span><span style='font-size:10pt'> = 0.5 ohm-m)</span><br /> </p><p><br /> </p><p><span style='font-size:10pt'>R</span><sub>m<span style='font-size:7pt'>f</span></sub><span style='font-size:10pt'> = 0.20</span><br /> </p><p><span style='font-size:10pt'>Solving the Archie formula,</span><br /> </p><p><br /> </p><p><br /> </p><p><span style='font-size:10pt'>S</span><span style='font-size:7pt'>xo</span><span style='font-size:10pt'> = 0.71</span><br /> </p><p><span style='font-size:10pt'>The solution is S</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'> = 71%.</span><br /> </p><p><span style='font-size:10pt'><strong>Exercise 7.<br /></strong></span></p><p><span style='font-size:10pt'>If S<sub>w</sub> = 30% and S<sub>xo</sub> = 65%, what percentage of the original oil in place (OOIP) has been moved?<br /></span></p><p><span style='font-size:10pt'>Solution 7:<br /></span></p><p><span style='font-size:10pt'>If S</span><span style='font-size:7pt'><sub>w</sub></span><span style='font-size:10pt'> = 30%, then S</span><span style='font-size:7pt'><sub>hydrocarbon</sub></span><span style='font-size:10pt'> = 70% (that is, 1 - S</span><span style='font-size:7pt'><sub>w</sub></span><span style='font-size:10pt'>).</span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p><span style='font-size:10pt'>If S</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'> = 65%, then S</span><span style='font-size:7pt'><sub>hydrocarbon</sub></span><span style='font-size:10pt'><sub><br /> </sub>= 35% (that is, 1 - S</span><span style='font-size:7pt'><sub>xo</sub></span><span style='font-size:10pt'>).</span><br /> </p><p><span style='font-size:10pt'>S</span><span style='font-size:7pt'><sub>hydrocarbon</sub></span><span style='font-size:10pt'><sub><br /> </sub>has changed from 70% to 35% because of mud filtrate invasion, hence 50% of the original oil in place</span><br /> </p><p><span style='font-size:10pt'>has been flushed by the invasion of the drilling fluids.</span><br /> </p><p><span style='font-size:10pt'>The solution is % OOIP moved = 50%.</span><br /> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-4557794794039210452008-11-20T20:34:00.001-08:002008-11-20T20:34:37.096-08:00Introduction to Well Logging (The Borehole Environment)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>The Borehole Environment<br /></span></h2></p><p><strong>The Borehole Environment, Mud, Mudcake, and Invasion <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>After drilling through a permeable formation, generally an invasion process begins. If the pressure in the mud column exceeds formation pressure, fluid from the mud will move into the formation (provided it is porous and permeable) and deposit a mud cake on the borehole wall.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>It is important to distinguish between the resistivity of the fluid within the pore space and the resistivity of the rock-fluid system itself. The terms used in <a href='javascript:figurewin('../../asp/graphic.asp?code=359&order=0','0')'>Table 1</a> should be well known to everyone involved in well log evaluation work.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The flushed zone is important because it affects the readings of some logging tools and because it forms a reservoir of mud filtrate to be recovered on a drillstem test before formation fluids are recovered.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Depending on the type of mud used, oil- or water-base, and the relative values of R<sub>mf</sub> and R<sub>w</sub>, the invasion process may result in a radial resistivity profile that increases or decreases with distance from the borehole wall. <a href='javascript:figurewin('../../asp/graphic.asp?code=359&order=1','1')'>Figure 1</a> illustrates what may be expected in a number of cases.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Symbol / Nomenclature<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>A.4. Logging Tools <br /></span></h2></p><p><strong>General Description<br /></strong></p><p><span style='font-family:Times'><strong>Logging Tools</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Logging tools are cylindrical tubes containing sensors and associated electronics that can be attached to the logging cable at the logging head. Although there are wide variations in sizes and shapes, a typical logging tool is 3 5/8 in. in diameter and from 10 to 30 ft long. They are built to withstand pressures up to 20,000 psi and temperatures of 300 to 400 F. The internal sensors and electronics are ruggedly built to withstand physical abuse. Modern tools are "modularized" to allow combination tool strings. By appropriate mixing and matching, various logging sensors can be connected with each other. Among the obvious limitations to this method are the difficulty in handling very long tools and the limited information-transmitting power of the cable conductors.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Because logging tools have multiple sensors at different points along their axes, their respective measurements have to be memorized and placed on a common depth reference. Thus, the signal from the sensor highest on the tool must be "remembered" until the signal from the lowest sensor arrives from the logging depth being memorized. <a href='javascript:figurewin('../../asp/graphic.asp?code=361&order=0','0')'>Figure 1</a> and <a href='javascript:figurewin('../../asp/graphic.asp?code=361&order=1','1')'>Figure 2</a> illustrate this characteristic.<br /></span></p><p style='text-align: justify'> <br /> </p><p><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The reference point for the logging tool shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=361&order=0','0')'>Figure 1</a> is the sensor A. Higher up the tool, sensors B and C record other parameters. Without memorization, sensors B and C record curves off depth that appear on the log to be deeper than sensor A by a distance equal to the spacings A-B and A-C. It is important, therefore, to ensure that all curves recorded simultaneously are on depth on the log by means of proper memorization (<a href='javascript:figurewin('../../asp/graphic.asp?code=361&order=1','1')'> Figure 2</a> , right).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Another associated depth problem arises when several surveys are recorded on different trips into the hole. Unless care is taken, these surveys may not be on depth with each other. The only method of ensuring good depth control is to insist on a repeat section that passes a good marker bed. Each subsequent log should be placed on depth using this repeat section as a depth reference before the main logging run is made.</span><br /> </p><p><span style='font-size:10pt'>Openhole logging tools currently in use are</span><br /> </p><p><span style='font-size:10pt'><em>Formation Fluid Content Indicators</em></span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>Induction <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>Laterolog</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Microfocused and microresistivity devices</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Dielectric</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Pulsed neutron</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Inelastic gamma</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>Porosity-Lithology Indicators</em></span><br /> </span></p><ul style='margin-left: 108pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>Acoustic (sonic) <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>Density and lithologic density</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Neutron</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Natural gamma ray</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Spectral gamma ray</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>Reservoir Geometry Indicators</em></span><br /> </span></p><ul style='margin-left: 108pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>Dipmeter <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>Borehole gravimeter</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Ultra-long-spacing electric</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>Formation Texture Indicators</em></span><br /> </span></p><ul style='margin-left: 108pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>Electrical borehole imagers <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>Ultrasonic borehole imagers</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>Formation Productivity Indicators</em></span><br /> </span></p><ul style='margin-left: 108pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>Wireline formation tester <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>Production logging</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>These are the basic tools that will answer 90% of the questions about the formation. Omitted from the list are various types of old logging tools (such as electric logs), and some standard auxiliary devices, which, although important, do not rate as separate tools since they always piggy-back along with one of the basic tools. Among those auxiliary tools are the spontaneous potential (SP), and the caliper.</span><br /> </span></p><p><span style='font-size:10pt'>A discussion of common basic tools follows.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Induction Tools </em>Induct ion tools belong to the resistivity tool family and measure apparent formation resistivity. They work like mine detectors by inducing electrical currents in the formation. They may be run simultaneously with a spontaneous potential (SP) or gamma ray (GR) log (or both) and optionally with various combinations of porosity tools. Curves recorded on a dual-induction log include deep induction, medium induction, shallow-focused electric, and SP and/or gamma ray and caliper.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Laterolog Tools </em>Laterolog tools also belong to the resistivity tool family. The most important is the dual laterolog. This tool can be run with SP, GR, and caliper logs. The curves recorded are laterolog deep, laterolog shallow, and shallow-focused electric.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Microresistivity Devices </em>Microresistivity devices attempt to measure formation resistivity in the zone very close to the borehole wall where invading mud filtrate has displaced any moveable formation fluids. They are all variations of a basic microfocused electric log. When certain constraints on hole conditions are met, these devices produce a measurement of the parameter R<sub>xo</sub>, the resistivity of the flushed zone surrounding the borehole.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Acoustic Tools </em>The modern acoustic log commonly used is known as the <em>borehole compensated sonic, </em>or BHC. It may be run with a GR, SP, and caliper, or in combination with other porosity and/or resistivity-measuring devices. Long-spacing sonic tools and tools with multiple transducers are also in use for special applications.</span><br /> </p><p><span style='font-size:10pt'>The curves recorded are D (sonic travel time), GR, SP, and caliper (optional).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Various other acoustical parameters can also be recorded, either simultaneously or on a separate run. Sonic amplitude logs are used for fracture detection. They may be recorded by various arrangements of gates for the received wave trains. The tool may also be used to record the <em>cement bond log </em>(CBL), in which case the recorded curves are D (a single-receiver travel time), amplitude, and VDL (a variable-density display, or wave trains).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Density Tools </em>Compensated formation density tools are also known as gamma-gamma tools in some parts of the globe (because their mode of operation is to send gamma rays to the formation and detect gamma rays coming back).</span><br /> </p><p><span style='font-size:10pt'>They record two basic curves <span style='font-family:Symbol'></span><sub>b</sub> (bulk density) and <span style='font-family:Symbol'><sub></sub></span> (correction) .</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Natural gamma ray and caliper tools are normally run simultaneously. Additionally, an apparent porosity curve can be generated and recorded and, from those data, a formation factor (F) curve can be generated and recorded as well. A density-derived F is referred to as F<sub>D</sub>.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A variation to the density tool is known as the lithodensity tool; in addition to measuring bulk density, it measures the photoelectric factor P</span><sub>e</sub><span style='font-size:10pt'>. P</span><sub>e</sub><span style='font-size:10pt'> is a direct indicator of formation lithology and, as such, is a valuable adjunct to the basic density measurement.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Neutron Tools </em>There are several types of neutron tools. Today's standard is the compensated neutron log, which records <span style='font-family:Symbol'></span><sub>N</sub>, the neutron porosity index, normally recorded for a particular assumed lithology. Reading the porosity curve requires close attention to the porosity scale and the assumed matrix. Normally, a natural gamma ray curve is recorded simultaneously with the neutron log. The standard presentation is a combination density/neutron, where the caliper from the density survey is also available.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Pulsed Neutron Log </em>The pulsed neutron tool measures the formation capture cross section for thermal neutrons. The end result is a measurement that helps distinguish oil from salt water in the formation in cased holes.</span><br /> </p><p><span style='font-size:10pt'>The curves appearing on the log are:</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>S sigma, the formation capture cross section</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>T tau, the thermal neutron decay time</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span> ratio, a porosity-type curve.</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>Dipmeter </em>Dipmeters come in several versions: four-arm dip-meters, six-arm dipmeters, and eight-electrode types. High-resolution dipmeters record all the necessary curves for computing formation dip, hole drift, and azimuth.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Wireline Formation Testers </em>(RFT) There are several types of wireline formation testers available, which are proving to be a valuable addition to the formation evaluation arsenal. These devices allow a small sample of formation fluid to be drained from the formation and brought up for analysis. They also allow multiple formation pressure tests to be conducted during one run into the hole.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Carbon/Oxygen Logging </em>This relatively new service uses inelastic fast-neutron scattering to attempt to measure directly the relative abundance of carbon, oxygen, and other elements in a formation. Its application is in cased holes, and it is a natural candidate in those parts of the world where fresh formation waters preclude the use of a pulsed neutron-logging survey.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Gamma Ray Spectral Log </em>This service measures the number and energy of naturally occurring gamma rays in the formation and distinguishes between elements and daughter products of three main radioactive families: uranium, thorium, and potassium. Since these elements and/or their decay products are associated with certain distinct types of mineralogy, sedimentology, and formation waters, the service has obvious appeal.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Borehole Gravimeter </em>The borehole gravimeter measures perturbations in the gravitational acceleration constant caused by the proximity to the borehole of rock material that is denser or less dense than normal. Thus, this tool can spot higher porosities, gas, and the like. Its use requires an exacting set of prerequisites relating to depth, temperature, time, and so forth; it may not be available or applicable to all wells everywhere.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Dielectric Logging </em>These tools send microwaves along the wall of the wellbore. The speed and attenuation of these electromagnetic waves are measured and the dielectric constant of the formation is deduced. Oil and water, having very different dielectric constants, can be distinguished. The application is in open holes where formation waters are fresh.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Nuclear Magnetic Resonance </em>Measures the precession rate of hydrogen nuclei after the removal of an intense magnetic field. The measured quantity is related to the free fluid content of the formation. Recent advances allow determination of formation porosity, permeability, and irreducible water saturation.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In order to put these tools, surveys, and curves in perspective, the section Logging Tools: Quick Reference sets out a summary of all the common logging tools, what they measure, and their uses. Included in this catalog of common wireline logging measurements are some common interpretive presentations derived from the basic measurements.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Formation "Texture" Indicators</em> Include both electrical and ultrasonic borehole wall imaging devices that reveal near wellbore sedimentary details as well as wellbore intersections with fractures and fault planes. These devices are particularly valuable in carbonate formations where various forms of secondary porosity are imaged.</span><br /> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-90675113060730769922008-11-20T20:33:00.001-08:002008-11-20T20:33:47.538-08:00Introduction to Well Logging (Logging System)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Logging System <br /></span></h2></p><p><strong>General Description<br /></strong></p><p><span style='font-family:Times'><strong>Modern Logging Tools<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The actual running of a log involves the tool on the end of the logging cable, the cable itself, and the controlling and recording apparatus on the ground surface. Before discussing downhole tools, however, the common elements of all logs will be presented. <a href='javascript:figurewin('../../asp/graphic.asp?code=354&order=0','0')'>Figure 1</a> illustrates the basic components of any logging system. A sensor, incorporated in a downhole measurement instrument called a sonde, together with its associated electronics, is suspended in the hole by a multiconductor cable. The sensor is separated from virgin formation by a portion of the mud column, by mud cake, and, more often than not, by an invaded zone in the surrounding rock. The signals from the sensor are conditioned by the electronics for transmission up the cable to the control panel, which in turn conditions the signals for the recorder. As the cable is raised or lowered, it<strong><br /> </strong>activates a depth-measuring device-a sheave wheel, for example-which in turn activates a recording device-either an optical camera (making a film) or a tape deck (making a digital recording on magnetic tape). The film (or tape) is reproduced to provide a hard copy of the recorded data.<br /></span></p><p><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In general, well-logging jargon distinguishes between a <em>logging survey, a logging tool, </em>and a <em>log, </em>as well as a <em>curve. </em>There is frequently some confusion about these terms when logging matters are discussed. A logging <em>survey </em>is provided by a logging service company for a client. During the course of the survey, the logger may employ several different logging <em>tools, </em>and record several different <em>logs, </em>on each of which are presented several different <em>curves. </em>The logging tools, in turn, consist of multiple sensors. <a href='javascript:figurewin('../../asp/graphic.asp?code=354&order=1','1')'>Figure 2</a> illustrates these terms and their interrelationship.<br /></span></p><p style='text-align: justify'><strong>Typical Logging Setup<br /></strong></p><p><span style='font-family:Times'><strong>Rigging Up to Run a Log<br /></strong></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=355&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> shows a typical setup for a logging job. A logging truck is anchored about 100 to 200 ft from the well. Two sheave wheels are mounted in the derrick, with one suspended from the crown block and the other chained down near the rotary table. The logging cable from the truck winch is then passed over the sheave wheels, attached to the logging tool string, and lowered into the hole. A more detailed diagram of this hookup is shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=355&order=1','1')'>Figure 2</a> .<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Two mechanical details regarding this method of rigging up are worth noting. Between the top sheave wheel and the elevators a tension device measures strain on the logging cable and displays it in the logging truck (<a href='javascript:figurewin('../../asp/graphic.asp?code=355&order=2','2')'> Figure 3</a> ). The tension on the elevators is twice that on the cable. The elevators should be securely locked and the traveling block braked and chained.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The tie-down chain for the lower sheave is also of great importance. If it breaks or comes untied, the snap will probably break the cable and catapult the sheave wheel several hundred feet ( <a href='javascript:figurewin('../../asp/graphic.asp?code=355&order=3','3')'>Figure 4</a> ).<br /></span></p><p style='text-align: justify'><strong>Logging Unit<br /></strong></p><p><span style='font-family:Times'><strong>Logging Trucks<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Logging service companies offer a variety of logging units, each of which has the following components:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>logging cable<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>winch to raise and lower the cable in the well<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>self-contained 120-volt AC generator<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>set of surface control panels<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>set of downhole tools (sondes and cartridges)<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>recording mechanism (tape and/or film)<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=356&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> shows a cutaway of a typical logging truck. Land units are mounted on a specially adapted chassis reinforced to bear the load of a full winch of cable (up to 30,000 ft long). The instrument and recorder cabs are usually cramped, noisy, too hot or too cold, and sometimes filled with ammonia fumes from an ozalid copier.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Offshore units are mounted on skids and bolted (or welded) to the deck of the drilling barge, vessel, or platform.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Other units can be disassembled into many small fragments and flown into remote jungles suspended under helicopters. However, all logging units are basically similar, and require good mechanical maintenance to avoid problems during logging operations.<br /></span></p><p style='text-align: justify'><br /> </p><p><span style='font-family:Times'><strong>Logging Cables</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Modern logging cables are of two types: monoconductor and multiconductor. Monoconductor cables, with a diameter of 1/4 in., are used for completion services, such as shooting perforating guns, or setting wireline packers and plugs, and for production logging surveys, such as flowmeters and temperature logs in producing wells. Multiconductor cables, with a diameter of about 1/2 in, are used by most logging service companies for recording openhole surveys. The multiconductor cables contain 6 or 7 individual insulated conductors in the core.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The outer sheath is composed of two counterwound layers of steel wire. Such a cable has a breaking strength of between 14,000 and 18,000 lb and weighs between 300 and 400 lb per 1000 ft. It is quite "elastic" and has a stretch coefficient of around I x l0</span><sup>-<span style='font-size:10pt'>6</span></sup> ft/1b. <br /></p><p><strong>The "Head" and the "Weakpoint"</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The cable ends at the logging "head." The head anchors the cable and attaches to the logging tool by a threaded ring. Thus, the head provides both the electrical connection between the individual cable conductors and the various pins in the top of the tool and the mechanical connection. Built into the head is a "weakpoint," a short length of aircraft cable designed to break at a given tension (usually about 6000 lb, but deep-hole weakpoints are designed to break at lower tension, e.g., 3500 lb). The weak-point provides a means to free the cable from the tool when it becomes irrevocably stuck in the wellbore. Several examples follow.</span><br /> </p><p style='text-align: justify'><strong>Computerized Logging Units<br /></strong></p><p><strong>Available Systems<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Major service companies now offer logging services from computerized logging units. The advantages of using these units are many and their use is encouraged.<br /></span></p><p><strong>Features of Computerized Units<br /></strong></p><p><span style='font-size:10pt'>In contrast to conventional logging units, computer-based units offer the following features:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>All logs are directly recorded on digital magnetic tape or onto a hard disk.<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Computer control of the data gathering allows logs to be recorded either logging up or down with all curves mutually on depth.<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Calibrations are performed under programmed control more quickly and accurately than in conventional units.<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Logs can be played back from the data tapes on many different scales (both depth and response scales).<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Wellsite computation of raw data ranges from completion aids (hole volume integration for cement volumes) to dipmeter computations and complete log analysis.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=358&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> is a schematic of a computerized logging system. The logging engineer accesses the system by keyboard. At his command, the computer loads programs to perform such functions as calibration, logging, computation, and playback.<br /></span></p><p style='text-align: justify'> <br /> </p><p><strong>Calibration Methods and Tolerances<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Conventional logging units require human operation of both sensitivity and zero offset control. <a href='javascript:figurewin('../../asp/graphic.asp?code=358&order=1','1')'>Figure 2</a> depicts a typical conventional calibration system.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The variable offset resistor is adjusted when the logging sensor is at the low end of its range of measurement (for example, the caliper tool in a 6-in. ring), and the variable gain resistor is adjusted when the sensor is at the high end (e.g., the caliper tool in a 12-in. ring).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The computer units eliminate the need for human intervention, other than to place the tool to be calibrated in the correct environment (e.g., putting the 6-in. ring over the caliper arms). The data-gathering system accepts the raw uncalibrated readings of the tool and computes a calibration equation to transform raw uncalibrated data into calibrated data. <a href='javascript:figurewin('../../asp/graphic.asp?code=358&order=2','2')'>Figure 3</a> illustrates this concept.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The important things to check include the agreement between all three numbers with the specified tolerances listed in <a href='javascript:figurewin('../../asp/graphic.asp?code=358&order=3','3')'>Figure 4</a> . Note that these sets of numbers refer to Schlumberger logs. Other service company tools use different numbers. Booklets explaining calibration techniques by each logging service company can be obtained from their sales personnel.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The tolerance table of <a href='javascript:figurewin('../../asp/graphic.asp?code=358&order=3','3')'>Figure 4</a> shows that the near count rates are allowed a variation of ±22 cps and the far count rates a variation of ±14 cps. Thus, the wellsite calibration in this case can be considered good.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Exercise 1.<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Read the difference in count rates between the Before and After survey calibrations from <a href='javascript:figurewin('../../asp/graphic.asp?code=1560&order=0','0')'>Figure 1</a> for both the near and far count rates.<br /></span></p><p style='text-align: justify; margin-left: 72pt'><span style='font-size:10pt'>a. Are they within allowable tolerances?<br /></span></p><p style='text-align: justify; margin-left: 72pt'><span style='font-size:10pt'>b. What effect will the drift have in terms of changes in the logged parameter, bulk density (<span style='font-family:Symbol'></span></span><span style='font-size:7pt'>B</span><span style='font-size:10pt'>)?<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Solution 1:<br /></span></p><p><span style='font-size:10pt'>a.</span><br /> <br/> <span style='font-family:Arial Unicode MS'><br /> </span></p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:66px'/><col style='width:53px'/><col style='width:49px'/><col style='width:73px'/><col style='width:108px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt; text-decoration:underline'><strong>Before</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt; text-decoration:underline'><strong>After</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt; text-decoration:underline'><strong>Change</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt; text-decoration:underline'><strong>Tolerance</strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>FFDC</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>335</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>337</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>+2</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>±14</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.5pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>NFDC</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.5pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>526</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.5pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>529</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.5pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>+3</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.5pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>±22</span></p></td></tr></tbody></table></div><p><br /> </p><p><br /> </p><p><br /> </p><p><span style='font-size:10pt'>b.</span><br /> </p><p><span style='font-size:10pt'>-2.118 kg/m<sup>3</sup>, or</span><br /> </p><p><span style='font-size:10pt'>-2.118 l0<sup>-3</sup> gm/cc</span><br /> </p></span>Unknownnoreply@blogger.com0tag:blogger.com,1999:blog-7412479292016008933.post-10889318929876156892008-11-20T20:32:00.001-08:002008-11-20T20:32:43.206-08:00Introduction to Well Logging (Logging Procedures)<span xmlns=''><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>Logging Procedures <br /></span></h2></p><p style='text-align: justify'><strong>Logging Program<br /></strong></p><p><span style='font-family:Times; font-size:13pt'><strong>Choosing a Logging Suite</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p><span style='font-size:10pt'>A logging suite should be selected on the basis of</span><br /> </p><ul style='margin-left: 108pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>type of well--wildcat or development <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>hole conditions--depth, deviation from vertical, hole size, mud type</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>formation fluid content--(fresh or salt) connate water</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>formation type--clastic or carbonate</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>economics--rig time, logging dollars, and so forth</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Each tool is designed with a specific set of conditions in mind. Outside these limitations, the tool fails to provide the required measurement and its use is discouraged.<br /></span></p><p><span style='font-family:Times'><strong>Depth, Pressure, and Temperature Considerations</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The majority of logging tools are rated at 20,000 psi and 350</span><span style='font-family:Symbol'></span><span style='font-size:10pt'> F. These parameters are adequate for logging most holes. For higher temperatures, special tools are available from the logging service companies.</span><br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>Hole Size and Deviation</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Six inches is the standard minimum hole size for correct and safe operation of normal logging tools. Some slim-line, small-diameter tools are available for smaller-diameter holes on a limited basis.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Maximum hole diameter is difficult to define. Most pad contact tools (compensated formation density logs, microfocused logs, dipmeter, and the like) have spring-loaded, hydraulically operated arms that push the relevant sensor against the borehole wall. The arms open to about 20 in., although this limit varies a little from tool to tool. If holes are deviated, good pad contact may still be obtained, since the tool will "lean" on the low side of the hole. However, this cannot be guaranteed. Running a pad contact tool in a hole greater than 20 in. in diameter is risky because the pad may not be able to make contact with the wall of the wellbore. Similarly, tools that need to be run eccentered--for example, the compensated neutron tool--are less accurate in enlarged holes.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Resistivity devices, such as induction and laterolog, suffer in a progressive fashion as the borehole gets bigger. Theoretically, there is no fixed limit to the hole size. Practically, however, there is a limit because borehole corrections to the raw data get so large that nothing useful can be determined from the logs.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Logging of large-diameter surface holes may thus cause a problem and require logging in a purposely drilled medium-sized hole that is subsequently underreamed to the desired gauge.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In today's offshore environment, the deviated hole is the norm rather than the exception. The greater the angle of deviation from vertical, the greater the difficulties of physically getting a logging tool to the bottom of the hole. In general, hole deviation greater than 400 causes problems. A number of techniques have been tried to get logging tools safely to bottom. Among them are</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-family:Arial Unicode MS; font-size:10pt'>keeping the openhole section as short as possible</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>removal of centralizers and standoff pads</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>use of a "hole finder," a rubber snout on the bottom of the logging tool string</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>use of logging tools especially adapted to be run to the bottom of the hole on drillpipe</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In difficult situations, the hole may have to be logged through open-ended drillpipe with a slim logging tool physically pumped down by mud circulation. Using this technique, holes with deviations as high as 65</span><span style='font-family:Symbol'></span><span style='font-size:10pt'> have been logged.<br /></span></p><p><span style='font-family:Times'><strong>Logging Programs</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Logging combinations generally consist of one resistivity device and one porosity device. However, where hydrocarbon reservoirs are more difficult to evaluate, several porosity devices are needed to provide more accurate porosity data and lithology information. In addition, the reservoir engineer, the completion engineer, and the geophysicist may need additional information for evaluation and completion of the well. With the addition of computers to aid in formation evaluation, such comprehensive logging programs offer greater utilization of the measurements recorded.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>General Logging Program lists recommended logging programs for most logging situations. Mud resistivity, formation water resistivity, hole conditions, and formation types dictate the type of devices needed. The extent of the logging program is also a function of the information obtained in previous wells.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A cross-reference list of tool nomenclature of the various service companies is presented in the Reference Section under Service Company Terminology.</span><br /> </p><p><span style='font-family:Times'><strong>Influence of the Mud Program</strong></span><br /> </p><p><span style='font-size:10pt'>The mud type influences the choice of logging tool, especially the choice of resistivity tool.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Air-drilled holes, which have no conductive fluid in them, must be logged with an induction device. Likewise, holes drilled with oil can only be logged with an induction log. Where conductive fluids are in the borehole for logging operations, the choice between induction and laterolog devices is controlled by the salinities of the mud and the formation water. Fresh muds and salty formation waters favor the induction log, and salty muds favor the laterolog.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>All samples should be protected from excessive fluid losses so that porosity and saturation can be adequately determined. Bit cuttings can be sufficient to interpret lithology and determine proper constants for log evaluation formulas. Thus, the mud program should be designed for both the drilling and the logging operations.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>It is possible for a logging program to succeed or fail strictly because of the design of the mud program. For example, filtrate from a high-water-loss mud can invade a formation so deeply as to mask the measurement of true resistivity, reduce the amplitude of the spontaneous potential curve, obscure the detection of the residual hydrocarbons, and result in water recovery on a drillstem test from zones that would otherwise produce oil. Invasion of oil from oil-base or oil-emulsion muds can increase the resistivity (R<sub>xo</sub>) and decrease the water saturation (S<sub>xo</sub>) of the invaded zone. This effect would erroneously indicate the presence of oil in water-bearing formations, or reduce formation porosity values calculated from microresistivity devices.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The practice of "mudding up" just before reaching the objective zone affects interpretation when mud filtrate invades the formation beyond the radius of investigation of the resistivity device. Friable formations, as well, drilled with natural high-water-loss muds are usually badly washed out and can prevent the logging tools from going down the hole because they hang up on ledges and/or bridges. Borehole contact devices cannot obtain effective contact with the side of the borehole in highly rugose holes and will give erroneous measurements. Normally, the extent of washouts through shale is in proportion to the water loss of the muds (i.e., the higher the water loss, the larger the washouts). Since many development and semiwild cat wells are drilled with natural high-water-loss muds through the shallower formations, reliable analysis of logs through these intervals is most difficult. The decision to drill with natural high-water-loss muds through shallow formations is normally based on the erroneous assumption that the shallow formations are of no interest. However, the logs through the shallow formations are invariably consulted later to find zones for recompletion, to determine prospects for new hydrocarbon-bearing zones in the area, to locate and evaluate high-pressure zones, and for general correlation work.</span><br /> </p><p><span style='font-family:Times'><strong>Choosing When to Log</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Logs should be run just prior to the running and setting of a casing string. Once casing is set, logging choices are severely limited.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>It is recommended that logs be run (1) if hole conditions suggest that a section of hole could be "lost" (caving, washouts, etc., which would contraindicate the running of a logging tool), (2) if cuttings indicate that an unexpected formation has been encountered, and/or (3) if one is otherwise "lost" structurally.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>However, one's enthusiasm for running logs should be tempered somewhat by the economic and practical realities of service company price lists and fee structures. Each time a logging truck is called, a setup charge is assessed to cover costs of mobilization. In addition, a depth charge is assessed per foot of hole from surface to total depth. Finally, a survey charge is assessed over the actual interval logged. The full cost of a logging operation is thus, more than anything else, a function of the depth of the well. To log a l00-ft section at 10,000 ft is an expensive proposition, while a 4000-ft survey at 5000 ft total depth is probably less expensive.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Service Co. Notification<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Service Co. Mobilization<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Rig up and Pre Survey<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Running The Tool String<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Repeat Section<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Main Survey<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Post Survey<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Ringing Down<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Stuck Cable or Tools<br /></strong></p><p><span style='font-family:Times'><strong>Getting Stuck <br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>There are two ways of getting stuck. Either the tool will stick and the cable in the hole above the tool will remain free, or the tool will remain free and the cable will be stuck further up the hole above the tool. <a href='javascript:figurewin('../../asp/graphic.asp?code=371&order=0','0')'>Figure 1</a> illustrates the difference. Once the system is firmly lodged, the first thing to do is determine whether it's the tool or the cable. The standard procedure is to apply normal logging tension on the cable and let it sit for a few minutes while the following data are gathered:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the present depth of the tool<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the cable's surface tension just before getting stuck<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the cable type and size<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the cable-head weakpoint rating<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The cable is marked (using chalk or friction tape) at the rotary table, with a T-bar clamp securely positioned around the cable, just above the rotary table. If the cable should break, this clamp will hold the cable end at the surface and prevent all the cable from snaking down the hole on top of the tool.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The winch operator then applies 1000 lb of tension on the cable and measures the distance the cable mark has moved at the rotary table. This is the stretch produced in the elastic cable due to 1000 lb of extra tension. Now, the length of free cable can be estimated from a stretch chart or from knowledge of the stretch coefficient. If the length of free cable so determined proves to be the present logging depth, then the tool is evidently stuck and the cable is free. On the other hand, if the length of free cable is less than the present logging depth, then the cable itself must be stuck higher up the hole.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>In the case of the tool being stuck, pulling on the cable will achieve one of three results. The tool will pop free, the weakpoint will break (leaving the tool in the hole but saving the cable), or the cable will break at the point of maximum tension at the top sheave. Of the three, the first is to be preferred. Of the other two, the breaking of the weakpoint is preferred. But which will occur first? Will the cable part at the surface before the weakpoint breaks? <a href='javascript:figurewin('../../asp/graphic.asp?code=371&order=1','1')'>Figure 2</a> will help to explain the tensions involved.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Differential pressure sticking of the cable is caused by the cable cutting through the mudcake. One side of the cable is exposed to formation pressure while the other side is exposed to the hydrostatic mud column. This forces the cable against the formation, and the resulting friction stops any further cable movement ( <a href='javascript:figurewin('../../asp/graphic.asp?code=371&order=2','2')'>Figure 3</a> ).<br /></span></p><p><span style='font-family:Times'><strong>Alternatives to Fishing<br /></strong></span></p><p><span style='font-size:10pt'>There are several alternatives available for recovering the stuck tool and/or cable:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Leave the cable attached to the tool and run a side-door overshot.<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Use the "cut and thread" overshot technique.<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>Break the weakpoint, recover the cable, and fish for the logging tool with the drillpipe, or push it to the bottom of the hole and mill it up.<br /></span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=371&order=3','3')'><span style='font-size:10pt'>Figure 4</span></a><span style='font-size:10pt'> illustrates the different methods.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The side-door overshot is not recommended at depths greater than 3000 ft. Historically, the cut and thread technique is the surest way to recover a stuck logging tool.<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Quality Control<br /></strong></p><p><span style='font-family:Times'><strong>Purpose<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>The need for log quality control has been documented in various studies, such as the one by Neinast and Knox (1973). Poor log quality control can result in a large percentage of logs being in error. Errors made in recording logs may render them useless as formation evaluation tools.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>It is the function of the well operator's representative to ensure that the best quality logs are obtained. Service company personnel expect a representative to be available and in the logging unit during the logging operation. Logging operations should be discussed with the logging engineer before and after the job.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The most critical time during a logging operation comes when the tool is within 1000 ft of the bottom of the well. The logging engineer must not be distracted during this time, but must be allowed to perform the operation with minimum interruption.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>After each log is complete, it should be discussed with the engineer as thoroughly as possible. Ask for an explanation of any abnormal curve responses, equipment failures, or hole problems, and enter the information in the "remarks" column of the log heading. This may be done after the first print is completed but before further prints are made. If there is any question about validity, the log should be rerun before the crew rigs down. Generally, 200 ft of repeat in a relatively smooth hole should be enough to verify the log. Everyone is reluctant to go back in the hole after rigging down. However, once pipe is set, it is impossible to get another resistivity survey of any type.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>No matter how competent and conscientious an observer may be, there are ways in which bad logs can defy detection at the wellsite. To this degree log quality also depends on the competence and integrity of the logging company's engineer. Perhaps the most important objective is to develop relationships of mutual trust with the logging company personnel. Further details of log quality control procedures are available in Bateman (1984).<br /></span></p><p><span style='font-family:Times'><strong>Practical Checks<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Logs consist of two kinds of data--log data (the curves), and heading and calibration data. Remarks may be added to either. The calibrations are objective verifications of log quality. Learn what they mean and how to use them.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Depth-related log measurements include one or more repeat sections, usually about 200 ft. These records are a valuable, though not conclusive, indication of correct tool operation, and should be examined carefully on every log run.<br /></span></p><p><span style='font-family:Times'><strong>Acceptance Standards for Logs<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>Although a large percentage of logs may contain some erroneous data, it is unfair to intimate that such logs are worthless. Though a log may be corrected visually or mathematically, it sometimes must be rerun before valid conclusions can be made. The cost of rerunning the log might thus outweigh the significance of the error. When the log is not rerun, the error should be noted on the heading in the "remarks" column and also noted on the log opposite any zone of interest.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>For more serious errors, it is a mistake to think that a bad log is better than none. Since a bad log may adversely influence important decisions, it is imperative that the log be rerun. The problem, of course, is to determine whether to accept or reject a questionable log. One reliable method for determining a bad log is to ask, Is the interpretation accurate? When in doubt, rerun the log. Also ask, Can everyone who will use this log see the error and/or be able to perform an accurate interpretation? If in doubt, rerun the log.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>A clear-cut criterion for acceptance or rejection of a log is difficult to establish, as situations differ. Good judgment should outweigh written instructions when deciding whether to accept or rerun a log. The following guidelines should assist in making such decisions.<br /></span></p><p><span style='font-size:10pt'><em>Overall Technical Quality </em>The technical quality of the data may be affected by many factors:<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>equipment malfunction<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>rugose borehole<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>sticking tools<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>logging engineer's errors<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>tool rotation<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>excess logging speed<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>deviated wells<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>tool eccentricity<br /></span></p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>formation alteration<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Many times an anomaly over a logged interval may indicate the possibility of a malfunction. This should be resolved by repeating the log in that section, since the problem may be significant. It is interesting to recall that the spontaneous potential (SP) was originally an anomaly that interfered with measurement of formation resistivity.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Repeatability </em>Properly functioning resistivity tools, run under conditions that are within their capability, nearly always repeat very well. As a functional check of the equipment, a repeat section of 200 ft or more is routinely run, and should be required, except in unusual circumstances.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Aside from equipment failures, factors that could cause poor repeats include washed-out holes, particularly those of extremely noncircular cross section; variable tool centering, particularly in large holes with fairly high mud conductivities; the presence of metallic "fish" in the borehole; and comparing an up run with a down run (which may appear quite different with some types of equipment).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Repeatability with a previous log run may be affected by time-related phenomena as well, such as varying invasion profiles. Invading filtrate can penetrate deeper, migrate vertically, accumulate as "annuli," or dissipate altogether with the passage of time. The log response, particularly of the shallower-reading devices, may continue to change for many days after the well is logged. Though unusual, such changes can be very troublesome; but from )the viewpoint of log quality they are usually recognizable. The changes occur only in the invaded sections, not in the shales or other impervious rocks.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Offset Logs </em>If the well is in a developing field, available offset logs are likely to be useful, especially in an unfamiliar or geologically complex area.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Absolute Log Values </em>Comparison of log readings with known absolute values is seldom possible, but when it can be done, this positive crosscheck should be used. Formations that consist of pure, zero-porosity minerals such as halite, anhydrite, or limestone can be used to check log readings. <a href='javascript:figurewin('../../asp/graphic.asp?code=372&order=0','0')'>Table 1</a> lists these natural benchmarks for several common tools.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Casing can sometimes be used as a check. All caliper tools should read the same in casing. The diameter indicated is usually slightly greater than that of new casing due to drill-pipe wear. The two diameters measured by a four-arm caliper should be equal. The sonic should read about 56 microseconds per foot in unbonded casing.<br /></span></p><p style='text-align: justify'><br /> <span style='font-size:10pt'><em>Depth Measurements </em>Measurement of depth is perhaps the logging company's most basic function, but one that tends to get lost among the more glamorous parameters. Absolute depth control is provided either by a calibrated sheave or by magnetic marks placed on the logging cable every 100 ft. In either case, the operational procedure for obtaining accurate depth control is rather rigorous, and if followed properly will almost always result in accurate depth measurements. This is one of the places where it is advisable to be on terms of mutual trust with the logging engineer. It may be possible to detect evidence of inaccurate depth measurements, but absolute verification is very difficult.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Compare logger's TD and casing depth with those reported by the driller. Watch for excessive tie-in corrections with previous log runs and check the apparent depths of known markers.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Relative depth control means ensuring that all measurements are on depth with each other. All curves recorded on the same trip in the hole should tie in with each other, within plus or minus 6 in. In addition, each subsequent log should match the base log within 2 ft in straight holes and 4 ft in highly deviated wells (greater than 30</span><span style='font-family:Symbol'></span><span style='font-size:10pt'>).<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><em>Logging Speeds </em>The logging speed in feet per minute is indicated by gaps or ticks along the edge of the film track. Acceptable logging speeds depend on the type of log, the type of unit (computer or conventional), the intended use of the data, and the type of formation being logged. Normal routine logging speeds are given in <a href='javascript:figurewin('../../asp/graphic.asp?code=372&order=1','1')'>Table 2</a> .<br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><h2><span style='font-family:Century Gothic; font-size:12pt'>A.6. Rock and Fluid Properties <br /></span></h2></p><p><strong>Definitions <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Porosity is defined as the ratio of the void space in a rock to its bulk volume. There are two components to a porous rock system: the grain volume VG and the pore volume V<sub>p</sub>. The sum of the two gives the bulk volume VB.</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>VB = VG + VP</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Porosity is thus the ratio of VP to VB</span><br /> </span></p><p style='margin-left: 36pt'><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>It can be measured in a number of ways; for example,</span><br /> </span></p><p style='margin-left: 36pt'><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>or</span><br /> </span></p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Deriving a value of porosity depends on the mechanism of the porosity-measuring device and knowledge of any two of the three volume fractions.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Saturation is defined as the ratio of the volume of saturating fluid to the volume of the available storage space (i.e., the pore space). Thus, the water saturation of a porous system is simply given by</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where Vw is the volume of water.</span><br /> </span></p><p><span style='font-size:10pt'>Permeability is defined as the ability of a porous system to allow fluids to flow through it.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Provided flow is laminar, Darcy's relation can be used to define permeability, k, in terms of flow rate, Q; area, A; length, L; pressure differential,<strong><br /> </strong><span style='font-family:Symbol'></span>P; and fluid viscosity,<span style='font-family:Symbol'></span> such that</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>If only one fluid is present in the pore system, this relation defines absolute permeability -- i.e., a rock property independent of the fluid flowing through it.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>If Q is in cc/sec, A is in sq cm, <span style='font-family:Symbol'></span>P \ L is in atmospheres/cm, and <span style='font-family:Symbol'></span>is in centipoise, then k is in darcies. The practical unit is the millidarcy, abbreviated md, equal to 1/1000 of a darcy.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The relationship between permeability and porosity depends on rock type. In general, the log of permeability is linear with porosity for a given rock type; however, the precise relationship is found only through direct measurements of representative rock samples. <a href='javascript:figurewin('../../asp/graphic.asp?code=373&order=0','0')'>Figure 1</a> shows some of these trends</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Porosity<br /></strong></p><p><span style='font-family:Times'><strong>Introduction</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Petrophysics is the name given to the study of rock-fluid systems. It is particularly important that the log analyst he aware of the way in which rocks and fluids interact in both static and dynamic situations.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Although logging measurements are made under static reservoir conditions, the prediction of reservoir behavior under dynamic flow conditions can only be made if the physics of fluid flow is understood. The objective of this discussion, therefore, is to equip the formation evaluator with sufficient information so that log response can be related to reservoir performance, which is what really counts, rather than to just static reservoir content. Ideally, the reader will come away with a better understanding of why some reservoirs with low water saturations produce with high water cut while others with much higher computed water saturations produce water-free hydrocarbons.</span><br /> </p><p><span style='font-family:Times'><strong>The Genesis of Reservoir Rooks</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A reservoir rock is one that has both storage capacity and the ability to allow fluids to flow through it; i.e., to be of practical use it must possess both porosity and permeability. Porosity (void spaces) can develop between grains of sediments as they are laid down--for example, intergranular porosity in sandstone reservoirs. Porosity can also develop when chemicals react with rocks after they have been deposited. Typical of this solution-type porosity are carbonate reservoirs. Porosity can also develop as fractures induced by the stresses of tectonic movement. Porosity per se does not guarantee permeability. Swiss cheese, for example, is highly porous but impermeable, as the void spaces are not connected.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Porosity The porosity developed in sedimentary rocks is a function of many variables--broadly defined as rock texture--including grain shape, size, orientation, and sorting. If all the grains are of the same size, sorting is said to be good. If grains of many diverse sizes are mixed together, sorting is said to be poor.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The packing of the grains ( <a href='javascript:figurewin('../../asp/graphic.asp?code=374&order=0','0')'>Figure 1</a> ) determines the porosity. For a given sorting, porosity is independent of grain size. For example, if spheres of diameter d are packed in a cubic lattice arrangement, the porosity can be calculated by the following method.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In unit volume n<sup>3</sup> spheres are packed n to a side. The total volume is (nd)<sup>3</sup>. The volume of any one sphere is (4/3)<span style='font-family:Symbol'></span>(d/2)</span><span style='font-size:7pt'><sup>3</sup></span><span style='font-size:10pt'>, so the volume occupied by n</span><span style='font-size:7pt'><sup>3</sup></span><span style='font-size:10pt'> spheres is (4/3)<span style='font-family:Symbol'></span>(nd/2)</span><span style='font-size:7pt'><sup>3</sup></span><span style='font-size:10pt'>. Thus the porosity is</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>which simplifies to (1 -<span style='font-family:Symbol'></span> /6) or 0.4764. Note that the term d cancels out and is not a determining factor.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Cubic packing is not an efficient way to store spheres in a box. Nature seeks more compact packing mechanisms, such as rhombohedral packing, which produces a porosity of 25.95% (versus 47.64% for cubic packing).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>For a given grain size, porosity decreases as sorting gets poorer, since intergranular pores may be occupied by eversmaller grains.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Quite apart from the mechanics of how sand grains are packed is the question of their compaction with regard to depth of burial. Porosity decreases with increasing depth in a predictable manner. A relationship of the sort</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>generally fits most normally pressured reservoirs; i.e., the log of porosity is linear with depth. For example, if </span><span style='font-family:Symbol'></span><span style='font-size:7pt'>fo</span><span style='font-size:10pt'> , the porosity at surface, is 45% and depth is in feet, then a typical value of a might be 12,000, resulting in a porosity of 12.9% at 15,000 ft and 8.5% at 20,000 ft.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Permeability while porosity is a static property of a rock, permeability is a dynamic one. Permeability is a measure of the ability of a rock to allow fluids to flow through it. Provided the flow is laminar, Darcy's relation can be used to define permeability (k) in terms of flow rate (Q), area (A), length (L), pressure differential (<span style='font-family:Symbol'></span>P), and fluid viscosity (µ), such that,</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>If only one fluid is present in the pore system, then this relation defines absolute permeability; i.e., it is a rock property independent of the fluid flowing through it. If Q is in cc/sec, A is in sq cm, <span style='font-family:Symbol'></span>P/L is in atmospheres/cm, and µ is in centipoise, then k is in darcies. The practical unit is the millidarcy, abbreviated md, equal to one-thousandth of a darcy.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The relationship between permeability and porosity depends on rock type. In general, the log of permeability is linear with porosity for a given rock type. However, the precise relationship is found only through direct measurement of representative rock samples. <a href='javascript:figurewin('../../asp/graphic.asp?code=374&order=1','1')'>Figure 2</a> shows some of these trends.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>over the years various investigators have developed theoretical relationships between permeability and porosity, taking into account the textural features such as the size, shape, and distribution of pore channels in the rock. Among these is the Carmen relationship,</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>k=<span style='font-family:Symbol'></span></span><span style='font-size:7pt'>3</span><span style='font-size:10pt'> / C(As)</span><span style='font-size:7pt'><sup>2</sup></span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where C is the Kozeny constant and As is internal surface area per unit bulk volume.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>For fracture systems, generalized formulas have been developed relating the permeability to the square of the fracture width.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In some reservoirs, permeability is a vector; i.e., it takes on directional properties. Depositional effects may tend to align grains along their long axis, increasing the permeability in that direction. Vertical permeability may also be different from horizontal permeability. In fractured reservoirs permeability is likely to be highly directional, depending on the azimuth of the fracture planes.</span><br /> </p><p><span style='font-family:Times'><strong>Summary</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The conduction of electric current through a porous rock is conceptually similar to the flow of fluid through the rock. Thus, measurement by wireline tools of formation conductivity is related to formation porosity, permeability, and fluid saturation. By combining the basic relationships established by Archie with the physics of fluid distribution and flow in a reservoir, the analyst may estimate productivity from the free-water level, the length of the transition zone, and the irreducible water saturation.</span><br /> </p><p><span style='font-family:Times'><strong>Definitions of Porosity and Effective Porosity</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The porosity of a formation is commonly defined as the volume of the pore space divided by the volume of the rock containing the pore space. This definition of porosity ignores the question of whether the pores are interconnected or not. Swiss cheese, for example, is quite porous, but is of very low permeability since the void spaces are not interconnected. Inter granular porosity that is interconnected is <em>effective </em>porosity. Pores that are blocked in some way (by clay particles, silt, etc.) are <em>ineffective. </em>Thus a preferred definition gives total porosity (<span style='font-family:Symbol'></span><sub>T</sub>) as the volume of the pores divided by the volume of rock, and effective porosity (<span style='font-family:Symbol'></span><sub>e</sub><span style='font-family:Symbol'></span> as the volume of <em>interconnected </em>pores divided by the volume of rock. <a href='javascript:figurewin('../../asp/graphic.asp?code=374&order=2','2')'>Figure 3</a> illustrates this concept.<br /></span></p><p style='text-align: justify'><br /> <span style='font-size:10pt'>Porosity is expressed as a fraction of the bulk volume of the rock. The normal convention in reservoir engineering is to express porosities in percentage units; e.g., a porosity of 0.3 is referred to as 30% porosity. However, another term frequently used is <em>porosity unit, </em>or P.U. By using <em>unit </em>rather than <em>percentage, a </em>lot of confusion is avoided, as, for example, in comparing a 20 P.U. sandstone with a 25 P.U. sandstone. The latter is 5 P.U. higher than the former. This negates the confusion caused by saying one is 5% (or 25%) better than the other.</span><br /> </p><p><span style='font-family:Times'><strong>Types of Porosity</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Porosity may develop in a formation by a variety of mechanisms. Where pores are uniformly distributed throughout the bulk rock, the porosity is referred to as <em>matrix porosity. </em>Where the only storage space in the rock system is in cracks and fissures in an otherwise zero porosity matrix, the porosity is referred to as <em>fracture porosity. </em>A third type of porosity may coexist with either of the other types in the form of vugs, and is referred to as vuggy porosity.</span><br /> </p><p><span style='font-family:Times'><strong>Matrix Porosity</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Matrix porosity is common in sandstone and other granular rock formations. The physics of the porosity measurement is unaffected by the manner in which the void spaces were created; i.e., it is not important whether the porosity was originally created by sedimentation of individual grains or by leaching by acidic solution after deposition. Thus, individual logging tools cannot tell directly the type or origin of the matrix porosity in a rock sample. Petrographic analysis of cores is required for that kind of information.</span><br /> </p><p><span style='font-family:Times'><strong>Fracture Porosity</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Fracture porosity is unevenly distributed throughout the rock. It appears normally as near-vertical cracks, or fractures, whose orientation depends on the azimuth of the stresses in the formation. Not all logging tools respond to fracture and/or vuggy porosity in the same manner. Thus, it is sometimes possible to distinguish fracture and/or vuggy porosity from matrix porosity with judicious use of a combination of porosity-measuring devices and careful analysis of the results.</span><br /> </p><p style='text-align: justify'><strong>Absolute Porosity<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p><span style='font-family:Times'><strong>Relative Permeability</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>If only one fluid is present in a pore system, fluid flow is nicely governed by Darcy's law. If two or more fluids are present together in a pore system, the dynamic behavior of the individual phases is not quite so straightforward. Consider the case of oil and water together in a pore system. The <em>effective</em> permeability is defined as the permeability to a particular phase at a particular saturation. Thus, if, under a given pressure gradient, oil and water flow through a pore system together, we find that</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>and</span><br /> </span></p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Furthermore, we find that the total flow rate Q<sub>t</sub> = (Q<sub>o</sub> + Q<sub>w</sub>) is less than the flow rate either phase would have if it were at 100% saturation. Thus it appears as though the two phases interfere with each other's progress through the pore system.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>A useful way to quantify this phenomenon is to define the relative permeability, k<sub>r</sub>. This is the ratio of the effective permeability of the rock to one phase divided by the absolute permeability, and it is quoted at some particular saturation value.</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>k<sub>ro</sub> = k<sub>r</sub>/k</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>k<sub>rw</sub> = k<sub>w</sub>/k</span><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=376&order=0','0')'><span style='font-family:Arial Unicode MS; font-size:10pt'>Figure 1</span></a><span style='font-family:Arial Unicode MS; font-size:10pt'> shows typical relative-permeability curves. Several things are worth noting. Relative permeability to oil at irreducible water saturation is 100% or 1, and as water saturation increases, k<sub>ro</sub> decreases until it effectively reaches zero at some high water saturation corresponding to S<sub>or</sub>, the residual oil saturation.<br /></span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>Relative permeability to water, on the other hand, commences effectively at zero when the rock is at S<sub>wi</sub> and thereafter increases as S<sub>w</sub> increases. It should also be noted that in an oil-wet system k<sub>ro</sub> is always less, at a given S<sub>w</sub>, than in a water-wet system. Conversely, k<sub>rw</sub> is always greater in an oil-wet system than in a water-wet one. <br /></span></p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A common way of representing these differences is a plot of the relative permeability ratio, k<sub>rw</sub>/k<sub>ro</sub>, versus water saturation, S<sub>w</sub>. <a href='javascript:figurewin('../../asp/graphic.asp?code=376&order=1','1')'>Figure 2</a> shows that in water-wet systems the relation is such that if the k<sub>rw</sub>/k<sub>ro</sub> ratio is on a log scale and S<sub>w</sub> on a linear one, a straight line is obtained. In an oil-wet system an S-shaped line is observed.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>When plotting relative permeability curves, the distinction is usually made between two possible scenarios: <em>imbibition</em> and <em>drainage</em>. Imbibition refers to the case in which the wetting fluid is increasing in saturation. For example, in a water-wet reservoir a rise in the water table subjects the transition zone to imbibition of water. Drainage refers to the case in which the wetting fluid saturation is decreasing, as, for example, when oil first migrates into a water-wet rock. The difference between the two sets of relative permeability curves reflects the saturation history and the trapping of the nonwetting phase that occurs after it has been imbibed. <a href='javascript:figurewin('../../asp/graphic.asp?code=376&order=2','2')'>Figure 3</a> illustrates these different cases.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Many workers in this field have proposed generalized empirical equations to relate k<sub>ro</sub> and k<sub>rw</sub> to S<sub>w</sub>, S<sub>wi</sub>, and S<sub>or</sub> Of particular note are those cited in Honarpour, Koederitz, and Harvey 1982, Molina 1983, and Pirson, Boatman, and Nettle 1964. A commonly used approximation gives</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>If a well is completed above the transition zone where the reservoir is at irreducible water saturation (i.e., k<sub>rw</sub> = 0), water cannot be produced. However, if completion is contemplated in the transition zone, it is helpful to know in advance what water cut may he expected. Fortunately this can be calculated as follows:</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-size:10pt'><span style='font-family:Arial Unicode MS'>The oil-flow rate is</span> Q<sub>o</sub> = k<sub>o</sub> • <span style='font-family:Symbol'></span>P • A/µ<sub>o</sub> • L</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>The water-flow rate is Q<sub>w</sub> = k<sub>w</sub> • <span style='font-family:Symbol'></span>P • A/µ<sub>w</sub> • L</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Thus the water-oil ratio is given by</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>WOR = k<sub>w</sub> µ<sub>o</sub>/k<sub>o</sub> µ<sub>w</sub></span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The ratio k<sub>w</sub>/k<sub>o</sub> is numerically equivalent to k<sub>rw</sub>/k<sub>ro</sub>, which can be deduced from measured relative permeability ratios or estimated from one of the generalized correlations.</span><br /> </span></p><p><span style='font-size:10pt'>The actual water cut of the production into the wellbore is given by</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>WC = Q<sub>w</sub>/(Q<sub>w</sub> + Q<sub>o</sub>)</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>which is equivalent to</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>WC = WOR/(l + WOR)</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Surface water cut is a function of the formation volume factors of the oil and water, so the complete expression is</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>WC = WOR <span style='font-family:Symbol'></span><sub>o</sub>/(<span style='font-family:Symbol'></span><sub>w</sub> + WOR • <span style='font-family:Symbol'></span><sub>o</sub>)</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Fluid Saturation<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p><strong>Fluid Distribution in the Reservoir <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Initially sediments are laid down in water--either in river and lake beds (continental) in deltas and along shore lines (transitional), or on the continental shelves (marine), as illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=378&order=0','0')'>Figure 1</a> . Eolian dune sediments, initially deposited in a water-free environment, are the exception to this rule.<br /></span></p><p style='text-align: justify'><br /> <span style='font-size:10pt'>Later in geologic time, after the reservoir rock has been buried, hydrocarbons migrate into the reservoir. Because of gravity segregation, gas accumulates above oil, and oil over-lies water. In the absence of any rock, gas, oil, and water form distinct layers with sharp contacts between each phase. In the reservoir, however, the contact lines between gas, oil, and water become blurred. To understand why this occurs, consider the simple case of a reservoir containing oil and water.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=378&order=1','1')'><span style='font-size:10pt'>Figure 2</span></a><span style='font-size:10pt'> shows such a reservoir. It is divided into three sections. The section at the top is mainly oil, the section at the bottom is all water, and the section in the middle has ever-increasing amounts of water as depth increases. Plotted on the right-hand side of the figure is a curve of water saturation, together with a plot of the pressure of the fluids in the pore space.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In order to understand the shape of the water saturation curve in the transition zone, consider the classical experiment of a small glass tube held in a beaker of water ( <a href='javascript:figurewin('../../asp/graphic.asp?code=378&order=2','2')'>Figure 3</a> ). A capillary tube of radius r is found to support a column of water of height h. If the density of the air is <span style='font-family:Symbol'></span><sub>a</sub> and the density of the water is <span style='font-family:Symbol'></span><sub>w</sub>, then the pressure differential at the air-water contact is simply (<span style='font-family:Symbol'></span><sub>w </sub>- <span style='font-family:Symbol'></span><sub>a</sub>)h. This pressure differential acting across the cross-sectional area of the capillary is exactly counterbalanced by the surface tension, T, of the water film acting around the inner circumference of the capillary tube. If, at the water-glass interface, the contact angle is , then at equilibrium we have</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>2<span style='font-family:Symbol'></span>rT cos<span style='font-family:Symbol'></span> = (<span style='font-family:Symbol'></span><sub>w</sub> - <span style='font-family:Symbol'></span><sub>a</sub>)h • <span style='font-family:Symbol'></span>r<sup>2</sup></span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>Force = Pressure • Area</span><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>By simplifying and rearranging this expression we have</span><br /> </span></p><p style='margin-left: 36pt'><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>We see that the smaller r gets, the larger h gets.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Translating this laboratory observation into terms of reservoir fluids, we can see that water can be drawn up into what would otherwise be a 100% oil column by the capillary effect of the small pores present in the rock system. We can equate the air in our experiment with oil, water with water, and the tube with pore throats. Thus the maximum height, h, to which water can he raised is controlled by the following factors:</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>the surface tension, T, between the two phases (here oil and water)</span><br /> </span></li></ul><p><span style='font-size:10pt'><span style='font-family:Symbol'></span>the contact angle, <span style='font-family:Symbol'></span> , between the wetting fluid (water) and the rock</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>the radius of the pore throats (r)</span><br /> </p><p style='margin-left: 72pt'><span style='font-size:10pt'><span style='font-family:Symbol'></span>the density difference between the phases (<span style='font-family:Symbol'></span><sub>w</sub> - <span style='font-family:Symbol'></span><sub>o</sub> in this case)</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Given these factors, it is simple to predict the length of a transition zone in a reservoir. Reservoirs with large pore throats and high permeability have short transition zones, and the transition zone at a gas-oil contact is shorter than that at an oil-water contact simply because of the interphase density differences involved ( <a href='javascript:figurewin('../../asp/graphic.asp?code=378&order=3','3')'>Figure 4</a> ).</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Since a pore system is made up of a variety of pore sizes and shapes, no single value of r can be assigned to one reservoir. Depending on the size and distribution of the pore throats, certain available pore channels will raise water above the free-water level. The water saturation above the top of the transition zone will thus he a function of porosity and pore-size distribution.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In a water-wet system, water wets the surface of each grain or lines the walls of the capillary tubes. At the time oil migrates into the reservoir the capillary pressure effects are such that the downward progress of oil in the reservoir is most strongly resisted in the smallest capillaries. A distinct limit is reached to the amount of oil that can be expected to fill the pores. Large-diameter pores offer little resistance (Pc is low because r is big). small-diameter pores offer greater resistance (Pc is high because r is small). For a given reservoir, <span style='font-family:Symbol'></span><sub>o</sub> and <span style='font-family:Symbol'></span><sub>w</sub> determine the pressure differential that an oil-water meniscus can support. Thus, the maximum oil saturation possible is controlled by the relative number of small and large capillaries or pore throats. This maximum possible oil saturation, if looked at in terms of water saturation, translates into a minimum possible water saturation, and this is referred to as the irreducible water saturation, Swi Shaly, silty, low-permeability rocks with their attendant small pore throats tend to have very high irreducible water saturations. Clean sands of high permeability have very low irreducible water saturations. <a href='javascript:figurewin('../../asp/graphic.asp?code=378&order=4','4')'>Figure 5</a> illustrates this important concept by comparing capillary pressure curves for four rock systems of different porosity and permeability.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><strong>Laboratory Measurement<br /></strong></p><p><span style='font-family:Times'><strong>Measuring Porosity</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p><span style='font-size:10pt'>Porosity may be measured by a variety of methods, including</span><br /> </p><ul><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>borehole gravimetrics</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>wireline logging</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>core analysis</span><br /> </span></li></ul><p style='text-align: justify'><span style='font-size:10pt'><span style='font-family:Arial Unicode MS'>Each method investigates a different volume of the formation. The borehole gravimeter samples very large volumes in the order of 10<sup>3</sup> to 10<sup>6</sup> cu ft. Wireline logging tools investigate a much smaller volume, on the order of 1 to 10 cu ft, depending on the specific porosity device used. Core analysis investigates much smaller volumes, ranging from 10<sup>-3</sup> to 10<sup>-1</sup> cu ft. From one extreme to the other lie nine orders of magnitude, so we should not be surprised to learn that porosity estimates using different tools and techniques do not always</span><br /> <span style='font-family:Arial Unicode MS'>agree.</span></span><br /> </p><p><strong>Measuring Permeability<br /></strong></p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>There are many ways to estimate permeability, including</span><br /> </span></p><ul><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>pressure buildup from drillstem tests</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>pressure drawdown and buildup from wireline repeat formation testers</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>log analysis</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>core analysis</span><br /> </span></li></ul><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Again, each method investigates an effective radius different from the others by several orders of magnitude. In increasing order, these are:</span><br /> <br/><span style='font-size:10pt'> </span><br /> </span></p><div style='margin-left: 5pt'><table border='0' style='border-collapse:collapse'><colgroup><col style='width:272px'/><col style='width:272px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Method</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'><strong>Approximate radius (ft.)</strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>DST</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>10<sup>2</sup> - 10<sup>4</sup></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>RFT buildup</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>10 - 10<sup>2</sup></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>RFT drawdown</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>10<sup>-2</sup> - 10<sup>0</sup></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>log analysis</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>10<sup>-1</sup> - 5</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.5pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>core analysis</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.5pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>8 x 10<sup>-2</sup> - 3 x 10<sup>-1</sup></span></p></td></tr></tbody></table></div><p style='text-align: justify'><span style='font-size:10pt'>It should come as no surprise that these different methods of measurement occasionally produce disparate results, especially in a heterogeneous reservoir. where the drilling process has caused clay swelling in the invaded zone, it is also to be expected that measurements made near the wellbore (logs, RFT tests) will reflect permeabilities that are lower than true permeabilities. Care must be taken in using the results of permeability measurements made on cores; they vary, depending on the type of fluid (air or brine) used for the measurement and the pressure and temperature of the sample at the time of the measurement (standard or reservoir conditions).<br /></span></p><p><span style='font-size:10pt'>Many investigators have attempted to correlate rock permeability to measurements made by wireline logging tools. These measurements fall into two categories--those that apply above the transition zone and those that apply only in the transition zone--among which are:</span><br /> <br/><span style='font-size:10pt'>k = 8581 • <span style='font-family:Symbol'></span>4.4 • S<sub>wi</sub><br /> <sup>-2</sup> (Timur)</span><br /> <br/><span style='font-size:10pt'>k = [250 • <span style='font-family:Symbol'></span>3 • S<sub>wi</sub>-1]2 -oils (Schlumberger) or</span><br /> <br/><span style='font-size:10pt'>k = [79 • <span style='font-family:Symbol'></span> 3 • S<sub>wi</sub>-1]2 -gas (after Wyllie and Rose)</span><br /> <br/><br /> </p><p><span style='font-size:10pt'>for O/W (Raymer and Freeman 1984) or</span><br /> </p><p><br /> </p><p><span style='font-size:10pt'>for G/<sub>W</sub></span><br /> </p><p><span style='font-size:10pt'>where:</span><br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:62px'/><col style='width:389px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>S<sub>wi</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>is fractional irreducible water saturation</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-family:Symbol; font-size:10pt'></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>is fractional porosity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>h</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>is height in feet from free-water level to the top of the transition zone</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>w</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>is the water density in gm/cc</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>o</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>is the oil density in gm/cc</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.5pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>g</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.5pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>is the gas density in gm/cc</span></p></td></tr></tbody></table></div><p style='text-align: justify'><span style='font-size:10pt'>The first three equations (Timur, Schlumberger, Wyllie/Rose) apply to points above the transition zone, since that is the only Place that S<sub>wi</sub> can be measured. The fourth equation applies to the oil/water transition zone, and the fifth to the gas/water transition zone.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the transition zone, the resistivity gradient is usually linear; i.e., a resistivity log on a linear scale shows a straight line in a transition zone. The resistivity gradient may then be related to k, provided the density difference between the wetting and nonwetting phases is known.</span><br /> </p><p><a href='javascript:figurewin('../../asp/graphic.asp?code=379&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> gives a graphical solution to the equation</span><br /> </p><p><br /> </p><p><span style='font-size:10pt'>where</span><br /> </p><p><span style='font-size:10pt'>and c = 20.</span><br /> </p><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>w</sub> and <span style='font-family:Symbol'></span><sub>hy</sub> are in gm/cc, <span style='font-family:Symbol'></span>R/<span style='font-family:Symbol'></span>D is expressed in ohms/ft and k is in md.</span><br /> </p><p style='text-align: justify'> <br /> </p><p><strong>Measuring Saturation<br /></strong></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Fluid saturations for the most part are adequately measured by log analysis techniques, provided formations are clean and connate waters are saline. Problems arise with shaly formations and fresh-water-bearing formations. Other methods of saturation determination are available from proper coring and subsequent core analysis techniques. Mud logging can provide a qualitative measure of oil and gas saturations.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Many similarities exist between the flow of fluids through a rock and the flow of electric current through a rock. The permeability to water, for example, can be equated with the electrical conductivity of a porous system, since both depend on interconnected pores. In cases in which both oil and water are present in a pore system, a parallel also exists between relative permeability to water and electrical conductivity of an oil-hearing sand.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Investigation of the electrical properties of water- and oil-hearing rocks was pioneered by Archie (1942). To follow the development of his experimental observations, let us examine the electrical behavior of electrolytes and water-filled rocks.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Water Resistivity (R<sub>w</sub>)</em> Connate waters range in resistivity from about 1/100 of an ohm-m up to several ohm-m, depending on the salinity and temperature of the solution. To find water saturation by quantitative analysis of porosity and resistivity logs, a value of R<sub>w</sub> is required.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>For our basic concept, we only need to understand that the ability of a rock to conduct electricity is due entirely to the ions in the water found in the pore spaces. <a href='javascript:figurewin('../../asp/graphic.asp?code=379&order=1','1')'>Figure 2</a> shows a cube of rock with a system of cylindrical tubes drilled through it. If the cylindrical "pores" are filled with water of resistivity R<sub>w</sub>, their total area is A, and their length is L, we can estimate that the resistivity of the total rock system is proportional to R<sub>w</sub> • L/A.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>If the area A is small, there is a small conductive path per length L and the resistivity of the rock system is high. Conversely, if A is large, the resistivity is low. The resistivity of a rock 100% saturated with water is referred to as R<sub>o</sub>. It can be seen that A is proportional to the porosity itself. Thus we may write</span><br /> </p><p><span style='font-size:10pt'>R<sub>o</sub> = f (R<sub>w</sub>,<span style='font-family:Symbol'></span>)</span><br /> </p><p><span style='font-size:10pt'>or that R<sub>o</sub> is related to R<sub>w</sub> by some formation factor, F, such that</span><br /> </p><p><span style='font-size:10pt'>R<sub>o</sub>=F • R<sub>w</sub></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Electrical Formation Factor The method Arch is used to arrive at this conclusion was simple. He took a number of cores of different porosity and saturated each one with a variety of brines. He could then measure, at each brine salinity, the resistivity of the water R</em><sub>w</sub>, and the resistivity of the 100% water saturation rock system, R<sub>o</sub>. when the results were plotted, he found a series of straight lines of slope F, as shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=379&order=2','2')'>Figure 3</a> .</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Archie conducted many experiments that showed that the formation factor is related to porosity in a predictable manner. Our simple tubular model bears little relationship to the tortuous paths that pores actually take. The factor L (the length of the tubular pore) grows larger as the tortuosity of the pore system increases. <a href='javascript:figurewin('../../asp/graphic.asp?code=379&order=3','3')'>Figure 4</a> illustrates the concept.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Note that by <em>definition</em> the formation factor is the ratio of R<sub>o</sub>/R<sub>w</sub> i.e., the resistivity of a rock sample 100% saturated with water to the resistivity of the water itself. Archie found that laboratory-measured values of F could also be related to the porosity of the rock by an equation of the form</span><br /> </p><p><span style='font-size:10pt'>F = a / <span style='font-family:Symbol'></span>m</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>where a and m are experimentally determined constants. In porous formations, a is usually close to 1 and m is usually close to 2 ( <a href='javascript:figurewin('../../asp/graphic.asp?code=379&order=4','4')'>Figure 5</a> ).</span><br /> </p><p style='text-align: justify'> <br /> </p><p><span style='font-size:10pt'>Three commonly used formation-factor-to-porosity relations are:</span><br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:144px'/><col style='width:308px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>F = 1/ <span style='font-family:Symbol'></span>2 </span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>(compacted formations and chalky rocks)</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>F = 0.62/ <span style='font-family:Symbol'></span>2.15 </span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>(Humble formula-soft formations and sucrosic rocks)</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.5pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>F = 0.81/ <span style='font-family:Symbol'></span>2 </span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.5pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>(simplified Humble formula for sands)</span></p></td></tr></tbody></table></div><p style='text-align: justify'><span style='font-size:10pt'>For a wet formation, we may combine the F to f relationship with the definition of F, and arrive at the equation</span><br /> </p><p><span style='font-size:10pt'>R<sub>w</sub> = R<sub>o</sub>/F = R<sub>o</sub> • <span style='font-family:Symbol'></span>m/a</span><br /> </p><p><span style='font-size:10pt'><em>Saturation Archie's experiments showed that the saturation of a clean formation could he expressed in terms of its true resistivity as S</em><sub>wn</sub> = R<sub>o</sub>/R<sub>t</sub>.</span><br /> </p><p><span style='font-size:10pt'>Since R<sub>o</sub> = F • R<sub>w</sub>, the water saturation equation can also be written</span><br /> </p><p><span style='font-size:10pt'>S<sub>wn</sub> = F • R<sub>w</sub>/R<sub>t</sub>,</span><br /> </p><p><span style='font-size:10pt'>where n is the saturation exponent and is usually set to 2 ( <a href='javascript:figurewin('../../asp/graphic.asp?code=379&order=5','5')'>Figure 6</a> ).</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Archie's classical relationships work well in clean formations, but not in shaly formations and where connate water is fresh. Archie's model considers the electrolytes in the pores as the only conductive path. As we shall see, an additional conductive path exists as the result of surface conductance effects which <em>only</em> become noticeable when they begin to provide a substantial percentage of the total rock system conductivity.</span><br /> </p><p><span style='font-family:Times'><strong>Permeability Estimates</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>As with porosity measurement, there are many ways to estimate permeability. These include</span><br /> </p><ul><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>pressure buildup from drillstem tests</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>pressure drawdown and buildup from wireline repeat formation testers</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>log analysis</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>core analysis</span><br /> </span></li></ul><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Different methods of measurement may produce dissimilar results because there are many orders of magnitude that separate the effective radius of investigation of each method. In increasing order these are</span><br /> <br/><span style='font-size:10pt'> </span><br /> </span></p><div style='margin-left: 5pt'><table border='0' style='border-collapse:collapse'><colgroup><col style='width:272px'/><col style='width:272px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Method</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'><strong>Approximate radius of investigation, ft</strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>DST</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>10<sup>2</sup> - 10<sup>4</sup></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>RFT buildup</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>10 - 10<sup>2</sup></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>RFT drawdown</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>10<sup>-2</sup> - 100</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>log analysis</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>10<sup>-1</sup> - 5</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.5pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>core analysis</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.5pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>8 x 10<sup>-2</sup> - 3 x 10<sup>-1</sup></span></p></td></tr></tbody></table></div><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>In a heterogeneous reservoir, such dissimilarities are to be expected. Where the drilling process has caused clay swelling in the invaded zone, measurements made near the wellbore (logs, cores, RFT tests) usually reflect permeabilities lower than actual permeabilities. Careful review of the results of permeability measurements made on cores is necessary to distinguish between the type of fluid (air or brine and its salt concentration) used for the measurement, and the pressure and temperature of the sample at the time of the measurement (standard or reservoir conditions).</span><br /> </span></p><p><span style='font-size:10pt'>Many investigators have attempted to correlate rock permeability to measurements made by wireline logging tools. These attempts fall into two categories: those that apply above the transition zone and those that apply only in the transition zone. Among them are</span><br /> <br/><span style='font-size:10pt'> </span><br /> </p><div style='margin-left: 5pt'><table border='0' style='border-collapse:collapse'><colgroup><col style='width:236px'/><col style='width:215px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p/></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>Timur (1968)</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p/></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>(Oils)</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.5pt; border-right: solid 0.75pt'><p/></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.5pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>(Gas) </span></p></td></tr></tbody></table></div><p><span style='font-size:10pt'>where:</span><br /> <br/><span style='font-size:10pt'> </span><br /> </p><div style='margin-left: 5pt'><table border='0' style='border-collapse:collapse'><colgroup><col style='width:43px'/><col style='width:243px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>k</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.5pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>= permeability (in md)</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-family:Symbol; font-size:10pt'></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>= fractional porosity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>S<sub>wi</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'><p><span style='font-size:10pt'>= fractional irreducible water saturation</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.5pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'> </td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.5pt'> </td></tr></tbody></table></div><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=379&order=6','6')'><span style='font-size:10pt'>Figure 7</span></a><span style='font-size:10pt'> shows a graphical representation of the Wyllie and Rose relationship where <span style='font-family:Symbol'></span> and S<sub>wi</sub> are crossplotted to yield values of k.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>In the transition zone a common observation is that the resistivity gradient is linear; i.e., a resistivity log on a linear scale will show a straight line in a transition zone. The resistivity gradient (Tixier 1949) then may be related to k, provided the density difference between the wetting and nonwetting phases is known.</span><br /> </p><p><a href='javascript:figurewin('../../asp/graphic.asp?code=379&order=7','7')'><span style='font-size:10pt'>Figure 8</span></a><span style='font-size:10pt'> gives a graphical solution to the equation</span><br /> </p><p><br /> </p><p><br /> </p><p><span style='font-size:10pt'>and</span><br /> </p><p><span style='font-size:10pt'>C = 20</span><br /> </p><p><span style='font-size:10pt'>where <span style='font-family:Symbol'></span><sub>w</sub> and <span style='font-family:Symbol'></span><sub>h</sub> are densities of water and hydrocarbon in gm/cc; <span style='font-family:Symbol'></span>R/<span style='font-family:Symbol'></span>D is expressed in ohms/ft and k is in md.</span><br /> </p><p><br /> </p><p><strong>Laboratory Measurement of Porosity</strong><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Rock samples suitable for laboratory analysis may come from a variety of sources, such as cuttings, sidewall cores and/or plugs, and conventional cores.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Depending on the source of the sample, the type of analysis made may be more or less sophisticated. At worst, a good idea of the rock type and porosity can be obtained, and, at best, a vast range of rock and fluid properties can be measured, including</span><br /> </p><ul><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>porosity</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>fluid saturation</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>permeability</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>relative permeability</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>wettability</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>capillary pressure</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>pore throat distribution</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>grain size distribution</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>grain density</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>mineral composition</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>electrical properties</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>effects of overburden stress</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>sensitivity to fluids</span><br /> </span></li><li><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>hydrocarbon analysis</span><br /> </span></li></ul><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Since most of these rock/fluid system properties are of vital interest to the formation evaluator, it is helpful to learn more about core analysis methods and the application of their results to log analysis in particular and formation evaluation in general.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Sidewall cores are usually shot at preselected depths determined from wireline logs. Cuttings are usually collected at 2-, 5-, 10-, or 20-ft intervals, and should be properly tagged and identified as to source depth range. Whole cores are usually cut to driller's depth, which may be at odds with wire-line logging depths; thus, a good starting point for whole core analysis is a gamma ray scan of the core. The core is laid out in its shipping container and moved relative to a gamma ray counter, which records a graph of radioactivity versus distance traveled along the core. This record may then be compared directly with a wireline gamma ray log. <a href='javascript:figurewin('../../asp/graphic.asp?code=379&order=8','8')'>Figure 9</a> shows an example.<br /></span></p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>When cutting conventional cores, it is wrong to assume that the only formations of interest are the clean reservoir rocks. Useful data may be extracted from shales as well, and the temptation to high-grade the core at the wellsite by throwing shale sections into the outer darkness should be resisted. The core gamma scan, for example, would be useless if the radioactive section of the core were missing.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Depending on the particular analysis to which the core is to be submitted, either a plug is cut or the whole core itself is used. Plugs are 1 to 1-1/2 in. in diameter and 1 to 3 in. long. Whole cores are normally 5 in. in diameter and up to 60 ft long.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><em>Fresh cores </em>are cores cut with water- or oil-base muds preserved without cleaning. <em>Native state cores </em>are those cut with lease crude as the coring fluid to minimize changes in rock wettability. <em>Restored cores </em>are cleaned and dried prior to testing; their wettability and fluid distributions are changed.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Cores may be epoxy coated, jacketed in heat-shrinkable tubing or metal (for unconsolidated cores), or molded in lucite.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>A porous rock system has two components: the grain volume and the pore volume. The sum of the two gives the bulk volume:</span><br /> </p><p><span style='font-size:10pt'>VB = VG + VP</span><br /> </p><p><span style='font-size:10pt'>The porosity is defined as the ratio of the pore volume to the bulk volume, for example,</span><br /> </p><p><br /> </p><p><span style='font-size:10pt'>Thus porosity can be measured in a number of ways, such as</span><br /> </p><p><br /> </p><p><span style='font-size:10pt'>or</span><br /> </p><p><br /> </p><p><span style='font-size:10pt'>Provided any two of the three entities are measured, porosity can be deduced. Among the commonly employed methods of deduction are</span><br /> </p><ul><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>summation of fluids </em>method, in which the volumes of water, oil, and gas are independently measured and then summed to give Vp. VB is deduced from the dimensions of the core.</span><br /> </span></div></li><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>Boyle's law </em>method, in which the core is cleaned and dried. Air, or other gas, is allowed to fill the pore space. When the sample is connected to another chamber filled with gas at a different pressure, the gas in the core pore space expands.</span><br /> </span></div></li><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The final pressure in the system allows deduction of VP by use of Boyle's (Charles's) law. Again, VB is deduced from the dimensions of the core.</span><br /> </span></div></li><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>Washburn-Bunting </em>vacuum extraction and collection ofgas in the pore space, which is somewhat similarto the Boyle's law method and measures VP.</span><br /> </span></div></li><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>liquid restoration, </em>which involves simply filling thepore space with a liquid of known density andmeasuring the weight increase. VP is thendeduced by dividing the weight increase by theknown liquid density.</span><br /> </span></div></li><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'><em>grain density </em>methods, which require that both bulk volume and dry weight of the sample bedetermined first. The sample is then crushed tograin-size particles and VG is measured. VP isthen deduced as the difference between VB andVG. A side benefit is the estimation of graindensity from the knowledge of dry weight and grainvolume. The disadvantage of the method is the physical destruction of the core sample.</span><br /> </span></div></li></ul><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Accuracy of core porosity measurements are claimed to be within a half P.U. Methods requiring that the core be cleaned and dried are subject to error if the core contains hydrated clay material. Heating such a sample in a retort may drive off water of hydration; the porosity measured thus may be larger than effective porosity. Use of a humidity-controlled oven to dry samples alleviates this problem.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Porosity measurements from sidewall cores may produce a value that is slightly different from the average over the zone. Therefore, sidewall-core porosity values should be used only <em>in addition </em>to other methods.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Porosity measurements should be "weighted" prior to their use, based on (1) the method used to obtain them, (2) their anticipated application, and (3) the homogeneity of the reservoir. A core plug is very localized and core plug porosities may be higher than whole core porosities if the whole core includes portions of rock of a lower porosity. The selection of places to plug a whole core is somewhat subjective and usually the "best-looking spot" is picked. This tendency should be resisted, lest the core data become so high-graded that they no longer tie to the log. Regularly spaced core plugs should be taken, regardless of the lithology. These data can then be processed in a rolling average to mimic the wireline logging tool response, and thus produce correlatable results.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Porosity measurements made from sidewall core plugs can be either higher or lower than true porosities, depending on the porosity range. This condition is illustrated in <a href='javascript:figurewin('../../asp/graphic.asp?code=379&order=9','9')'>Figure 10</a> by the plotting of sidewall core porosity against conventional core porosity. In general, low-porosity formations tend to fracture when sidewall core bullets strike them and hence induce additional pore volume.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Porosity measurements may also be made on sample cuttings as small as a cubic centimeter or less. Such measurements compare well to core plug porosities within one P.U.</span><br /> </p><p><br /> </p><p><span style='font-family:Times'><strong>Effects of Overburden Pressure</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Although most basic rock properties are measured at atmospheric conditions, in some cases it is important to make the measurements (especially those of porosity and permeability) at simulated reservoir conditions. Both rock matrix and pore fluids are compressible, although matrix compressibility is generally very low. Thus, measurements at standard conditions give overly optimistic values for <span style='font-family:Symbol'></span> and k. <a href='javascript:figurewin('../../asp/graphic.asp?code=379&order=10','10')'>Figure 11</a> illustrates the effects of net overburden pressure on permeability.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Depending on the type of material tested, reduction of up to 80% can be expected. Note that permeability is an intrinsic rock property, independent of the fluid in the pore space.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>When it comes to discussing porosity reductions that are the result of changes in pressure, however, the total rock/fluid system must be considered, since both the rock matrix and the fluids in the pore space are compressible. Thus, both overburden and pore pressure come into play. Compressibilities are expressed in vol/vol/psi. It would not be uncommon to find a 6% reduction in porosity caused by compressibility; e.g., if a sample in the lab measured 20%, the porosity at depth might be 18.8%. Lab measurements of oil, water, and rock compressibility can be made and the exact pore reduction factor deduced if reservoir pore and overburden stress are known.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Other pressure-sensitive parameters include acoustic velocity and formation factor. The effects of pressure are to raise the lab-reported values by 20 to 30%.</span><br /> </p><p><br /> </p><p><strong>Porosity and Formation Factor <br /></strong></p><p><span style='font-size:10pt'>Porosity may be measured by a variety of methods, including</span><br /> </p><ul><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>core analysis</span><br /> </span></div></li><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>wireline logging</span><br /> </span></div></li><li><div style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>borehole gravimetrics</span><br /> </span></div></li></ul><p style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>Each method investigates a different volume of the formation. Core analysis investigates very small volumes, ranging from l0<sup>-3</sup> to 10<sup>-1</sup> cu ft. Wireline logging tools investigate volumes on the order of 1 to 10 cu ft, depending on the specific porosity device used. The borehole gravimeter evaluates very large volumes in the order of 10<sup>3</sup> to 10<sup>6</sup> cubic feet. With nine orders of magnitude (10<sup>-3</sup> to 10<sup>6</sup>), one should not be surprised to learn that porosity estimates using different tools and techniques do not always agree. <br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>If formations are clean and connate waters are saline, fluid saturations are usually measured by log analysis techniques. Problems arise in shaly formations and where formation waters are fresh. Other methods of saturation determination are possible through core analysis techniques. Mud logging can qualitatively measure the presence of oil and gas, but is not available on all wells.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Many similarities exist between the flow of fluids through a rock and the flow of electric current through a rock. The permeability to water, for example, can be likened to the electrical conductivity of a porous system, since both depend on interconnected pores. In cases in which both oil and water are present in a pore system, there is a parallel between relative permeability to water and electrical conductivity of an oil-bearing sand.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Investigation of the electrical properties of water- and oil-bearing rocks was pioneered by Archie. A good starting point to follow the development of his experimental observations is the behavior of electrolytes.</span><br /> </p><p style='text-align: justify'><strong>Porosity and Permeability<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Porosity and Water Saturation<br /></strong></p><p><span style='font-family:Times'><strong>Interpreting Petrophysical Data</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>When a formation is above the transition zone, i.e., at irreducible water saturation, the product of <span style='font-family:Symbol'></span> and S<sub>w</sub> is a constant. variations of porosity are normal on a local scale, caused both by changes in the depositional environment and by subsequent diagenesis. If porosity is reduced locally, either a greater proportion of the pore throats are small or there are simply fewer pore throats. Either way, the mean radius r is smaller; thus Pc is larger and more water can be held in the pore maintaining the constant</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>f • S<sub>wi</sub> product .</span><br /> </span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>This has a practical application. After a zone has been analyzed on a foot-by-foot basis for porosity and water saturation, a plot of f versus S<sub>w</sub> reveals the presence or absence of a transition zone.</span><br /> </span></p><p style='text-align: justify'><a href='javascript:figurewin('../../asp/graphic.asp?code=382&order=0','0')'><span style='font-size:10pt'>Figure 1</span></a><span style='font-size:10pt'> shows a plot on log-log paper. Here, the points at irreducible saturation plot on a straight line and the points in the transition zone plot to the right of the irreducible line.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Reservoirs may be characterized by the f • S<sub>wi</sub> product, and this knowledge used as a basis for predicting production characteristics. For points not at irreducible saturation, some water production is to be expected, depending on the mobility ratio, (k<sub>w</sub>µ<sub>o</sub>/k<sub>o</sub>µ<sub>w</sub>), for the particular fluids present. Note that in a low-porosity, low-permeability formation, surprisingly high water saturations can be tolerated without fear of water production. Conversely, in others with good porosity and permeability, even with moderate values of S<sub>w</sub>, water production can be expected. This salient fact is all too often overlooked.</span><br /> </p><p style='text-align: justify'><strong>Resistivity<br /></strong></p><p><span style='font-family:Times'><strong>Conduction of Electric Current in Porous Rocks</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Ohm's law states that the potential difference, V, between two points on a conductor is equal to the product of the current flowing in the conductor, I, and the resistance of the conductor, R. Practical units of measurement are, respectively, the volt, the amp, and the ohm. Expressed as an equation, the relationship is</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS; font-size:10pt'>V = I • R <br /></span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>Volts = Amps </span>•<span style='font-size:10pt'> Ohms</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Of more interest in logging is the <em>resistivity, </em>rather than the <em>resistance, </em>of a rock. Resistivity is defined as the resistance of a specific amount of a substance. It is further defined as the voltage required to cause one amp to pass through a cube of face area one meter square. <a href='javascript:figurewin('../../asp/graphic.asp?code=383&order=0','0')'>Figure 1</a> illustrates this concept. The unit of resistivity is the ohm-meter</span><span style='font-size:7pt'>2</span><span style='font-size:10pt'>/meter and abbreviated as ½m</span><span style='font-size:7pt'>2</span><span style='font-size:10pt'>/m or ½m.<br /></span></p><p style='text-align: justify'><br /> <span style='font-size:10pt'>When discussing formation resistivities, it is common to say "this is a 25-ohm sand" rather than to say "this sand has a resistivity of 25 ohms meters squared per meter." So the field jargon, when talking about resistivity logs, is to say "ohm" when "ohm m</span><span style='font-size:7pt'>2</span><span style='font-size:10pt'>/m" is really meant.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Why the need to know the resistivity rather than the resistance? Because resistance is a function not only of the resistivity measured, but also of the geometry of the body of material on which the measurement is being made. The geometry of the body is not of prime interest. The measurement that characterizes the rock, as far as fluid content is concerned, is the resistivity, not the resistance. The resistance of a wire stretching across the Pacific Ocean could be high, but the resistivity of the wire itself could be very low.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Conductivity is the reciprocal of resistivity. A substance with infinite resistivity (empty space) has a conductivity of zero, and a substance with low resistivity has high conductivity. Common units of conductivity are milliohms, or 1/1000th of a reciprocal ohm-m.</span><br /> </p><p><span style='font-size:10pt'>conductivity (C) (in milliohms) = 1000/resistivity (in ohm-m)</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Typical formation resistivities range from 0.2 ohm-m to 1000 ohm-m. Soft formations (shaly sands) range from 0.2 ohm-m to about 50 ohm-m. Hard formations (carbonates) range from 100 ohm-m to 1000 ohm-m. Evaporites (salt, anhydrite) may exhibit resistivities of several thousand ohm-m. Formation water, by contrast, ranges from a few hundredths of an ohm-m (brines) to several ohm-m (fresh water). Sea water has a resistivity of 0.35 ohm-m at 75</span><span style='font-family:Symbol'></span><span style='font-size:10pt'> F.</span><br /> </p><p><span style='font-family:Times'><strong>Types of Resistivity Measurements</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Given an infinite isotropic homogeneous medium with a spherical electrode implanted in it emitting a current I radially in a spherical distribution (see <a href='javascript:figurewin('../../asp/graphic.asp?code=383&order=1','1')'>Figure 2</a> ), the voltage drop between any two concentric spherical shells with radii <span style='font-family:Symbol'></span> and <span style='font-family:Symbol'></span> + d<span style='font-family:Symbol'></span> can be determined in the following manner:</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS; font-size:10pt'>dV = I • dr<br /></span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where dV is the voltage drop, I is the current, and dr is the resistance between the two shells. If the resistivity of the medium is R, then</span><br /> </span></p><p style='margin-left: 36pt'><span style='font-size:10pt'>dr = R </span>•<span style='font-size:10pt'> d / 4 ¹<span style='font-family:Symbol'><sup></sup></span> and,</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>dV = I </span>•<span style='font-size:10pt'> R </span>•<span style='font-size:10pt'> d / 4 ¹<span style='font-family:Symbol'><sup></sup></span></span><br /> </p><p>Integrating this equation from <span style='font-family:Symbol'></span> = A to <span style='font-family:Symbol'></span> = M, the equation to determine the value for V<sub>m</sub> becomes <br /></p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>where V</span><span style='font-size:7pt'><sub>m</sub></span><span style='font-size:10pt'> is the measured voltage at some point a distance M from the current electrode A, and R is the formation resistivity .<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>This ideal derivation does not fit the real world for two reasons. First, a borehole is required in order to introduce an electrode into the formation, and, second, no formation is infinite and homogeneous. Over the years, many improvements have been made to this simple, but inadequate, method of measuring formation resistivity .</span><br /> </p><p><span style='font-family:Times'><strong>Resistivity</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Electricity can pass through a formation only because of the conductive water it contains. With a few rare exceptions, such as metallic sulfide or graphite, dry rock is a good electrical insulator. But perfectly dry rocks are very seldom encountered; water is in their pores or absorbed in their interstitial clay, therefore subsurface formations have finite, measurable resistivities.</span><br /> </p><p><span style='font-size:10pt'>The resistivity (R) of a formation depends on:</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>the resistivity of the formation water <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>the amount of water present</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>the pore structure geometry</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Resistivity, a key parameter in determining hydrocarbon saturation, is defined as the specific resistance of a substance, i.e., the resistance of a specific amount of it. It is numerically equivalent to the voltage required to cause one amp to pass through a cube of face area one meter square. <a href='javascript:figurewin('../../asp/graphic.asp?code=383&order=2','2')'>Figure 3</a> illustrates this concept. The unit of resistivity is the ohm-meter2/meter, abbreviated as m2/m, or simply ohm-meter (ohm-m).<br /></span></p><p style='text-align: justify'><br /> <span style='font-size:10pt'>Conductivity is the reciprocal of resistivity and is expressed in mhos per meter (mho/m). A substance with infinite resistivity (empty space) has a conductivity of zero and a substance with low resistivity has high conductivity.</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Conductivity is usually expressed in millimhos per meter (mmho/m), where 1000 mmho/m = 1 mho/m:</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Typical formation resistivities range from 0.2 ohm-m to 1000 ohm-m. Soft formations (shaly sands) range from 0.2 ohm-m to about 50 ohm-m. Hard formations (carbonates) range from 100 ohm-m to 1000 ohm-m. Evaporates (salt, anhydrite) may exhibit resistivities of several thousand ohm-m. Formation water, by contrast, ranges from a few hundredths of an ohm-m (brines) to several ohm-m (fresh water). Seawater has a resistivity of 0.35 ohm-m at 75 F.<br /></span></p><p><strong>Water Resistivity (R<sub>w</sub>) <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Connate waters range in resistivity from about 1/100 of an ohm-m up to several ohm-m, depending on the salinity and temperature of the solution. A value of R</span><sub>w</sub><span style='font-size:10pt'> is required to determine water saturation by quantitative analysis of porosity and resistivity logs.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The ability of a rock to conduct electricity is due entirely to the ions in the water found in its pore spaces. <a href='javascript:figurewin('../../asp/graphic.asp?code=383&order=3','3')'>Figure 4</a> shows a cube of rock with a system of cylindrical tubes drilled through it. If the cylindrical "pores" are filled with water of resistivity R</span><sub>w</sub><span style='font-size:10pt'>, their total area is A, and their individual length is L, we can estimate that the resistivity of the total rock system is proportional to R</span><sub>w</sub><span style='font-size:10pt'> L/A. By definition the resistivity of water-bearing porous rock systems is R</span>0<span style='font-size:10pt'>.<br /></span></p><p style='text-align: justify'><br /> <span style='font-size:10pt'>If the area A is small, there is a small conductive path per length L and the resistivity of the rock system is high. Conversely, if A is large the resistivity is low. It can be seen that A is proportional to the porosity itself. Thus we may write:</span><br /> </p><p style='margin-left: 36pt'><span style='font-family:Arial Unicode MS; font-size:10pt'><strong>R<sub>o</sub> = f(R<sub>w</sub>,f)<br /></strong></span></p><p style='margin-left: 36pt'><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The resistivity of the formation water, R</span><sub>w</sub><span style='font-size:10pt'> is an intrinsic property of the water and is a function of its salinity and temperature. The higher these two variables, the more conductive the water and the lower its resistivity.<br /></span></p><p><br /> </p><p><span style='font-family:Times'><strong>Electrical Formation Factor</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The method Archie used to arrive at the functional form of the relationship was simple. He took a number of cores of different porosities and saturated each one with a variety of brines. He could measure, at each brine salinity, the resistivity of the water, R</span><sub>w</sub><span style='font-size:10pt'>, and the resistivity of the 100% water-saturated rock system, R<sub>o</sub>. When the results were plotted, he found a series of straight lines of slope F, as shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=383&order=4','4')'>Figure 5</a> . Archie determined that the relationship between R<sub>o</sub> and R</span><sub>w</sub><span style='font-size:10pt'> is as follows:</span><br /> </p><p><span style='font-size:10pt'>R<sub>o</sub> = F RW</span><br /> </p><p><span style='font-size:10pt'>R<sub>o</sub> = F RW</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Archie conducted many experiments that showed that the formation factor is related to porosity in a predictable manner. Our simple tubular model ( <a href='javascript:figurewin('../../asp/graphic.asp?code=383&order=5','5')'>Figure 6</a> ) bears little relationship to the tortuous paths that pores actually take. The factor L, the length of the tubular pore, grows longer as the tortuosity of the pore system increases.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'>By definition, the formation factor is the ratio of R<sub>o</sub>/R</span><sub>w</sub><span style='font-size:10pt'>; i.e., the ratio of the resistivity of a rock sample 100% saturated with water to the resistivity of the water itself. Archie found that laboratory-measured values for F could also be related to the porosity of the rock by an equation of the form</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>where a is the cementation factor and m is the cementation exponent. The values of a and m are experimentally determined constraints; a is usually close to 1 and m is usually close to 2 in porous formations ( <a href='javascript:figurewin('../../asp/graphic.asp?code=383&order=6','6')'>Figure 7</a> ).<br /></span></p><p><span style='font-size:10pt'>Two commonly used formation-factor-to-porosity relations are</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>(carbonates)</span><br /> </p><p style='margin-left: 36pt'><span style='font-size:10pt'>(Humble formula – sands)</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>To eliminate the fractional cementation exponent, the Humble formula is sometimes simplified to</span><br /> </span></p><p style='margin-left: 36pt'><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>The exponent m can be as high as 3 in some severely ooliclastic packs.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>In a wet formation we may therefore combine the F to 4 relationship with the definition of F and arrive at the equation</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p><strong>Resistivity Index and Water Saturation <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>Archie's experiments showed that the saturation of a core could be related to its resistivity. He found that the fractional water saturation, S</span><sub>w</sub><span style='font-size:10pt'>, was equal to the square root of the ratio of the wet formation resistivity, R<sub>o</sub> to the formation resistivity, R</span><sub>t</sub><span style='font-size:10pt'>. That is,</span><br /> </p><p style='margin-left: 36pt'><br /> </p><p><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>In a more generalized form this equation can be written as</span><br /> </span></p><p style='margin-left: 36pt'><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>where n is the saturation exponent ( <a href='javascript:figurewin('../../asp/graphic.asp?code=383&order=7','7')'>Figure 8</a> ). Laboratory experiments have shown n = 2.0 in the average case.</span><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>These classic Archie's relationships work well in clean formations. In shaly formations and where connate water is fresh they do not work as well. Archie's model considers the electrolyte in the pores as the <em>only </em>conductive path. However, a second conductive path exists, due to surface conductance effects.</span><br /> </p><p style='text-align: justify'><strong>Resistivity Measurement <br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Resistivity Relationship<br /></strong></p><p style='text-align: justify'><span style='font-size:10pt'>UNDER CONSTRUCTION …!<br /></span></p><p style='text-align: justify'><strong>Elastic Wave Propagation<br /></strong></p><p><span style='font-family:Times'><strong>Introduction</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p style='text-align: justify'><span style='font-size:10pt'>Many disciplines meet at a common point when formation evaluation is discussed from the point of view of elastic waves. Elastic formation properties control the transmittal of elastic waves through subsurface formations; indeed, the whole science of seismic evaluation is based on the physics of rock elasticity. Acoustic logging is a localized, downhole branch of geophysics. By properly combining measurements both from surface and downhole, a wealth of information can be gathered concerning formation properties. For example,</span><br /> </p><ul style='margin-left: 81pt'><li><span style='font-family:Arial Unicode MS; font-size:10pt'>acoustic logs and check shot surveys can be used to "calibrate" seismic surveys <br /></span></li></ul><p><span style='font-family:Symbol'></span><span style='font-size:10pt'>combined acoustic and density logs can provide "synthetic seismic" traces</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>combined acoustic and density logs can deduce formation mechanical properties, used in turn to deduce pore pressure, rock compressibility, fracture gradients, sanding problems, etc.</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>acoustic logs, used in conjunction with other logs, can deduce porosity, lithology, and fluid saturations</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>in borehole measurements, acoustic logs can produce vertical seismic profiles (VSP) that "see" below the bottom of the well</span><br /> </p><p style='margin-left: 72pt'><span style='font-family:Symbol'></span><span style='font-size:10pt'>acoustic tools may be used for cement bond logging in cased holes</span><br /> </p><p style='text-align: justify'><span style='font-family:Arial Unicode MS'><span style='font-size:10pt'>Since the elasticity of subsurface formations is basic to all of these measurements and interpreted answers, a good starting point is the study of elastic wave propagation through a medium.</span><br /> </span></p><p><br /> </p><p><strong>Propagation of Elastic Waves</strong><br /> </p><p><span style='font-size:10pt'>Two types of sound waves are propagated in an infinite medium:</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Compressional Waves.</strong> Compressional (or pressure) waves are longitudinal, that is, the direction of propagation is parallel to the direction of particle displacement ( <a href='javascript:figurewin('../../asp/graphic.asp?code=386&order=0','0')'>Figure 1</a> ). Gases and liquids, as well as solids, tend to oppose compression, therefore compressional waves can be propagated through them.</span><br /> </p><p style='text-align: justify'> <br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Shear Waves.</strong> Shear waves are transverse; that is, the direction of propagation is perpendicular to the direction of particle displacement ( <a href='javascript:figurewin('../../asp/graphic.asp?code=386&order=1','1')'>Figure 2</a> ). Shear waves can be propagated through solids, owing o their rigidity. On the other hand, gases (and liquids having negligible viscosity) cannot oppose shearing, and shear waves cannot be propagated through them. In practice, viscous fluids do permit some propagation of shear waves, though they become highly attenuated.</span><br /> </p><p><span style='font-size:10pt'>In a finite medium (e.g., a borehole) other types of waves are propagated. These are guided waves, which include:</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Rayleigh Waves.</strong> Rayleigh waves occur at the mud/formation interface and are a combination of two displacements, one parallel and the other perpendicular to the interface. Their speed is slightly less than the shear wave velocity (V</span><span style='font-size:7pt'><sub>Rayleigh</sub></span><span style='font-size:10pt'> is 86% to 96% of V</span><span style='font-size:7pt'>Shear</span><span style='font-size:10pt'>). When energy leaks away from the interface as compressional waves are set up in the mud, the waves are then referred to as pseudo-Rayleigh waves.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Stoneley Waves.</strong> Stoneley waves ("tube waves") can travel in the mud by interaction between the mud and the formation. The amplitude of these low-frequency waves decays exponentially in both the mud and the formation away from the borehole boundary. Stoneley wave velocity is lower than the mud compressional velocity.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Proper interpretation of any measurement made using elastic wave data requires an understanding of the elastic properties of a medium.</span><br /> </p><p><span style='font-family:Times'><strong>Elastic Constants</strong></span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The properties derived from testing rock samples in the laboratory, such as measuring the strain fore a given applied stress, are static elastic constants. Dynamic elastic constants are determined by measuring elastic wave velocities in the material. Acoustic logging and waveform analysis provide the means for obtaining continuous velocity measurements and, thus, knowledge of the mechanical properties of the rock in situ.</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>The speed at which a wave travels through a medium may be expressed in two ways. Geophysicists think in terms of velocity, i.e., distance traveled per unit of time. Subsurface formation velocities range from 6000 to 25,000 ft/second. Log analysts think in terms of time, i.e., the time taken to travel one unit of distance. A convenient unit of measurement is the microsecond per foot (µ sec/ft) given the symbol <span style='font-family:Symbol'></span>t. With these definitions in mind, the dynamic elastic constants of a medium can be expressed as a function of bulk density ( b) and travel time fore compressional and shear waves, <span style='font-family:Symbol'></span>t</span><span style='font-size:7pt'><sub>c</sub></span><span style='font-size:10pt'> and <span style='font-family:Symbol'></span>t</span><span style='font-size:7pt'><sub>s</sub></span><span style='font-size:10pt'>, respectively, as shown in <a href='javascript:figurewin('../../asp/graphic.asp?code=386&order=2','2')'>Table 1</a> .</span><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><br /> </p><p style='text-align: justify'><span style='font-size:10pt'><strong>Exercise 1.<br /></strong></span></p><p style='text-align: justify'><span style='font-family:Arial Unicode MS; font-size:10pt'>A 30% porous sandstone bed is 100 ft thick. It is 100% saturated with mud filtrate (S<sub>xo</sub> = 100%) to an invasion diameter of 40 in. The hole diameter is 8-1/2 in. Estimate the volume of filtrate that will be recovered from this sandstone before connate water or oil begins to be recovered. <br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>How many linear feet of 3-1/2 in, 15.25 1b/ft drillpipe will the volume of recovered filtrate occupy? (Note: For this drillpipe there are 27.1002 linear ft/cu ft.)</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Solution 1:<br /></span></p><p><span style='font-size:10pt'>Filtrate volume =250 Cu ft or 44.5 bbl<br /></span></p><p><span style='font-size:10pt'>Linear ft of drillpipe = 6774.44 ft<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><strong>Exercise 2.<br /></strong></span></p><p style='text-align: justify'><span style='font-size:10pt'>A sample of porous sandstone saturated with water is found to weigh 215.5 gm. After removing all the water from the sample it weighs 185.5 gm. If the density of the sandstone matrix is 2.65 gm/cc and the density of the water is I gm/cc, what is the porosity of the sample?<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>Solution 2:<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>We need to know two things: the volume of the rock sample, including its pores, and the volume of the pore space itself. Since the water removed from the sample entirely filled the pore space, it follows that the volume of the water equals the pore volume. Thus the pore volume (215.5 - 185.5) gm @ 1 gm/cc = 30 cc.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'>The volume of the rock itself is given by its weight divided by its density, or 185.5/2.65, which gives 70 cc of dry rock. This total volume of the rock plus the pores is thus 100 cc. The porosity of this system is thus 30/100 = 0.3, or 30%.<br /></span></p><p style='text-align: justify'><span style='font-size:10pt'><strong>Exercise 3.<br /></strong></span></p><p><span style='font-family:Arial Unicode MS; font-size:10pt'>If r<sub>b</sub> = 2.4 gm/cc <br /></span></p><p><span style='font-size:10pt'>and <span style='font-family:Symbol'></span></span><span style='font-size:7pt'><sub>f</sub><br /> </span><span style='font-size:10pt'>= 1.0 gm/cc</span><br /> </p><p><span style='font-size:10pt'>and the rock is sandstone, find</span><br /> </p><p><span style='font-family:Symbol; font-size:10pt'></span><span style='font-size:7pt'><sub>D</sub><br /> </span><span style='font-size:10pt'>= ?</span><br /> </p><p style='text-align: justify'><span style='font-size:10pt'>Solution 3:<br /></span></p><p style='text-align: justify'><span style='font-family:Symbol; font-size:10pt'></span><span style='font-size:7pt'><sub>D</sub><br /> </span><span style='font-size:10pt'>= 15.2%<br /></span></p><p><br /> </p><p><strong>REFERENCES<br /></strong></p><p><span style='font-size:10pt'>Allaud, L., and N. Martin. 1977. <em>Schlumberger, the history of a technique. </em>New York: Wiley and Sons.<br /></span></p><p><span style='font-size:10pt'>Bateman, R. M. 1984. <em>Log quality control. </em>Boston: IHRDC.<br /></span></p><p><span style='font-size:10pt'>___________. 1985. <em>Openhole log analysis and formation evaluation. </em>Boston: IHRDC.<br /></span></p><p><span style='font-size:10pt'>Bateman, R. N., and E. E. Konen. 1977. The log analyst and the programmable pocket calculator. <em>The Log Analyst </em>(SPWLA) Sept. -Oct.<br /></span></p><p><span style='font-size:10pt'>Burke, J. A., R. L. Campbell, and A. W. Schmidt. 1969. The litho-porosity crossplot. SPWLA Symposium, May.<br /></span></p><p><span style='font-size:10pt'>___________. 1969. The litho-porosity crossplot. <em>The Log Analyst </em>(SPWLA) Nov. -Dec.<br /></span></p><p><span style='font-size:10pt'>Burke, J. A., M. R. Curtis, and J. T. Cox. 1966. Computer processing of log data enables better production in Chaveroo field. SPE 1576, presented at the 41st Annual Meeting. October, Dallas.<br /></span></p><p><span style='font-size:10pt'>Cox, J. W., and L. L. Raymer. 1976. The effect of potassium salt muds on gamma ray and spontaneous potential measurements. SPWLA 17th Annual Logging Symposium.<br /></span></p><p><span style='font-size:10pt'>Doll, H. G. 1949. The SP log: Theoretical analysis and principles of interpretation. <em>Trans. AIME </em>179:146.<br /></span></p><p><span style='font-size:10pt'>_________. 1949. The SP log in shaly sands. <strong>J. </strong><em>Pet. Tech. </em>2912.<br /></span></p><p><span style='font-size:10pt'>__________. 1955. The invasion process in high permeability sands. <em>Pet. Engr. </em>(January).<br /></span></p><p><span style='font-size:10pt'>Dresser Industries Inc. 1974. Log Review 1. Dresser Atlas.<br /></span></p><p><span style='font-size:10pt'>_________. 1979. Gamma ray spectral data assists in complex formation evaluation. Dresser Atlas (February).<br /></span></p><p><span style='font-size:10pt'>_________. 1980. Formation multi-tester interpretation manual. Dresser Atlas (June) 9404.<br /></span></p><p><span style='font-size:10pt'>_________. 1981. Spectralog. Dresser Atlas.<br /></span></p><p><span style='font-size:10pt'>_________. 1984. Wireline service catalog. Dresser Atlas.<br /></span></p><p><span style='font-size:10pt'>_________. 1984. Services catalog. Dresser Atlas.<br /></span></p><p><span style='font-size:10pt'>Eck, M. E., and D. E. Powell. 1983. Application of electromagnetic propagation logging in the Permian Basin of West Texas. SPE 12183, presented at the 58th Annual Technical Conference and Exhibition. October, San Francisco.<br /></span></p><p><span style='font-size:10pt'>Ellis, D., C. Flaum, C. Roulet, E. Marienbach, and B. Seeman. 1983. Litho-density tool calibration. SPE paper 12048, presented at the Annual Technical Conference and Exhibition. October, San Francisco.<br /></span></p><p><span style='font-size:10pt'>Evers, J. F., and B. G. Iyer. 1975. A statistical study of the SP log in fresh water formations of northern Wyoming. 16th Annual Logging Symposium of the SPWLA.<br /></span></p><p><span style='font-size:10pt'>Fertl, W. H., and E. Frost, Jr. 1982. Experiences with natural gamma ray spectral logging in North America. SPE paper 11145, presented at the 57th Annual Technical Conference and Exhibition. September, New Orleans.<br /></span></p><p><span style='font-size:10pt'>Fertl, W. H., W. L. Stapp, D. B. Vaello, and W. C. Vercellino. 1980. Spectral gamma ray logging in the Texas Austin Chalk trend. J. <em>Pet. Tech. </em>(March).<br /></span></p><p><span style='font-size:10pt'>Fitzgerald, D. D. 1980. Obtaining valid dipmeter surveys in deviated wells. <em>World Oil </em>(November).<br /></span></p><p><span style='font-size:10pt'>Garner, J. S., and J. L. Dumanoir. 1980. Litho-density log interpretation. Paper N, Trans., SPWLA 21st Annual Logging Symposium. July, Lafayette, LA.<br /></span></p><p><span style='font-size:10pt'>Gaymard, R., and A. Poupon. 1968. Response of neutron and formation density logs in hydrocarbon-bearing formations. <em>The Log Analyst </em>(SPWLA) Sept. -Oct.<br /></span></p><p><span style='font-size:10pt'>Gilreath, J. A., and R. W. Stephens. 1975. Interpretation of log response in a deltaic environment. Paper presented at the AAPG Marine Geology Workshop, April, Dallas. <br /></span></p><p><span style='font-size:10pt'>Gondouin, M., M. P. Tixier, and G. L. Simard. 1957. An experimental study on the influence of the chemical composition of electrolytes on the SP curve. <em>Trans. AIME </em>210:58.<br /></span></p><p><span style='font-size:10pt'>Hassan M., A. Hossin, and A. Combaz. l976. Fundamentals of the differential gamma ray log-interpretation technique. Paper presented at the SPWLA 17th Annual Logging Symposium. June, Denver.<br /></span></p><p><span style='font-size:10pt'>Hilchie, D. W. 1984. A new water resistivity versus temperature equation. <em>The Log Analyst </em>(SPWLA) July-August: p. 20.<br /></span></p><p><span style='font-size:10pt'>Kokish, F. P. 1951. Gamma ray logging. <em>Oil and Gas Journal, </em>July 26.<br /></span></p><p><span style='font-size:10pt'>Marett, G., P. Chevalier, P. Souhaite, and J. Suau. 1976. Shaly sand evaluation using gamma ray spectrometry applied to the North Sea Jurassic. SPWLA 17th Annual Symposium. June.<br /></span></p><p><span style='font-size:10pt'>Neinast, G. S., and C. C. Knox. 1973. Normalization of well log data. SPWLA 14th Annual Symposium Transactions, Paper I.<br /></span></p><p><span style='font-size:10pt'>Nugent, W. H., G. R. Coates, and R. P Peebler. 1978. A new approach to carbonate analysis. SPWLA 19th Annual Logging Symposium, June.<br /></span></p><p><span style='font-size:10pt'>Overton, H. L., and L. B. Lipson. 1958. A correlation of the electrical properties of drilling fluids with solids content. <em>Trans. AIME, </em>Vol. 213.<br /></span></p><p><span style='font-size:10pt'>Poupon, A., R. W. Hoyle, and A. W. Schmidt. 1971. Log analysis in formations with complex lithologies. J. <em>Pet. Tech. </em>(August).<br /></span></p><p><span style='font-size:10pt'>Quirein, J. A., J. S. Gardner, and J. T. Watson. 1982. Combined natural gamma ray spectral/litho-density measurements applied to complex lithologies. SPE paper 11143, presented at the 57th Annual Technical Conference and Exhibition. September, New Orleans.<br /></span></p><p><span style='font-size:10pt'>Raymer, L. L., and W. P. Biggs. 1963. Matrix characteristics defined by porosity computations. Trans., SPWLA 4th Annual Logging Symposium.<br /></span></p><p><span style='font-size:10pt'>Raymer, L. L., W. R. Hoyle, M. P. Tixier. 1962. Formation density log applications in liquid-filled holes. J. <em>Pet. Tech. </em>(March).<br /></span></p><p><span style='font-size:10pt'>Raymer, L. L., and E. R. Hunt. 1980. An improved sonic transit time-to-porosity transform. SPWLA 21st Annual Logging Symposium. July, Lafayette, LA.<br /></span></p><p><span style='font-size:10pt'>Savre, W. C. 1963. Determination of a more accurate porosity and mineral composition in complex lithologies with the use of sonic, neutron, and density surveys. J. <em>Pet. Tech. </em>(September) 945-959.<br /></span></p><p><span style='font-size:10pt'>Schmidt, A. W., A. G. Land, J D. Yunker, and E. C. Kilgore. 1971. Applications of the Coriband technique to complex lithologies. SPWLA 12th Annual Logging Symposium (May), paper Z.<br /></span></p><p><span style='font-size:10pt'>Segesman, F. 1962. New SP correction charts. <em>Geophysics, </em>27(6): Part 1.<br /></span></p><p><span style='font-size:10pt'>Segesman, F. and M. P. Tixier. 1958. Some effects of invasion on the SP curve. SPE Annual Fall Meeting, October.<br /></span></p><p><span style='font-size:10pt'>Sherman, H., and S. Locke. 1975. Effect of porosity on depth of investigation of neutron and density sondes. Paper SPE 5510, presented at SPE Annual Fall Meeting, September-October, Dallas.<br /></span></p><p><span style='font-size:10pt'>Silva, P., and z. Bassiouni. 1981. A new approach to the determination of formation water resistivity from the SP log. SPWLA 22nd Annual Logging Symposium.<br /></span></p><p><span style='font-size:10pt'>Smith, H. D., Jr., C. A. Robbins, D. M. Arnold, and J. G. Deaton. 1983. A multi-function compensated spectral natural gamma ray logging system. SPE paper 12050, presented at the 58th Annual Technical Conference and Exhibition. October, San Francisco.<br /></span></p><p><span style='font-size:10pt'>Smolen, J., and L. Litsey. 1977. Formation evaluation using wireline formation tester pressure data. SPE paper 6822, presented at the 18th Annual Technical Conference and Exhibition. October, Denver.<br /></span></p><p><span style='font-size:10pt'>Stewart, G., and M. J. Wittmann. 1981. The application of the repeat formation tester to the analysis of naturally fractured reservoirs. SPE paper 10181, presented at the 22nd Annual Technical Conference and Exhibition. October, San Antonio.<br /></span></p><p><span style='font-size:10pt'>Tilly, H. 0., B. J. Gallagher, and T. D. Taylor. 1982. Methods for correcting porosity data in a gypsum-bearing carbonate reservoir. J. <em>Pet. Tech. </em>(October) 2449-2454.<br /></span></p><p><span style='font-size:10pt'>Tittman, J. 1956. Radiation logging lecture 1: Physical principle, and lecture 2: Applications. Petroleum engineering conference on the fundamental theory and quantitative analysis of electric and radioactivity logs. University of Kansas.<br /></span></p><p><span style='font-size:10pt'>Tittman, J., and J. S. WahI. 1965. The physical foundations of formation density logging (gamma-gamma). <em>Geophysics </em>(April).<br /></span></p><p><span style='font-size:10pt'>Tixier, M. P., and R. P. A1ger. 1968. Log evaluation of nonmetallic mineral deposits. SPWLA 9th Annual Logging Symposium, New Orleans.<br /></span></p><p><span style='font-size:10pt'>Truman, R. B., R. P. Alger, J. G. Connell, and R. L. Smith. 1972. Progress report on interpretation of the dual-spacing neutron log (CNL) in the U.S. SPWLA Trans., 13th Annual Logging Symposium, Tulsa.<br /></span></p><p><span style='font-size:10pt'>Wah1, J. S., J. Tittman, C. W. Johnstone. 1964. The dual spacing formation density log. J. <em>Pet. Tech. </em>(December) 17.<br /></span></p><p><span style='font-size:10pt'>Watson C. C. 1983. Numerical simulation of the litho-density tool lithology response. SPE paper 12051, presented at the Annual Technical Conference and Exhibition. October, San Francisco.<br /></span></p><p><span style='font-size:10pt'>Welex, a Halliburton Company. (undated). Open-hole services. Catalog G 6003.<br /></span></p><p><span style='font-size:10pt'>Williams, H., and H. F. Dunlap. 1984. Short term variations in drilling parameters, their measurement and implications. <em>The Log Analyst. </em>(SPWIA) Sept.- Oct. :3-9.<br /></span></p><p><br /> </p><p><span style='font-family:Times'><strong>NOMENCLATURE</strong></span><br /> </p><p><br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:134px'/><col style='width:469px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px' vAlign='middle' colspan='2'><p><span style='font-family:Times; font-size:13pt'><strong>Mud and Borehole Terms</strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>d<sub>h</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Diameter of hole (in.).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>h</span><sub>mc</sub></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Mudcake thickness (in.).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R</span><sub>m</sub></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity of mud (ohm-meters).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>mc</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity of mudcake (ohm-meters).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R</span><span style='font-size:7pt'><sub>mf</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity of mud filtrate (ohm-meters).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px' vAlign='middle' colspan='2'><p><span style='font-size:13pt'><strong>Formation Terms</strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>h</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Formation thickness (ft).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-family:Symbol; font-size:10pt'></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Porosity = Fraction of formation volume that is pore space.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>h</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Permeability (millidarcies) - Fluid flow characteristic of formation.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>d<sub>1</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity of connate water (ohm-meters).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>w</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Diameter of invasion (in.).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>wa</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Apparent resistivity of formation water (ohm-meters).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>o</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity of uninvaded formation with pores completely filled with connate water (ohm-meters).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>t</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity of uninvaded (deep ) formation with pores containing both connate water and hydrocarbon.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>i</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>An average resistivity of invaded zone; pores may contain a mixture of mud filtrate, connate water, and hydrocarbons; a nebulous term, not commonly used.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>xo</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity of shallow zone completely flushed by mud filtrate; pores may contain residual hydrocarbon as well as mud filtrate.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>F</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Formation factor=R<sub>o</sub>/R<sub>w</sub> or R<sub>xo</sub>/R<sub>mf</sub> by definition. = 1/<span style='font-family:Symbol'></span><sub>2</sub>(ls) or 0.81/<span style='font-family:Symbol'></span><sub>2</sub> (ss), by experiment.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>C</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Conductivity (mmho) = 1,000/resistivity (ohm-meters).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>S<sub>w</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Water saturation = Fraction of pore space in uninvaded zone containing water = (R<sub>o</sub>/R<sub>t</sub>)<sup>1/2</sup>=</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>S<sub>h</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Hydrocarbon saturation = Fraction of pore space in uninvaded zone containing hydrocarbons = (1 - S<sub>w</sub>).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>S<sub>o</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Oil saturation = Fraction of pore space in uninvaded zone containing oil.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>S<sub>g</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Gas saturation = Fraction of pore space in uninvaded zone containing gas; (S<sub>o</sub> + S<sub>g</sub> = S<sub>h</sub>).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>S<sub>xo</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Fraction of pore space in flushed zone containing water = (F R<sub>mf</sub>/R<sub>xo</sub>)<sup>1/2</sup></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>S<sub>hr</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Residual hydrocarbon saturation = Fraction of pore space in flushed zone containing hydrocarbons.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>S<sub>oxo</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Fraction of pore space in flushed zone containing oil.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>S<sub>gxo</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Fraction of pore space in flushed zone containing gas. (S<sub>oxo</sub> + S<sub>gxo</sub>=S<sub>hr</sub>).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px' colspan='2'><p><span style='font-size:13pt'><strong>Terms Related to Logging Measurements</strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>SP</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>SSP</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Static spontaneous potential = SP deflection (millivolts from shale line ) in PSP thick, clean formation.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>PSP</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Pseudo-static spontaneous potential = SP deflection (mV ) in thin or shaly formation.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px' colspan='2'><p><strong>Resistivity - Deep</strong></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>ILd</sub> or R<sub>ID</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity measured by deep induction.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>LLD</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity measured by deep laterolog.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>s</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Adjacent bed resistivity read by deep induction (for bed thickness correction).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px' colspan='2'><p><strong>Resistivity - Medium</strong></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>ILM</sub> or R<sub>IM</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity measured by medium induction.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>RLLS</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity measured by shallow laterolog.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>s</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Adjacent bed resistivity read by deep induction (or deep laterolog) .</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px' colspan='2'><p><strong>Resistivity - Shallow</strong></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>SN</sub> or R<sub>16</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity measured by short normal.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>LL8</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity measured by laterolog-8.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>SFL</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity measured by spherically focused.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px' colspan='2'><p><strong>Resistivity - Flushed Zone (Pad Measurements)</strong></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>MLL</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity measured by microlaterolog.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>PL</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity measured by proximity tool.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>M</sub></span><sub>S<span style='font-size:10pt'>FL</span></sub></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity measured by micro- spherically-focused logging tool.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px' colspan='2'><p><strong>Resistivity - Mudcake Controlled</strong></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>1</sub>"x1"</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity measured by extremely shallow microlog curve.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>2</sub>"</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity measured by slightly deeper microlog curve.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p><strong>Sonic</strong></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>t (or <span style='font-family:Symbol'></span>t)</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Travel time measured by sonic tool (<span style='font-family:Symbol'></span>sec/ft).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>t<sub>ma</sub> (or <span style='font-family:Symbol'></span>t<sub>ma</sub>)</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Travel time of solid rock matrix.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>t<sub>f</sub> (or <span style='font-family:Symbol'></span>t<sub>f</sub>)</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Travel time of 100% pore fluid.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>C<sub>p</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Compaction correction (³1).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>s</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sonic-derived porosity.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p><strong>Density</strong></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>b</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Bulk density measured by density tool (gm/cc).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>ma</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Density of solid rock matrix (grain density).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>g</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Density of pore fluid. </span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>D</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Density-derived porosity (ss or ls matrix specified).</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p><strong>Neutron</strong></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='font-family:Symbol'></span><sub>N</sub></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Neutron-derived porosity (ss or ls matrix specified).</span></p></td></tr></tbody></table></div><p><br /> </p><p><span style='font-family:Times; font-size:13pt'><strong>Service company nomenclature</strong></span><br /> <br/><span style='font-family:Times; font-size:13pt'><strong> </strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:299px'/><col style='width:255px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-family:Times; font-size:13pt'><strong>Schlumberger</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-family:Times; font-size:13pt'><strong>Computalog</strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt' vAlign='middle'><p><span style='font-size:10pt'>1. Electrical Log (ES)</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt' vAlign='middle'><p><span style='font-size:10pt'>Electrical Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>2. Induction Electric Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Induction Electrical Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>3. Induction Spherically</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>–</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Focused Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>–</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>4. Dual Induction Spherically Focused</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Dual Induction</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Laterolog</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>5. Laterolog-3</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Laterolog-3</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>6. Dual Laterolog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Dual Laterolog</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>7. Microlog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Micro-Electrical Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>8. Microlaterolog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Microlaterolog</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>9. Proximity Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>–</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>10. Microspherically Focused Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>–</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>11. Borehole Compensated Sonic Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Borehole Compensated Sonic</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>12. Long Spaced Sonic</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Log Acoustilog</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>13. Cement Bond/Variable Density Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sonic Cement Bond System</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>14. Gamma Ray Neutron</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Gamma Ray Neutron</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>15. Sidewall Neutron</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sidewall Neutron</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Porosity Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Porosity Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>16. Compensated Neutron Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Compensated Neutron Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>17. Thermal Neutron Decay Time Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>–</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>18. Formation Density Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Compensated Density Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>19. Litho-Density Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>–</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>20. High Resolution Dipmeter</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Four-Electrode Dipmeter</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>21. Formation Interval Tester</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>–</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>22. Repeat Formation Tester </span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Selective Formation Tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>23. Sidewall Sampler</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sidewall Core Gun</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>24. Electromagnetic Propagation Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Dielectric Constant Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>25. Borehole Geometry Tool</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>X-Y Caliper</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>26. Ultra Long Spacing Electric Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>–</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>27. Natural Gamma Ray Spectrometry</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>–</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>28. General Spectroscopy Tool</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>–</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>29. Well Seismic Tool</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>–</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>30. Fracture Identification Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Fracture Detection Log</span></p></td></tr></tbody></table></div><p><span style='font-family:Times; font-size:13pt'><strong>Service company nomenclature (Cont.)</strong></span><br /> <br/> <br /></p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:299px'/><col style='width:245px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Western Atlas</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Halliburton Logging Services</strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>1. Electrolog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Electric Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>2. Induction Electrolog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Induction Electric Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>3. 4. Dual Induction Induction Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Dual Induction Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>5. Focused Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Guard Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>6. Dual Laterolog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Dual Guard Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>7. Minilog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Contact Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>8. Microlaterolog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>F</span><span style='font-size:7pt'>o</span><span style='font-size:10pt'>R</span><span style='font-size:7pt'>xo</span><span style='font-size:10pt'> Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>9. Proximity Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>11. Borehole Compensated</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Acoustic Velocity Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>10.-</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Acoustilog</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>12. Long Spacing BHC Acoustilog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>13. Acoustic Cement Bond Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Microseismogram</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>14. Gamma Ray Neutron</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Gamma Ray Neutron</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>15. Sidewall Epithermal Neutron Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sidewall Neutron Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>16. Compensated Neutron Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Dual Spaced Neutron</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>17. Neutron Lifetime Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Thermal Multigate Decay</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>18. Compensated Densilog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Density Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>19. Z Densilog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>–</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>20. Diplog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Diplog</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>21. Formation Tester</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Formation Test</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>22. Formation Multi Tester</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Multiset Tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>23. Corgun</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sidewall Coring</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>24. Dielectric Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Dielectric Constant Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>25. Caliper Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Caliper</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>26. –</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>27. Spectralog</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Compensated</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>28. Carbon/Oxygen Log</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>29. Borehole Seismic Record</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>30. –</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p> </p></td></tr></tbody></table></div><p><br /> </p><p><br /> </p><p><br /> </p><p><span style='font-family:Times; font-size:13pt'><strong>Logging Tools: Quick Reference</strong></span><br /> <span style='font-family:Arial Unicode MS'><br /> </span></p><p><span style='font-size:10pt'>Openhole logs, logging tools, and what they measure</span><br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:196px'/><col style='width:409px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Induction</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Primary log in fresh or oil- base mud where invasion is shallow</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Measures formation resistivity, R</span><sub>t</sub></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Behaves badly in salt muds and/or large boreholes and in formation with high resistivities</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often combined with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Porosity tools</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>20 kHz coil induces current in formation</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Deep induction, conductivity, shallow-focused electric log SP and/or GR</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Dual induction</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Primary log in fresh mud where invasion is moderate or deep</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Measures formation resistivity, R</span><sub>t</sub></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Behaves badly in salt muds and/or large boreholes</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often combined with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Porosity tools</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>20 kHz coil induces current in formation</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Deep induction, medium induction, shallow-focused electric log SP and/or GR</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Dual laterolog</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Openhole</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Measures formation resistivity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Works best in salt muds. Cannot be used in oil-base muds</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often combined with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Porosity tools</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Horizontal bean of current sent to formation</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Laterolog deep, laterolog shallow, microfocused electric log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Microlog</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Microresistivity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Openhole</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sand count, permeability indication, invaded-zone resistivity R<sub>xo</sub></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Water-base muds required</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often combined with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Other microresistivity devices</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Measures two shallow investigation resistivities</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Micro (normal), micro (inverse or lateral)</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log::</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Compensated density</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Radioactivity/porosity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Openhole, primary porosity device</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Measures porosity, indication of lithology</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Requires smooth borehole wall</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often combined with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Other porosity and/or resistivity tools </span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Gamma rays from source scatter in formation </span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>; Bulk density, , correction, apparent porosity,</span><br /> </p><p><span style='font-size:10pt'>(for selected 1ithology)</span></p></td></tr></tbody></table></div><p> <br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:196px'/><col style='width:409px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Compensated neutron</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Radioactivity/porosity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Open or cased hole</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Measures porosity/lithology</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Requires liquid-filled hole</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often combined with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Other porosity and/or resistivity tools</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Fast neutrons thermalized by hydrogen atoms in formation</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>(for selected lithology), GR, etc.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Acoustic</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sonic/porosity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Openhole</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Measures porosity, lithology</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Some hole size limitations depending on value of formation</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often combined with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Other porosity and/or resistivity tools</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Measures travel time of compressional waves in formation. If wave trains are recorded, the travel time of shear waves in the formation can also be deduced.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>, wave train</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Gamma ray</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Radioactivity/lithology</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Open or cased hole</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sand/shale discriminator</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>None</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often combined with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Any and all open- and cased-hole tools</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Scintillation detector measures natural formation gamma ray activity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>GR</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Gamma ray spectral log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Radioactivity/lithology</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Open or cased hole</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Measures K, U, and Th concentrations in formation</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Slow logging speed</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often combined with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Neutron/density</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Gamma ray energy spectrum characterizes source of gamma rays</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Total counts, uranium, </span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>potassium, and thorium</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Dipmeter</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Resistivity correlation/ orientation</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Openhole</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Measures formation dip, detects fractures</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Does not perform well in oil-base muds</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often combined with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>SP, GR</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>4, 6, or 8 independent pad electrodes record correlation curves</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Hole deviation, azimuth of Pad 1, relative bearing, correlation, caliper</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sidewall sampler</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Percussion core cutter</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Openhole</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Retrieves samples of the formation</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limited number of cores (typically 30 or 60) per trip in hole</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often combined with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>SP for depth control</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Explosive charge propels hollow cylinder into formation</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>SP, only for depth control; recovery report</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>F-overlay</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Quick-look log analysis</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Openhole</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Generates R</span>o<span style='font-size:10pt'> curve</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Works best in clean formations of constant lithology</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often generated with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Density log or neutron/ density when run with deep induction or deep laterolog</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>If R</span>o<span style='font-size:10pt'> < R</span><sub>t</sub><span style='font-size:10pt'> then S</span>w<span style='font-size:10pt'> < 100</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>F or rescaled as an R</span>o<span style='font-size:10pt'> curve</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R</span><sub>wa</sub></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Quick-look log analysis</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Openhole</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Distinguishes water- and oil-bearing rocks, finds R</span>w</p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Needs careful attention to detail in gas-bearing formations and/or shales, depending on porosity tool used</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often generated with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Sonic, porosity/resistivity combination tools</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Apparent porosity and R</span><sub>t</sub><span style='font-size:10pt'> combined to give apparent water resistivity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R</span><sub>wa</sub></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-bottom: solid 0.75pt'><p> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Generic name of log:</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>xo</sub>/R</span><sub>t</sub><span style='font-size:10pt'> versus SP</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Type of tool:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Quick-look log analysis</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>When run:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Openhole, fresh muds</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Purpose:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Hydrocarbon indicator</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Limitations:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Requires an SP log. Used primarily when no porosity tool is available</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Often generated with:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Induction log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Operating principle:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Scaled R<sub>xo</sub>R<sub>xo</sub>/R</span><sub>t</sub><span style='font-size:10pt'> ratio compared to SP</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Curves recorded:</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>R<sub>xo</sub>/R</span><sub>t</sub><span style='font-size:10pt'>, SP</span></p></td></tr></tbody></table></div><p><strong>General Recommended Logging Program<span style='font-size:13pt'><br /> </span><span style='font-size:10pt'> <br /></span></strong></p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:148px'/><col style='width:424px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Condition--</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Correlation and lithology in sand/shale</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Fresh mud </span><br /> <br/></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Dual Induction--SFL--GR/SP; Induction Electrical; Dual Laterolog-- GR/SP (low porosity and/or high resistivities); Sidewall Cores </span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>The dual induction and dual laterolog devices are superior to single induction and single laterolog in all cases Sidewall cores give lithology in sand/ shale</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Porosity; water saturation; lithology in carbonates and evaporates; hydrocarbon type</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Density and/or Neutron and /or Sonic and GR; Formation Tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>For Shaly sands or simple mixed lithologies, density--neutron or neutron--sonic. For complex mixed lithologies use all three. For hydrocarbon type as above and or Formation Tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Producible hydrocarbons and permeability indicators</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Proximity-Microlog; Microlaterolog or Micro-SFL; Dual Resistivity device; Sidewall Cores; Formation Tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>Proximity log used for thick mudcake; Microlaterolog for thin mudcake; Micro-SFL available with Dual Laterolog. Sidewall cores give permeability estimate in shaly sands</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Hydrocarbon indication at the wellsite</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Wellsite Computer Products, including apparent formation water resistivity, Rwa; formation factor/resistivity overlay; and Rxo/Rt vs. SP overlay</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>Available with computer units only. Others available with both units.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Formation dip magnitude and directional</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Dipmeter</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>Wellbore directional information is also available</span></p></td></tr></tbody></table></div><p> <br /> </p><div><table border='0' style='border-collapse:collapse'><colgroup><col style='width:143px'/><col style='width:441px'/></colgroup><tbody valign='top'><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Condition--</strong></span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: solid 0.75pt; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Correlation and lithology in sand/shale</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Salt mud</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Dual Laterolog--Micro-SFL--GR</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p/></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>In some areas of low porosity and/or mixed lithology the neutron or density--neutron is usable as a correlation log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Porosity, water saturation, and lithology in carbonates and evaporates; hydrocarbon type</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Density and/or Neutron and/or Sonic and GR; Formation Tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>See <span style='text-decoration:underline'>Remarks</span> under fresh mud</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Producible hydrocarbons and permeability indicators</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Proximity--Microlog; Microlaterolog-Microlog; Dual Laterolog--Micro-SFL; Sidewall Core; Formation Tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>In very salty muds or when Rxo is less than Rmc, the microlog results may be unsatisfactory. See <span style='text-decoration:underline'>Remarks</span> under fresh mud</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Hydrocarbon indication at the wellsite</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Wellsite Computer Products; Rwa, Ro Overlay</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>See <span style='text-decoration:underline'>Remarks</span> under fresh mud. Apparent formation water resistivity may not be satisfactory in low and/or mixed lithologies</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Formation dip magnitude and directional</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Dipmeter</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>Wellbore directional information is also available</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Condition--</strong> Oil-base mud</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Correlation and lithology in sand/shale</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Dual Induction--GR; Induction--GR; Sidewall Cores</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>High temperature (350 to 400&deg;F) will restrict the use of the dual induction and sidewall cores</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong></span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'>Porosity, water saturation, lithology in carbonates and evaporites; hydrocarbon type</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Density and/or Neutron and/or Sonic; Formation Tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>See <span style='text-decoration:underline'>Remarks</span> under fresh mud. High temperature (350&deg;F) and small holes(6 in.) restrict the use of the formation tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Producible hydrocarbons and permeability indicators</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Dual Induction; Sidewall Cores; Formation Tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>Sidewall cores give permeability estimates in shaly sands</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Hydrocarbon indication at the wellsite</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Wellsite Computer Products; Rwa, Ro Overlay</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>See <span style='text-decoration:underline'>Remarks</span> under fresh mud</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Formation dip magnitude and directional</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Dipmeter</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>See <span style='text-decoration:underline'>Remarks</span> under fresh mud</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Condition--</strong> Air- or gas-filled hole</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Resistivity, correlation, and lithology in sand/shale</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Dual Induction--GR; Induction--GR</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>None</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Porosity, water saturation, gas saturation, estimated lithology in carbonated and evaporates</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Density and/or Neutron</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>Dual spacing neutron CNL cannot be used; must use gamma ray-neutron(GRN) or preferable sidewall neutron porosity (SNP)</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Permeability Indicator</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Temperature Log; Noise Log</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>Gas entry</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Hydrocarbon indication at the wellsite</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Wellsite Computer Products; Ro Overlay, Rwa</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>See <span style='text-decoration:underline'>Remarks</span> under fresh mud</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Condition--</strong> Fresh or unknown formation water</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Resistivity; correlation and estimated lithology in sand/shale</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>See fresh mud and salt mud</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>See fresh mud and salt mud</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Porosity water saturation; estimated lithology in carbonates and evaporates; hydrocarbon type</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Density and/or Neutron and/or Sonic and GR; Electromagnetic Propagation Tool; Inelastic Neutron Scattering and Capture Gamma Ray Spectroscopy; Formation Tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>Under conditions of no invasion the electromagnetic propagation tool will yield water saturation directly. See <span style='text-decoration:underline'>Remarks</span> under fresh mud</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Producible hydrocarbons and permeability indicators</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Sidewall Cores; Formation Tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>None</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Hydrocarbon indication at the wellsite</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Wellsite Computer Products.</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>See <span style='text-decoration:underline'>Remarks</span> under fresh mud. May use electromagnetic propagation tool</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Condition--</strong> Cased hole</span></p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Fluid type and lithology</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Pulsed Neutron Log; Inelastic Neutron Scattering and Capture Gamma Ray Spectroscopy; GR and Natural Gamma Ray Spectroscopy</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>None</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Porosity and hydrocarbon type</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Pulsed Neutron Log; Gamma Ray-Neutron; Density Formation Tester; Inelastic Neutron Scattering and Capture Gamma Ray Spectroscopy</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>Dual spacing neutron (CNL) cannot be used if hole is gas filled. Under favorable conditions the density may be used for porosity</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><strong>Data Desired</strong> </span><br /> <br/><span style='font-size:10pt'>Permeability</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Recommended Services</span> </span><br /> <br/><span style='font-size:10pt'>Formation Tester</span></p></td></tr><tr><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: solid 0.75pt; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'> </span> </p></td><td style='padding-top: 7px; padding-left: 7px; padding-bottom: 7px; padding-right: 7px; border-top: none; border-left: none; border-bottom: solid 0.75pt; border-right: solid 0.75pt'><p><span style='font-size:10pt'><span style='text-decoration:underline'>Remarks</span> </span><br /> <br/><span style='font-size:10pt'>None</span></p></td></tr></tbody></table></div><p> <br /> </p><p><br /> </p><p><br /> </p></span>Unknownnoreply@blogger.com0