Introduction to Well Logging (Logging Procedures)

Logging Procedures

Logging Program

Choosing a Logging Suite

A logging suite should be selected on the basis of

• type of well--wildcat or development
  

hole conditions--depth, deviation from vertical, hole size, mud type

formation fluid content--(fresh or salt) connate water

formation type--clastic or carbonate

economics--rig time, logging dollars, and so forth

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.

Depth, Pressure, and Temperature Considerations

The majority of logging tools are rated at 20,000 psi and 350 F. These parameters are adequate for logging most holes. For higher temperatures, special tools are available from the logging service companies.

 

Hole Size and Deviation

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.

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.

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.

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.

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

keeping the openhole section as short as possible

removal of centralizers and standoff pads

use of a "hole finder," a rubber snout on the bottom of the logging tool string

use of logging tools especially adapted to be run to the bottom of the hole on drillpipe

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 have been logged.

Logging Programs

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.

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.

A cross-reference list of tool nomenclature of the various service companies is presented in the Reference Section under Service Company Terminology.

Influence of the Mud Program

The mud type influences the choice of logging tool, especially the choice of resistivity tool.

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.

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.

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_xo) and decrease the water saturation (S_xo) 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.

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.

Choosing When to Log

Logs should be run just prior to the running and setting of a casing string. Once casing is set, logging choices are severely limited.

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.

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.

 

Service Co. Notification

UNDER CONSTRUCTION …!

Service Co. Mobilization

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Rig up and Pre Survey

UNDER CONSTRUCTION …!

Running The Tool String

UNDER CONSTRUCTION …!

Repeat Section

UNDER CONSTRUCTION …!

Main Survey

UNDER CONSTRUCTION …!

Post Survey

UNDER CONSTRUCTION …!

Ringing Down

UNDER CONSTRUCTION …!

Stuck Cable or Tools

Getting Stuck

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. Figure 1 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:

the present depth of the tool

the cable's surface tension just before getting stuck

the cable type and size

the cable-head weakpoint rating

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.

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.

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? Figure 2 will help to explain the tensions involved.

 

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 ( Figure 3 ).

Alternatives to Fishing

There are several alternatives available for recovering the stuck tool and/or cable:

Leave the cable attached to the tool and run a side-door overshot.

Use the "cut and thread" overshot technique.

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.

Figure 4 illustrates the different methods.

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.

 

Quality Control

Purpose

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.

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.

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.

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.

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).

Practical Checks

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.

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.

Acceptance Standards for Logs

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.

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.

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.

Overall Technical Quality The technical quality of the data may be affected by many factors:

equipment malfunction

rugose borehole

sticking tools

logging engineer's errors

tool rotation

excess logging speed

deviated wells

tool eccentricity

formation alteration

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.

Repeatability 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.

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).

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.

Offset Logs If the well is in a developing field, available offset logs are likely to be useful, especially in an unfamiliar or geologically complex area.

Absolute Log Values 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. Table 1 lists these natural benchmarks for several common tools.

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.

Depth Measurements 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.

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.

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).

Logging Speeds 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 Table 2 .

 

A.6. Rock and Fluid Properties

Definitions

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_p. The sum of the two gives the bulk volume VB.

VB = VG + VP

Porosity is thus the ratio of VP to VB

It can be measured in a number of ways; for example,

or

Deriving a value of porosity depends on the mechanism of the porosity-measuring device and knowledge of any two of the three volume fractions.

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

where Vw is the volume of water.

Permeability is defined as the ability of a porous system to allow fluids to flow through it.

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,
P; and fluid viscosity, such that

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.

If Q is in cc/sec, A is in sq cm, P \ L is in atmospheres/cm, and is in centipoise, then k is in darcies. The practical unit is the millidarcy, abbreviated md, equal to 1/1000 of a darcy.

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. Figure 1 shows some of these trends

 

Porosity

Introduction

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.

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.

The Genesis of Reservoir Rooks

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.

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.

The packing of the grains ( Figure 1 ) 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.

In unit volume n³ spheres are packed n to a side. The total volume is (nd)³. The volume of any one sphere is (4/3)(d/2)³, so the volume occupied by n³ spheres is (4/3)(nd/2)³. Thus the porosity is

which simplifies to (1 - /6) or 0.4764. Note that the term d cancels out and is not a determining factor.

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).

For a given grain size, porosity decreases as sorting gets poorer, since intergranular pores may be occupied by eversmaller grains.

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

generally fits most normally pressured reservoirs; i.e., the log of porosity is linear with depth. For example, if fo , 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.

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 (P), and fluid viscosity (µ), such that,

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, 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.

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. Figure 2 shows some of these trends.

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,

k=3 / C(As)²

where C is the Kozeny constant and As is internal surface area per unit bulk volume.

For fracture systems, generalized formulas have been developed relating the permeability to the square of the fracture width.

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.

Summary

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.

Definitions of Porosity and Effective Porosity

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 effective porosity. Pores that are blocked in some way (by clay particles, silt, etc.) are ineffective. Thus a preferred definition gives total porosity (_T) as the volume of the pores divided by the volume of rock, and effective porosity (_e as the volume of interconnected pores divided by the volume of rock. Figure 3 illustrates this concept.

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 porosity unit, or P.U. By using unit rather than percentage, a 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.

Types of Porosity

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 matrix porosity. 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 fracture porosity. 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.

Matrix Porosity

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.

Fracture Porosity

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.

Absolute Porosity

UNDER CONSTRUCTION …!

Relative Permeability

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 effective 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

and

Furthermore, we find that the total flow rate Q_t = (Q_o + Q_w) 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.

A useful way to quantify this phenomenon is to define the relative permeability, k_r. 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.

k_ro = k_r/k

k_rw = k_w/k

Figure 1 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_ro decreases until it effectively reaches zero at some high water saturation corresponding to S_or, the residual oil saturation.

Relative permeability to water, on the other hand, commences effectively at zero when the rock is at S_wi and thereafter increases as S_w increases. It should also be noted that in an oil-wet system k_ro is always less, at a given S_w, than in a water-wet system. Conversely, k_rw is always greater in an oil-wet system than in a water-wet one.

 

 

A common way of representing these differences is a plot of the relative permeability ratio, k_rw/k_ro, versus water saturation, S_w. Figure 2 shows that in water-wet systems the relation is such that if the k_rw/k_ro ratio is on a log scale and S_w on a linear one, a straight line is obtained. In an oil-wet system an S-shaped line is observed.

When plotting relative permeability curves, the distinction is usually made between two possible scenarios: imbibition and drainage. 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. Figure 3 illustrates these different cases.

Many workers in this field have proposed generalized empirical equations to relate k_ro and k_rw to S_w, S_wi, and S_or 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

If a well is completed above the transition zone where the reservoir is at irreducible water saturation (i.e., k_rw = 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:

The oil-flow rate is Q_o = k_o • P • A/µ_o • L

The water-flow rate is Q_w = k_w • P • A/µ_w • L

Thus the water-oil ratio is given by

WOR = k_w µ_o/k_o µ_w

The ratio k_w/k_o is numerically equivalent to k_rw/k_ro, which can be deduced from measured relative permeability ratios or estimated from one of the generalized correlations.

The actual water cut of the production into the wellbore is given by

WC = Q_w/(Q_w + Q_o)

which is equivalent to

WC = WOR/(l + WOR)

Surface water cut is a function of the formation volume factors of the oil and water, so the complete expression is

WC = WOR _o/(_w + WOR • _o)

 

Fluid Saturation

UNDER CONSTRUCTION …!

Fluid Distribution in the Reservoir

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 Figure 1 . Eolian dune sediments, initially deposited in a water-free environment, are the exception to this rule.

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.

 

Figure 2 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.

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 ( Figure 3 ). A capillary tube of radius r is found to support a column of water of height h. If the density of the air is _a and the density of the water is _w, then the pressure differential at the air-water contact is simply (_w - _a)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

2rT cos = (_w - _a)h • r²

Force = Pressure • Area

By simplifying and rearranging this expression we have

We see that the smaller r gets, the larger h gets.

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:

• the surface tension, T, between the two phases (here oil and water)
  

the contact angle,  , between the wetting fluid (water) and the rock

the radius of the pore throats (r)

the density difference between the phases (_w - _o in this case)

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 ( Figure 4 ).

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.

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, _o and _w 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. Figure 5 illustrates this important concept by comparing capillary pressure curves for four rock systems of different porosity and permeability.

 

Laboratory Measurement

Measuring Porosity

Porosity may be measured by a variety of methods, including

• borehole gravimetrics
  
• wireline logging
  
• core analysis
  

Each method investigates a different volume of the formation. The borehole gravimeter samples very large volumes in the order of 10³ to 10⁶ 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^-3 to 10^-1 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
agree.

Measuring Permeability

There are many ways to estimate permeability, including

• pressure buildup from drillstem tests
  
• pressure drawdown and buildup from wireline repeat formation testers
  
• log analysis
  
• core analysis
  

Again, each method investigates an effective radius different from the others by several orders of magnitude. In increasing order, these are:

 

Method	Approximate radius (ft.)
DST	102 - 104
RFT buildup	10 - 102
RFT drawdown	10-2 - 100
log analysis	10-1 - 5
core analysis	8 x 10-2 - 3 x 10-1

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).

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:

k = 8581 • 4.4 • S_wi
^-2 (Timur)

k = [250 • 3 • S_wi-1]2 -oils (Schlumberger) or

k = [79 •  3 • S_wi-1]2 -gas (after Wyllie and Rose)

for O/W (Raymer and Freeman 1984) or

for G/_W

where:

Swi	is fractional irreducible water saturation
	is fractional porosity
h	is height in feet from free-water level to the top of the transition zone
w	is the water density in gm/cc
o	is the oil density in gm/cc
g	is the gas density in gm/cc

The first three equations (Timur, Schlumberger, Wyllie/Rose) apply to points above the transition zone, since that is the only Place that S_wi can be measured. The fourth equation applies to the oil/water transition zone, and the fifth to the gas/water transition zone.

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.

Figure 1 gives a graphical solution to the equation

where

and c = 20.

_w and _hy are in gm/cc, R/D is expressed in ohms/ft and k is in md.

 

Measuring Saturation

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.

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.

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.

Water Resistivity (R_w) 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_w is required.

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. Figure 2 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_w, 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_w • L/A.

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_o. It can be seen that A is proportional to the porosity itself. Thus we may write

R_o = f (R_w,)

or that R_o is related to R_w by some formation factor, F, such that

R_o=F • R_w

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_w, and the resistivity of the 100% water saturation rock system, R_o. when the results were plotted, he found a series of straight lines of slope F, as shown in Figure 3 .

 

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. Figure 4 illustrates the concept.

Note that by definition the formation factor is the ratio of R_o/R_w 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

F = a / m

where a and m are experimentally determined constants. In porous formations, a is usually close to 1 and m is usually close to 2 ( Figure 5 ).

 

Three commonly used formation-factor-to-porosity relations are:

F = 1/ 2	(compacted formations and chalky rocks)
F = 0.62/ 2.15	(Humble formula-soft formations and sucrosic rocks)
F = 0.81/ 2	(simplified Humble formula for sands)

For a wet formation, we may combine the F to f relationship with the definition of F, and arrive at the equation

R_w = R_o/F = R_o • m/a

Saturation Archie's experiments showed that the saturation of a clean formation could he expressed in terms of its true resistivity as S_wn = R_o/R_t.

Since R_o = F • R_w, the water saturation equation can also be written

S_wn = F • R_w/R_t,

where n is the saturation exponent and is usually set to 2 ( Figure 6 ).

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 only become noticeable when they begin to provide a substantial percentage of the total rock system conductivity.

Permeability Estimates

As with porosity measurement, there are many ways to estimate permeability. These include

• pressure buildup from drillstem tests
  
• pressure drawdown and buildup from wireline repeat formation testers
  
• log analysis
  
• core analysis
  

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

 

Method	Approximate radius of investigation, ft
DST	102 - 104
RFT buildup	10 - 102
RFT drawdown	10-2 - 100
log analysis	10-1 - 5
core analysis	8 x 10-2 - 3 x 10-1

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).

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

 

	Timur (1968)
	(Oils)
	(Gas)

where:

 

k	= permeability (in md)
	= fractional porosity
Swi	= fractional irreducible water saturation

 

 

Figure 7 shows a graphical representation of the Wyllie and Rose relationship where  and S_wi are crossplotted to yield values of k.

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.

Figure 8 gives a graphical solution to the equation

and

C = 20

where _w and _h are densities of water and hydrocarbon in gm/cc; R/D is expressed in ohms/ft and k is in md.

 

Laboratory Measurement of Porosity

Rock samples suitable for laboratory analysis may come from a variety of sources, such as cuttings, sidewall cores and/or plugs, and conventional cores.

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

• porosity
  
• fluid saturation
  
• permeability
  
• relative permeability
  
• wettability
  
• capillary pressure
  
• pore throat distribution
  
• grain size distribution
  
• grain density
  
• mineral composition
  
• electrical properties
  
• effects of overburden stress
  
• sensitivity to fluids
  
• hydrocarbon analysis
  

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.

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. Figure 9 shows an example.

 

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.

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.

Fresh cores are cores cut with water- or oil-base muds preserved without cleaning. Native state cores are those cut with lease crude as the coring fluid to minimize changes in rock wettability. Restored cores are cleaned and dried prior to testing; their wettability and fluid distributions are changed.

Cores may be epoxy coated, jacketed in heat-shrinkable tubing or metal (for unconsolidated cores), or molded in lucite.

A porous rock system has two components: the grain volume and the pore volume. The sum of the two gives the bulk volume:

VB = VG + VP

The porosity is defined as the ratio of the pore volume to the bulk volume, for example,

Thus porosity can be measured in a number of ways, such as

or

Provided any two of the three entities are measured, porosity can be deduced. Among the commonly employed methods of deduction are

• summation of fluids 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.
  
• Boyle's law 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.
  
• 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.
  
• Washburn-Bunting vacuum extraction and collection ofgas in the pore space, which is somewhat similarto the Boyle's law method and measures VP.
  
• liquid restoration, 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.
  
• grain density 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.
  

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.

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 in addition to other methods.

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.

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 Figure 10 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.

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.

 

Effects of Overburden Pressure

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  and k. Figure 11 illustrates the effects of net overburden pressure on permeability.

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.

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.

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%.

 

Porosity and Formation Factor

Porosity may be measured by a variety of methods, including

• core analysis
  
• wireline logging
  
• borehole gravimetrics
  

Each method investigates a different volume of the formation. Core analysis investigates very small volumes, ranging from l0^-3 to 10^-1 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 10³ to 10⁶ cubic feet. With nine orders of magnitude (10^-3 to 10⁶), one should not be surprised to learn that porosity estimates using different tools and techniques do not always agree.

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.

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.

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.

Porosity and Permeability

UNDER CONSTRUCTION …!

Porosity and Water Saturation

Interpreting Petrophysical Data

When a formation is above the transition zone, i.e., at irreducible water saturation, the product of  and S_w 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

f • S_wi product .

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_w reveals the presence or absence of a transition zone.

Figure 1 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.

Reservoirs may be characterized by the f • S_wi 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_wµ_o/k_oµ_w), 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_w, water production can be expected. This salient fact is all too often overlooked.

Resistivity

Conduction of Electric Current in Porous Rocks

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

V = I • R

Volts = Amps • Ohms

Of more interest in logging is the resistivity, rather than the resistance, 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. Figure 1 illustrates this concept. The unit of resistivity is the ohm-meter2/meter and abbreviated as ½m2/m or ½m.

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 m2/m" is really meant.

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.

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.

conductivity (C) (in milliohms) = 1000/resistivity (in ohm-m)

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 F.

Types of Resistivity Measurements

Given an infinite isotropic homogeneous medium with a spherical electrode implanted in it emitting a current I radially in a spherical distribution (see Figure 2 ), the voltage drop between any two concentric spherical shells with radii  and  + d can be determined in the following manner:

dV = I • dr

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

dr = R • d / 4 ¹^  and,

dV = I • R • d / 4 ¹^

Integrating this equation from  = A to  = M, the equation to determine the value for V_m becomes

where V_m is the measured voltage at some point a distance M from the current electrode A, and R is the formation resistivity .

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 .

Resistivity

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.

The resistivity (R) of a formation depends on:

• the resistivity of the formation water
  

the amount of water present

the pore structure geometry

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. Figure 3 illustrates this concept. The unit of resistivity is the ohm-meter2/meter, abbreviated as m2/m, or simply ohm-meter (ohm-m).

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.

 

 

 

Conductivity is usually expressed in millimhos per meter (mmho/m), where 1000 mmho/m = 1 mho/m:

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.

Water Resistivity (R_w)

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_w is required to determine water saturation by quantitative analysis of porosity and resistivity logs.

The ability of a rock to conduct electricity is due entirely to the ions in the water found in its pore spaces. Figure 4 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_w, 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_w L/A. By definition the resistivity of water-bearing porous rock systems is R0.

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:

R_o = f(R_w,f)

 

 

The resistivity of the formation water, R_w 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.

 

Electrical Formation Factor

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_w, and the resistivity of the 100% water-saturated rock system, R_o. When the results were plotted, he found a series of straight lines of slope F, as shown in Figure 5 . Archie determined that the relationship between R_o and R_w is as follows:

R_o = F RW

R_o = F RW

Archie conducted many experiments that showed that the formation factor is related to porosity in a predictable manner. Our simple tubular model ( Figure 6 ) 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.

 

By definition, the formation factor is the ratio of R_o/R_w; 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

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 ( Figure 7 ).

Two commonly used formation-factor-to-porosity relations are

(carbonates)

(Humble formula – sands)

To eliminate the fractional cementation exponent, the Humble formula is sometimes simplified to

The exponent m can be as high as 3 in some severely ooliclastic packs.

In a wet formation we may therefore combine the F to 4 relationship with the definition of F and arrive at the equation

Resistivity Index and Water Saturation

Archie's experiments showed that the saturation of a core could be related to its resistivity. He found that the fractional water saturation, S_w, was equal to the square root of the ratio of the wet formation resistivity, R_o to the formation resistivity, R_t. That is,

In a more generalized form this equation can be written as

where n is the saturation exponent ( Figure 8 ). Laboratory experiments have shown n = 2.0 in the average case.

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 only conductive path. However, a second conductive path exists, due to surface conductance effects.

Resistivity Measurement

UNDER CONSTRUCTION …!

Resistivity Relationship

UNDER CONSTRUCTION …!

Elastic Wave Propagation

Introduction

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,

• acoustic logs and check shot surveys can be used to "calibrate" seismic surveys
  

combined acoustic and density logs can provide "synthetic seismic" traces

combined acoustic and density logs can deduce formation mechanical properties, used in turn to deduce pore pressure, rock compressibility, fracture gradients, sanding problems, etc.

acoustic logs, used in conjunction with other logs, can deduce porosity, lithology, and fluid saturations

in borehole measurements, acoustic logs can produce vertical seismic profiles (VSP) that "see" below the bottom of the well

acoustic tools may be used for cement bond logging in cased holes

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.

 

Propagation of Elastic Waves

Two types of sound waves are propagated in an infinite medium:

Compressional Waves. Compressional (or pressure) waves are longitudinal, that is, the direction of propagation is parallel to the direction of particle displacement ( Figure 1 ). Gases and liquids, as well as solids, tend to oppose compression, therefore compressional waves can be propagated through them.

 

Shear Waves. Shear waves are transverse; that is, the direction of propagation is perpendicular to the direction of particle displacement ( Figure 2 ). 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.

In a finite medium (e.g., a borehole) other types of waves are propagated. These are guided waves, which include:

Rayleigh Waves. 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_Rayleigh is 86% to 96% of VShear). 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.

Stoneley Waves. 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.

Proper interpretation of any measurement made using elastic wave data requires an understanding of the elastic properties of a medium.

Elastic Constants

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.

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 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, t_c and t_s, respectively, as shown in Table 1 .

 

 

Exercise 1.

A 30% porous sandstone bed is 100 ft thick. It is 100% saturated with mud filtrate (S_xo = 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.

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.)

Solution 1:

Filtrate volume =250 Cu ft or 44.5 bbl

Linear ft of drillpipe = 6774.44 ft

Exercise 2.

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?

Solution 2:

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.

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%.

Exercise 3.

If r_b = 2.4 gm/cc

and _f
= 1.0 gm/cc

and the rock is sandstone, find

_D
= ?

Solution 3:

_D
= 15.2%

 

REFERENCES

Allaud, L., and N. Martin. 1977. Schlumberger, the history of a technique. New York: Wiley and Sons.

Bateman, R. M. 1984. Log quality control. Boston: IHRDC.

___________. 1985. Openhole log analysis and formation evaluation. Boston: IHRDC.

Bateman, R. N., and E. E. Konen. 1977. The log analyst and the programmable pocket calculator. The Log Analyst (SPWLA) Sept. -Oct.

Burke, J. A., R. L. Campbell, and A. W. Schmidt. 1969. The litho-porosity crossplot. SPWLA Symposium, May.

___________. 1969. The litho-porosity crossplot. The Log Analyst (SPWLA) Nov. -Dec.

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.

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.

Doll, H. G. 1949. The SP log: Theoretical analysis and principles of interpretation. Trans. AIME 179:146.

_________. 1949. The SP log in shaly sands. J. Pet. Tech. 2912.

__________. 1955. The invasion process in high permeability sands. Pet. Engr. (January).

Dresser Industries Inc. 1974. Log Review 1. Dresser Atlas.

_________. 1979. Gamma ray spectral data assists in complex formation evaluation. Dresser Atlas (February).

_________. 1980. Formation multi-tester interpretation manual. Dresser Atlas (June) 9404.

_________. 1981. Spectralog. Dresser Atlas.

_________. 1984. Wireline service catalog. Dresser Atlas.

_________. 1984. Services catalog. Dresser Atlas.

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.

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.

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.

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.

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).

Fitzgerald, D. D. 1980. Obtaining valid dipmeter surveys in deviated wells. World Oil (November).

Garner, J. S., and J. L. Dumanoir. 1980. Litho-density log interpretation. Paper N, Trans., SPWLA 21st Annual Logging Symposium. July, Lafayette, LA.

Gaymard, R., and A. Poupon. 1968. Response of neutron and formation density logs in hydrocarbon-bearing formations. The Log Analyst (SPWLA) Sept. -Oct.

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.

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. AIME 210:58.

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.

Hilchie, D. W. 1984. A new water resistivity versus temperature equation. The Log Analyst (SPWLA) July-August: p. 20.

Kokish, F. P. 1951. Gamma ray logging. Oil and Gas Journal, July 26.

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.

Neinast, G. S., and C. C. Knox. 1973. Normalization of well log data. SPWLA 14th Annual Symposium Transactions, Paper I.

Nugent, W. H., G. R. Coates, and R. P Peebler. 1978. A new approach to carbonate analysis. SPWLA 19th Annual Logging Symposium, June.

Overton, H. L., and L. B. Lipson. 1958. A correlation of the electrical properties of drilling fluids with solids content. Trans. AIME, Vol. 213.

Poupon, A., R. W. Hoyle, and A. W. Schmidt. 1971. Log analysis in formations with complex lithologies. J. Pet. Tech. (August).

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.

Raymer, L. L., and W. P. Biggs. 1963. Matrix characteristics defined by porosity computations. Trans., SPWLA 4th Annual Logging Symposium.

Raymer, L. L., W. R. Hoyle, M. P. Tixier. 1962. Formation density log applications in liquid-filled holes. J. Pet. Tech. (March).

Raymer, L. L., and E. R. Hunt. 1980. An improved sonic transit time-to-porosity transform. SPWLA 21st Annual Logging Symposium. July, Lafayette, LA.

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. Pet. Tech. (September) 945-959.

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.

Segesman, F. 1962. New SP correction charts. Geophysics, 27(6): Part 1.

Segesman, F. and M. P. Tixier. 1958. Some effects of invasion on the SP curve. SPE Annual Fall Meeting, October.

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.

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.

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.

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.

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.

Tilly, H. 0., B. J. Gallagher, and T. D. Taylor. 1982. Methods for correcting porosity data in a gypsum-bearing carbonate reservoir. J. Pet. Tech. (October) 2449-2454.

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.

Tittman, J., and J. S. WahI. 1965. The physical foundations of formation density logging (gamma-gamma). Geophysics (April).

Tixier, M. P., and R. P. A1ger. 1968. Log evaluation of nonmetallic mineral deposits. SPWLA 9th Annual Logging Symposium, New Orleans.

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.

Wah1, J. S., J. Tittman, C. W. Johnstone. 1964. The dual spacing formation density log. J. Pet. Tech. (December) 17.

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.

Welex, a Halliburton Company. (undated). Open-hole services. Catalog G 6003.

Williams, H., and H. F. Dunlap. 1984. Short term variations in drilling parameters, their measurement and implications. The Log Analyst. (SPWIA) Sept.- Oct. :3-9.

 

NOMENCLATURE

 

Mud and Borehole Terms
dh	Diameter of hole (in.).
hmc	Mudcake thickness (in.).
Rm	Resistivity of mud (ohm-meters).
Rmc	Resistivity of mudcake (ohm-meters).
Rmf	Resistivity of mud filtrate (ohm-meters).
Formation Terms
h	Formation thickness (ft).
	Porosity = Fraction of formation volume that is pore space.
h	Permeability (millidarcies) - Fluid flow characteristic of formation.
d1	Resistivity of connate water (ohm-meters).
Rw	Diameter of invasion (in.).
Rwa	Apparent resistivity of formation water (ohm-meters).
Ro	Resistivity of uninvaded formation with pores completely filled with connate water (ohm-meters).
Rt	Resistivity of uninvaded (deep ) formation with pores containing both connate water and hydrocarbon.
Ri	An average resistivity of invaded zone; pores may contain a mixture of mud filtrate, connate water, and hydrocarbons; a nebulous term, not commonly used.
Rxo	Resistivity of shallow zone completely flushed by mud filtrate; pores may contain residual hydrocarbon as well as mud filtrate.
F	Formation factor=Ro/Rw or Rxo/Rmf by definition. = 1/2(ls) or 0.81/2 (ss), by experiment.
C	Conductivity (mmho) = 1,000/resistivity (ohm-meters).
Sw	Water saturation = Fraction of pore space in uninvaded zone containing water = (Ro/Rt)1/2=
Sh	Hydrocarbon saturation = Fraction of pore space in uninvaded zone containing hydrocarbons = (1 - Sw).
So	Oil saturation = Fraction of pore space in uninvaded zone containing oil.
Sg	Gas saturation = Fraction of pore space in uninvaded zone containing gas; (So + Sg = Sh).
Sxo	Fraction of pore space in flushed zone containing water = (F Rmf/Rxo)1/2
Shr	Residual hydrocarbon saturation = Fraction of pore space in flushed zone containing hydrocarbons.
Soxo	Fraction of pore space in flushed zone containing oil.
Sgxo	Fraction of pore space in flushed zone containing gas. (Soxo + Sgxo=Shr).
Terms Related to Logging Measurements
SP
SSP	Static spontaneous potential = SP deflection (millivolts from shale line ) in PSP thick, clean formation.
PSP	Pseudo-static spontaneous potential = SP deflection (mV ) in thin or shaly formation.
Resistivity - Deep
RILd or RID	Resistivity measured by deep induction.
RLLD	Resistivity measured by deep laterolog.
Rs	Adjacent bed resistivity read by deep induction (for bed thickness correction).
Resistivity - Medium
RILM or RIM	Resistivity measured by medium induction.
RLLS	Resistivity measured by shallow laterolog.
Rs	Adjacent bed resistivity read by deep induction (or deep laterolog) .
Resistivity - Shallow
RSN or R16	Resistivity measured by short normal.
RLL8	Resistivity measured by laterolog-8.
RSFL	Resistivity measured by spherically focused.
Resistivity - Flushed Zone (Pad Measurements)
RMLL	Resistivity measured by microlaterolog.
RPL	Resistivity measured by proximity tool.
RMSFL	Resistivity measured by micro- spherically-focused logging tool.
Resistivity - Mudcake Controlled
R1"x1"	Resistivity measured by extremely shallow microlog curve.
R2"	Resistivity measured by slightly deeper microlog curve.
Sonic
t (or t)	Travel time measured by sonic tool (sec/ft).
tma (or tma)	Travel time of solid rock matrix.
tf (or tf)	Travel time of 100% pore fluid.
Cp	Compaction correction (³1).
s	Sonic-derived porosity.
Density
b	Bulk density measured by density tool (gm/cc).
ma	Density of solid rock matrix (grain density).
g	Density of pore fluid.
D	Density-derived porosity (ss or ls matrix specified).
Neutron
N	Neutron-derived porosity (ss or ls matrix specified).

 

Service company nomenclature

 

Schlumberger	Computalog
1. Electrical Log (ES)	Electrical Log
2. Induction Electric Log	Induction Electrical Log
3. Induction Spherically	–
Focused Log	–
4. Dual Induction Spherically Focused	Dual Induction
Log	Laterolog
5. Laterolog-3	Laterolog-3
6. Dual Laterolog	Dual Laterolog
7. Microlog	Micro-Electrical Log
8. Microlaterolog	Microlaterolog
9. Proximity Log	–
10. Microspherically Focused Log	–
11. Borehole Compensated Sonic Log	Borehole Compensated Sonic
12. Long Spaced Sonic	Log Acoustilog
13. Cement Bond/Variable Density Log	Sonic Cement Bond System
14. Gamma Ray Neutron	Gamma Ray Neutron
15. Sidewall Neutron	Sidewall Neutron
Porosity Log	Porosity Log
16. Compensated Neutron Log	Compensated Neutron Log
17. Thermal Neutron Decay Time Log	–
18. Formation Density Log	Compensated Density Log
19. Litho-Density Log	–
20. High Resolution Dipmeter	Four-Electrode Dipmeter
21. Formation Interval Tester	–
22. Repeat Formation Tester	Selective Formation Tester
23. Sidewall Sampler	Sidewall Core Gun
24. Electromagnetic Propagation Log	Dielectric Constant Log
25. Borehole Geometry Tool	X-Y Caliper
26. Ultra Long Spacing Electric Log	–
27. Natural Gamma Ray Spectrometry	–
28. General Spectroscopy Tool	–
29. Well Seismic Tool	–
30. Fracture Identification Log	Fracture Detection Log

Service company nomenclature (Cont.)

 

Western Atlas	Halliburton Logging Services
1. Electrolog	Electric Log
2. Induction Electrolog	Induction Electric Log
3. 4. Dual Induction Induction Log	Dual Induction Log
5. Focused Log	Guard Log
6. Dual Laterolog	Dual Guard Log
7. Minilog	Contact Log
8. Microlaterolog	FoRxo Log
9. Proximity Log
11. Borehole Compensated	Acoustic Velocity Log
10.-	Acoustilog
12. Long Spacing BHC Acoustilog
13. Acoustic Cement Bond Log	Microseismogram
14. Gamma Ray Neutron	Gamma Ray Neutron
15. Sidewall Epithermal Neutron Log	Sidewall Neutron Log
16. Compensated Neutron Log	Dual Spaced Neutron
17. Neutron Lifetime Log	Thermal Multigate Decay
18. Compensated Densilog	Density Log
19. Z Densilog	–
20. Diplog	Diplog
21. Formation Tester	Formation Test
22. Formation Multi Tester	Multiset Tester
23. Corgun	Sidewall Coring
24. Dielectric Log	Dielectric Constant Log
25. Caliper Log	Caliper
26. –
27. Spectralog	Compensated
28. Carbon/Oxygen Log
29. Borehole Seismic Record
30. –

 

 

 

Logging Tools: Quick Reference

Openhole logs, logging tools, and what they measure

Generic name of log:	Induction
Type of tool:	Resistivity
When run:	Primary log in fresh or oil- base mud where invasion is shallow
Purpose:	Measures formation resistivity, Rt
Limitations:	Behaves badly in salt muds and/or large boreholes and in formation with high resistivities
Often combined with:	Porosity tools
Operating principle:	20 kHz coil induces current in formation
Curves recorded:	Deep induction, conductivity, shallow-focused electric log SP and/or GR
Generic name of log:	Dual induction
Type of tool:	Resistivity
When run:	Primary log in fresh mud where invasion is moderate or deep
Purpose:	Measures formation resistivity, Rt
Limitations:	Behaves badly in salt muds and/or large boreholes
Often combined with:	Porosity tools
Operating principle:	20 kHz coil induces current in formation
Curves recorded:	Deep induction, medium induction, shallow-focused electric log SP and/or GR
Generic name of log:	Dual laterolog
Type of tool:	Resistivity
When run:	Openhole
Purpose:	Measures formation resistivity
Limitations:	Works best in salt muds. Cannot be used in oil-base muds
Often combined with:	Porosity tools
Operating principle:	Horizontal bean of current sent to formation
Curves recorded:	Laterolog deep, laterolog shallow, microfocused electric log
Generic name of log:	Microlog
Type of tool:	Microresistivity
When run:	Openhole
Purpose:	Sand count, permeability indication, invaded-zone resistivity Rxo
Limitations:	Water-base muds required
Often combined with:	Other microresistivity devices
Operating principle:	Measures two shallow investigation resistivities
Curves recorded:	Micro (normal), micro (inverse or lateral)
Generic name of log::	Compensated density
Type of tool:	Radioactivity/porosity
When run:	Openhole, primary porosity device
Purpose:	Measures porosity, indication of lithology
Limitations:	Requires smooth borehole wall
Often combined with:	Other porosity and/or resistivity tools
Operating principle:	Gamma rays from source scatter in formation
Curves recorded:	; Bulk density, , correction, apparent porosity, (for selected 1ithology)

 
 

Generic name of log:	Compensated neutron
Type of tool:	Radioactivity/porosity
When run:	Open or cased hole
Purpose:	Measures porosity/lithology
Limitations:	Requires liquid-filled hole
Often combined with:	Other porosity and/or resistivity tools
Operating principle:	Fast neutrons thermalized by hydrogen atoms in formation
Curves recorded:	(for selected lithology), GR, etc.
Generic name of log:	Acoustic
Type of tool:	Sonic/porosity
When run:	Openhole
Purpose:	Measures porosity, lithology
Limitations:	Some hole size limitations depending on value of formation
Often combined with:	Other porosity and/or resistivity tools
Operating principle:	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.
Curves recorded:	, wave train
Generic name of log:	Gamma ray
Type of tool:	Radioactivity/lithology
When run:	Open or cased hole
Purpose:	Sand/shale discriminator
Limitations:	None
Often combined with:	Any and all open- and cased-hole tools
Operating principle:	Scintillation detector measures natural formation gamma ray activity
Curves recorded:	GR
Generic name of log:	Gamma ray spectral log
Type of tool:	Radioactivity/lithology
When run:	Open or cased hole
Purpose:	Measures K, U, and Th concentrations in formation
Limitations:	Slow logging speed
Often combined with:	Neutron/density
Operating principle:	Gamma ray energy spectrum characterizes source of gamma rays
Curves recorded:	Total counts, uranium,
	potassium, and thorium
Generic name of log:	Dipmeter
Type of tool:	Resistivity correlation/ orientation
When run:	Openhole
Purpose:	Measures formation dip, detects fractures
Limitations:	Does not perform well in oil-base muds
Often combined with:	SP, GR
Operating principle:	4, 6, or 8 independent pad electrodes record correlation curves
Curves recorded:	Hole deviation, azimuth of Pad 1, relative bearing, correlation, caliper
Generic name of log:	Sidewall sampler
Type of tool:	Percussion core cutter
When run:	Openhole
Purpose:	Retrieves samples of the formation
Limitations:	Limited number of cores (typically 30 or 60) per trip in hole
Often combined with:	SP for depth control
Operating principle:	Explosive charge propels hollow cylinder into formation
Curves recorded:	SP, only for depth control; recovery report
Generic name of log:	F-overlay
Type of tool:	Quick-look log analysis
When run:	Openhole
Purpose:	Generates Ro curve
Limitations:	Works best in clean formations of constant lithology
Often generated with:	Density log or neutron/ density when run with deep induction or deep laterolog
Operating principle:	If Ro < Rt then Sw < 100
Curves recorded:	F or rescaled as an Ro curve
Generic name of log:	Rwa
Type of tool:	Quick-look log analysis
When run:	Openhole
Purpose:	Distinguishes water- and oil-bearing rocks, finds Rw
Limitations:	Needs careful attention to detail in gas-bearing formations and/or shales, depending on porosity tool used
Often generated with:	Sonic, porosity/resistivity combination tools
Operating principle:	Apparent porosity and Rt combined to give apparent water resistivity
Curves recorded:	Rwa
Generic name of log:	Rxo/Rt versus SP
Type of tool:	Quick-look log analysis
When run:	Openhole, fresh muds
Purpose:	Hydrocarbon indicator
Limitations:	Requires an SP log. Used primarily when no porosity tool is available
Often generated with:	Induction log
Operating principle:	Scaled RxoRxo/Rt ratio compared to SP
Curves recorded:	Rxo/Rt, SP

General Recommended Logging Program
 

Condition--	Data Desired  Correlation and lithology in sand/shale
Fresh mud	Recommended Services  Dual Induction--SFL--GR/SP; Induction Electrical; Dual Laterolog-- GR/SP (low porosity and/or high resistivities); Sidewall Cores
	Remarks  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
	Data Desired  Porosity; water saturation; lithology in carbonates and evaporates; hydrocarbon type
	Recommended Services  Density and/or Neutron and /or Sonic and GR; Formation Tester
	Remarks  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
	Data Desired  Producible hydrocarbons and permeability indicators
	Recommended Services  Proximity-Microlog; Microlaterolog or Micro-SFL; Dual Resistivity device; Sidewall Cores; Formation Tester
	Remarks  Proximity log used for thick mudcake; Microlaterolog for thin mudcake; Micro-SFL available with Dual Laterolog. Sidewall cores give permeability estimate in shaly sands
	Data Desired  Hydrocarbon indication at the wellsite
	Recommended Services  Wellsite Computer Products, including apparent formation water resistivity, Rwa; formation factor/resistivity overlay; and Rxo/Rt vs. SP overlay
	Remarks  Available with computer units only. Others available with both units.
	Data Desired  Formation dip magnitude and directional
	Recommended Services  Dipmeter
	Remarks  Wellbore directional information is also available

 
 

Condition--	Data Desired  Correlation and lithology in sand/shale
Salt mud	Recommended Services  Dual Laterolog--Micro-SFL--GR
	Remarks  In some areas of low porosity and/or mixed lithology the neutron or density--neutron is usable as a correlation log
	Data Desired  Porosity, water saturation, and lithology in carbonates and evaporates; hydrocarbon type
	Recommended Services  Density and/or Neutron and/or Sonic and GR; Formation Tester
	Remarks  See Remarks under fresh mud
	Data Desired  Producible hydrocarbons and permeability indicators
	Recommended Services  Proximity--Microlog; Microlaterolog-Microlog; Dual Laterolog--Micro-SFL; Sidewall Core; Formation Tester
	Remarks  In very salty muds or when Rxo is less than Rmc, the microlog results may be unsatisfactory. See Remarks under fresh mud
	Data Desired  Hydrocarbon indication at the wellsite
	Recommended Services  Wellsite Computer Products; Rwa, Ro Overlay
	Remarks  See Remarks under fresh mud. Apparent formation water resistivity may not be satisfactory in low and/or mixed lithologies
	Data Desired  Formation dip magnitude and directional
	Recommended Services  Dipmeter
	Remarks  Wellbore directional information is also available
Condition-- Oil-base mud	Data Desired  Correlation and lithology in sand/shale
	Recommended Services  Dual Induction--GR; Induction--GR; Sidewall Cores
	Remarks  High temperature (350 to 400°F) will restrict the use of the dual induction and sidewall cores
	Data Desired
	Porosity, water saturation, lithology in carbonates and evaporites; hydrocarbon type
	Recommended Services  Density and/or Neutron and/or Sonic; Formation Tester
	Remarks  See Remarks under fresh mud. High temperature (350°F) and small holes(6 in.) restrict the use of the formation tester
	Data Desired  Producible hydrocarbons and permeability indicators
	Recommended Services  Dual Induction; Sidewall Cores; Formation Tester
	Remarks  Sidewall cores give permeability estimates in shaly sands
	Data Desired  Hydrocarbon indication at the wellsite
	Recommended Services  Wellsite Computer Products; Rwa, Ro Overlay
	Remarks  See Remarks under fresh mud
	Data Desired  Formation dip magnitude and directional
	Recommended Services  Dipmeter
	Remarks  See Remarks under fresh mud
Condition-- Air- or gas-filled hole	Data Desired  Resistivity, correlation, and lithology in sand/shale
	Recommended Services  Dual Induction--GR; Induction--GR
	Remarks  None
	Data Desired  Porosity, water saturation, gas saturation, estimated lithology in carbonated and evaporates
	Recommended Services  Density and/or Neutron
	Remarks  Dual spacing neutron CNL cannot be used; must use gamma ray-neutron(GRN) or preferable sidewall neutron porosity (SNP)
	Data Desired  Permeability Indicator
	Recommended Services  Temperature Log; Noise Log
	Remarks  Gas entry
	Data Desired  Hydrocarbon indication at the wellsite
	Recommended Services  Wellsite Computer Products; Ro Overlay, Rwa
	Remarks  See Remarks under fresh mud
Condition-- Fresh or unknown formation water	Data Desired  Resistivity; correlation and estimated lithology in sand/shale
	Recommended Services  See fresh mud and salt mud
	Remarks  See fresh mud and salt mud
	Data Desired  Porosity water saturation; estimated lithology in carbonates and evaporates; hydrocarbon type
	Recommended Services  Density and/or Neutron and/or Sonic and GR; Electromagnetic Propagation Tool; Inelastic Neutron Scattering and Capture Gamma Ray Spectroscopy; Formation Tester
	Remarks  Under conditions of no invasion the electromagnetic propagation tool will yield water saturation directly. See Remarks under fresh mud
	Data Desired  Producible hydrocarbons and permeability indicators
	Recommended Services  Sidewall Cores; Formation Tester
	Remarks  None
	Data Desired  Hydrocarbon indication at the wellsite
	Recommended Services  Wellsite Computer Products.
	Remarks  See Remarks under fresh mud. May use electromagnetic propagation tool
Condition-- Cased hole	Data Desired  Fluid type and lithology
	Recommended Services  Pulsed Neutron Log; Inelastic Neutron Scattering and Capture Gamma Ray Spectroscopy; GR and Natural Gamma Ray Spectroscopy
	Remarks  None
	Data Desired  Porosity and hydrocarbon type
	Recommended Services  Pulsed Neutron Log; Gamma Ray-Neutron; Density Formation Tester; Inelastic Neutron Scattering and Capture Gamma Ray Spectroscopy
	Remarks  Dual spacing neutron (CNL) cannot be used if hole is gas filled. Under favorable conditions the density may be used for porosity
	Data Desired  Permeability
	Recommended Services  Formation Tester
	Remarks  None