Introduction
Development of Mud Logging
MUD LOG: A continuous analysis of the drilling mud and cuttings to determine the presence or absence of oil, gas, or water in the formations penetrated by the drill bit, and to ascertain the depths of any oil- or gas-bearing formations. (Gary et al., 1972)
Conventional mud logging is a wellsite effort that attempts to determine as rapidly as practicable, and from materials at hand, numerous subsurface conditions that are directly related to petroleum exploration and development drilling.
Concept of Mud Logging
When a rock is penetrated by the drill bit, a quantity of rock with the fluids it contains — water, oil, and gas — is ground up, dispersed in the circulating drilling mud, and transported up the well annulus . The relative volumes of rock and fluids arriving at surface during any one sampling period will be controlled by:
the volume of the cylinder of drilled rock, which depends upon drill bit size (cylinder cross-sectional area) and penetration rate (cylinder height);
the porosity of the rock which determines how much fluid can be entrapped;
the permeability of the rock which determines how much of each fluid can escape from the cuttings into the drilling mud while in uphole transit;
the relative saturations of water, oil, and gas, which represent the proportions of the total porosity filled with each of these fluids;
the differences in temperature and pressure between the bottom of the borehole and surface conditions, which control changes in such phenomena as the solubility of gas in oil or water, the distribution of hydrocarbons between liquid and gas phases, and the bulk volume of gas present at ambient surface conditions.
The rationale for mud-logging services is that if representative samples of drilled materials are analyzed as soon as they come from the borehole, it should quickly be feasible to reconstruct the nature and composition of rocks and fluids at depth.
Two conditions prevent mud logging from achieving its ideal goal of providing immediate measurement of in situ subsurface conditions. First, none of the factors listed can be precisely measured to permit quantitative reconstruction of down-hole conditions. Second, drilling practices and analytic procedures introduce other variables into any such reconstruction. These include:
· the addition of fluids and cavings from uphole, uncased portions of the wellbore;
the introduction of mud additives as well as recycled debris and gas from the mud tanks;
the variation in operational efficiencies of surface pumping and extracting equipment.
Nevertheless, important qualitative deductions and interpretations can be made from mud log data.
Conventional Mud-Logging Services
The two basic categories of service routinely available are combustible gas detection and formation logging.
Combustible Gas Detection
Mud logging originated as an exploration service in 1939. At that time it consisted of the extraction and gross detection of combustible gases carried to surface by circulating drilling mud. To provide this combustible gas detection service, a portion of the returning drilling mud was passed through a gas trap, where it was agitated and aerated. This mixture of air and extracted gas was then drawn by vacuum from the top of the trap to a nearby detector .The original "hot wire" gas detectors were nondiscriminating and provided a single output of total combustible gases to an analog meter calibrated in arbitrary "gas units." The operator, or mud logger, manually transcribed and plotted the readings of the detector. However, the analytical instruments initially available were relatively unwieldy and troublesome and required constant attention, adjustment, and recalibration. Consequently, operation and maintenance of gas detectors required the full-time attention of early mud loggers. Interpretation of the results or their correlation with other drilling data was the responsibility of the wellsite geologist or engineer.
Basic Formation Logging
The 1940s and early 1950s saw a broadening of the simple gas-logging effort as a consequence of improvements in gas analysis instruments. As transportable gas detectors became more rugged, reliable, and automated, mud-logging personnel had more free time to work with other on-site sources of information.
As a first step, mud loggers took over the drillers' traditional task of collecting and examining cuttings samples and preparing a lithology. Combining the lithology log with the combustible gas plot created the primitive formation log.
The following quotation, from Hugh Barton of Phillips Petroleum, provides some insight into early mud logging:
A soil gas analysis apparatus for surface oil prospecting was developed around 1938by R.L. Eoan, R.W. Crawford, and B.H. Ashe of Phillips Petroleum Company. In about 1939, G.G. Oberfell, Research Vice President, requested that this system be adapted to measure hydrocarbons in drilling mud to improve the chances of finding oil and gas in geological formations where electric logs of the time sometimes missed them. T.C. Wherry was assigned the task and he set up a laboratory in Oklahoma City to analyze muds from a well being drilled in the area. The mud was put in a pressure vessel and heated until head-space pressure reached about two atmospheres. At that point the gaseous mixture was expanded into an evacuated vessel. After cooling, the mixture was passed into a "hot wire" gas analyzer consisting of a platinum wire heated in a bridge circuit. The system was calibrated in terms of equivalent normal butane concentration in air.
First Results showed an increase in gas content near the pay zone-not dramatic, but enough to encourage further development of the concept. Phillips decided to build an improved apparatus into a trailer and do analyses on site. Our first analyses in 1939 at the Billings Unit north of Perry Oklahoma, were performed by Crawford, Ashe, Bill Flatford, Wayne Peck, and me. Results were promising but, as with many drilling operations, "gas sniffing" did not go smoothly. We drilled the main pay zone in bitter cold weather and the logging unit was frozen up and inoperable at that time. We refined the apparatus and took it to Hidalgo County in south Texas, where no freezing weather was expected. A good log was obtained on the next well.
My recollection of first direct, on-site use of mud logging occurred on Christmas Eve, 1940, in the Chocolate Bayou field near Alvin, Texas. The gas content in the mud began to build up and I informed the driller, who refused to believe it because he could not see or smell it in the mud. He would not stop drilling to circulate the gas cut mud. At this point I did insist that a test be made of the blowout preventer. Naturally it was found to be stuck open. The driller did agree, reluctantly, to clean it out, probably because there had been a disastrous blowout nearby earlier. A few minutes after repairs were made the well began to kick hard and would have blown out except for the now-working blowout preventor. About 20 feet of gas zone had been penetrated so that the near-blowout stuck the pipe in the hole and required an expensive fishing operation.
Two research mud logging units were fielded with good results prior to World War II. After the war, Bob Pryor built another one in a large trailer and operated it for a few years until industry picked up mud logging.
Initially, the quality of lithologic descriptions showed little improvement over those of drillers. Lithologic nomenclature often appears to have been restricted to terms like sand, hard shale, soft shale, lime, and "Annie Hydrite." Nevertheless, as experience and training of mud loggers improved, mud log geology became a first-hand record of the depths and characteristics of downhole rock types.
The drilling rig also provided another source of data — rate of penetration (ROP) — which has become a routine inclusion in formation logging. Initially, mud loggers took depth measurements from the driller's report. Later, however, mud loggers began to attach their own sensors to the kelly and calculate depth drilled and ROP on a fine foot-by-foot scale. This was a substantial improvement over driller's ten-foot-or-more averages. The addition of accurate penetration rate data permitted improved interpretation of rock strength and porosity. The ROP plot also encouraged visual correlations to be made between the mud log and those wireline logs that reflected rock properties related to drillability (e.g., porosity).
The final developmental step in formation logging was the introduction of tracer materials, such as calcium carbide, to the mud system and the addition of a pump stroke counter. With these, the rate of mud flow in the borehole could be measured accurately. This, in turn, provided a reliable means of estimating the lag time between penetration of a rock unit at depth and the arrival of its gases and cuttings at surface.
Although a minor technological achievement, lagging was a major practical advance for the working geologist. Reporting of gas and cuttings data at lagged depths allowed direct comparisons and correlations to be made with logs from other sources.
Modern Formation Logging
Since the development of formation logging, improvements have been made in gas detection capabilities through the introduction of more accurate and discriminating gas analyzers. Gas chromatography, for example, is now used routinely in formation logging to measure the con-cent rations of individual hydrocarbon compounds in mud and cuttings gases. Other analyzers, such as for hydrogen sulfide and carbon dioxide, can be added upon request to formation logging programs. Some modern formation logging units have incorporated pyroanalyzers to evaluate cuttings as petroleum source and reservoir rocks.
Advanced Mud-Logging Services
We have broken advanced services into three categories-pressure evaluation, systems monitoring and data acquisition, and interactive evaluation and advisory.
Pressure Evaluation Services
In the mid 1960s a major expansion in mud-logging services began as mud-logging companies became more involved in engineering and operational aspects of well drilling. The first expansion was to monitor for overpressured zones. This marked the transition to advanced mud-logging services.
The need for pressure evaluation services evolved because of improvements made in drilling techniques in the 1960s. Development of more stable drilling fluids
and mud additives
allowed for much greater control of mud density and mud properties. As a result, mud weight could be increased or decreased rapidly as needed, and also be maintained at relatively constant levels, without full-time attention and treatment. At the same time, improvements in blowout prevention technology, adjustable choke design, and well-kill capabilities
took.
These factors led first to a reduced fear of well blowouts, then to increased confidence in the ability of a rig and its crew to prevent or control a well kick, and finally to a full appreciation of the economic benefits to be gained from balanced drilling.
Balanced drilling — which is drilling with a minimum or with no overbalance of drilling mud density relative to the formation pressure gradient — reduced drilling mud treatment costs, improved penetration rates, and resulted in better overall conditions in borehole walls and adjacent formations.
However, these technical advances in drilling did not entirely remove the risks related to loss of well control. The penetration of abnormally high formation pressures could rapidly dilute the balanced mud system, lower the mud density, and cause the mud to surge to the surface. The stage would be set for a blowout.
As a result, the concept of "geopressure evaluation," also called "surnormal pressure recognition" or "pressure prediction," was incorporated into some mud-logging programs.
It was realized early that data directly applicable to identification of over-pressured zones could be obtained from available mud-logging techniques. Changes in penetration rate, cuttings character, and mud gas volume are examples of such indicators. Concurrently, mud-logging service companies introduced several additional wellsite geological and petrophysical techniques that improved detection of a "geopressured formation" or of a declining mud overbalance at the bottom of the borehole. These techniques provide such measurements as shale density, clay mineralogy (shale factor), mud temperature gradient, and mud pit volume. Techniques have continued to evolve to the point that pressure evaluation programs are now used routinely to select optimum casing points in overpressure transition zones in order to both control formation pressure on the wellbore and minimize excessive mud weight damage to openhole formations.
Systems-Monitoring and Data-Acquisition Services
With the expansion of mudlogging services to include pressure evaluation, it became logical, if not necessary, to install sensors and central recorders that were able to measure continuously various drill rig, mud pit, and circulation system parameters. This led to the evolution of systems-monitoring and data-acquisition services that constantly monitored diverse drilling operations. This, in turn, resulted in drillers and operators improving overall rig performance and safety.
Advanced logging service continued to expand in the 1970s through the
introduction of mini- and microcomputers. While these were able to automate data acquisition and analysis systems, they could not be interfaced readily with older hydraulic or pneumatic sensors on the rig. As a result, independent electronic sensors were added to advanced mud-logging facilities.
Interactive Evaluation and Advisory Services
Logging units set up to perform the types of advanced mud-logging service available in the 1970s were well equipped to act as "command" centers for nearly all engineering and drilling operations. This indeed became the case in many of the more advanced logging facilities in the late 1970s and early 1980s.
This funneling of data through one facility, the mud-logging unit, encouraged further expansion of advanced mud logging into interactive evaluation and advisory services. Mud-logging companies added new types of programs, software, and reports. Well kill, mud hydraulics, optimum drilling, and inventory control programs
are examples. Specialized communications equipment also was incorporated in many advanced mud-logging units for two-way transmittal of data between the drillsite and company offices.
The 1980s introduced another expansion to interactive evaluation and advisory services — downhole measurement while drilling — commonly referred to as measurement while drilling (MWD). MWD technology involves installing common wireline logging sensors in the drillstring, a short distance above the bit. From these sensors, data are either transmitted directly to surface, generally through the mud system, or are recovered from recorders when the drillstring is pulled. Sensors are currently available for (1) directional monitoring (e.g., inclination, azimuth, tool face); (2) drill system monitoring (e.g., weight on bit, rotary torque, bottomhole pressure, mud temperature); and (3) formation evaluation (e.g., formation resistivity, mud resistivity, formation gamma ray).
While all of these advanced services are still generally classified as "mud logging," in many cases it can be seen that similarities lie only in the mode of operation-continuous monitoring in an on-site laboratory during active well drilling. In addition, availability has expanded to the point that many of the routine services and basic instruments can be acquired individually from the many smaller
companies that specialize in particular aspects of logging and supply stand-alone equipment.
Exercise 1.
How do the following parameters affect cuttings and mud gas samples arriving at surface during one sample period?
a. ROP
b. porosity of rock drilled
c. permeability of rock drilled
d. depth of bottomhole
Solution 1:
a. The greater the ROP, the greater the volume of cuttings and gas to arrive at surface during the same time interval (assuming all other factors to be constant).
b. The greater the porosity, the greater the volume of fluids that will be in the combined mud and cuttings arriving at surface.
c. The greater the permeability, the greater the percentage of pore fluids that will have escaped to the mud.
d. The greater the depth, the greater the hydrostatic pressure change during uphole travel and, therefore, gas expansion. Also, the drop in temperature relative to the local geothermal gradient will be greater, with proportional modifications to phase and solubility.
Exercise 2.
Discuss at least two factors that influence cuttings and gases during their transit from bit to mud-logging unit and will affect analytical results.
Solution 2:
- Cavings — modify apparent cuttings composition
- Fluid incursions — modify gas composition and concentration
- Recycled materials — contaminate samples
- Variations in sampling efficiency — yield inconsistent, and perhaps nonrepresentative samples.
- Variations of analytical sensitivity (inside the logging unit) — yield inconsistent or biased data.
Exercise 3.
What was the original function of mud logging?
Solution 3:
Originally, mud logging monitored combustible gases returning uphole in the circulating mud.
Exercise 4.
What general categories of information are commonly found on a modern formation log?
Solution 4:
ROP, lithology, shows, total combustible gas and individual hydrocarbon compounds of mud gas (and possibly cuttings gas), descriptive information, and basic geopressure plots.
D.2. Conventional Mud Logging Practices
General Description
UNDER CONSTRUCTION …!
Routine Services
With a diversity of services at hand, an operator has a number of decisions to make when selecting the types and level of services needed for a specific drilling program. Conventional mud-logging services generally include the following capabilities:
- Monitoring, calculating, and plotting drill depth and drill rate;
- Determining lag time (stroke count) and making continuous adjustments while drilling;
- Describing, interpreting, and plotting lithologies from cuttings and cores;
- Detecting, plotting, and evaluating concentrations of total combustible gas in mud and cuttings;
- Detecting, plotting, and evaluating concentrations of individual hydrocarbon compounds in mud and cuttings gas;
- Measuring basic physical and chemical properties of drilling mud;
- Making basic pressure evaluation measurements, calculations, and log presentations;
- Making borehole deviation calculations to produce logs. and reports with data adjusted to true vertical depth;
- Providing notification and interpretive functions to drilling supervisors concerning drilling events (e.g., oil show, gas kick, and mud cut); Interpreting formation log data and plots and correlating them to reference wireline logs and core data.
Supplemental services generally available and compatible with conventional mud-logging units and programs include these capabilities:
- Monitoring work sites for dangerous and nonhydrocarbon gases;
- Monitoring mud pits for dissolved acid gases, mud surges, and in/out properties;
- Providing basic geochemical and petrophysical analyses of cuttings and sidewall cores.
Standard Equipment
Based on observations published in 1983 by the Society of Professional Well Log Analysts (SPWLA) and information provided by established mud-logging service companies, a number of instruments and support systems are considered basic to a conventional mud-logging unit. These are listed below. Individual pieces of equipment may be omitted from a mud-logging unit if the functions they perform are not needed during a specific drilling program.
In addition to the items listed, it is desirable that preparatory arrangements assure that the equipment has been designed and installed to provide continuous, reliable performance under any adverse operating or climatic conditions expected at the wellsite. The equipment should also satisfy any environmental or safety regulations of the area.
It also is advisable to ensure that logging personnel are sufficiently qualified and experienced both to operate and maintain the mud-logging equipment specified for the site and to assemble and interpret mud-logging data for designated geological and engineering purposes.
Mud-logging Equipment Commonly Used During Conventional Mud Logging
Total combustible gas analyzer using a catalytic combustion detector (COD) or flame ionization detector (FID)
Gas sample dilution system to obtain linear detector response at all gas sample concentrations
Automatic sampling gas chromatograph (GO) capable of routinely isolating and detecting the following:
lightest combustible gases (hydrogen and methane)
other hydrocarbon gases (ethane, propane, butane, and isobutane)
lightest hydrocarbon liquids (pentane+)
Gas calibration system that allows for the following:
· Total hydrocarbon detector to be calibrated to respond in units of percentage equivalent methane in air(% EMA)
Gas chromatograph calibrated to read directly in % EMA or parts per million of the types of individual hydrocarbons it detects
Backup catalytic combustion or thermal conductivity detector (TCD) compatible with operating detector systems
Batch total hydrocarbon analyzer equipped with blender and vacuum line for the extraction and analysis of cuttings gas
Microscope and ultraviolet (UV) light inspection chamber for description of cuttings lithology and evaluation of oil shows
Bulk density apparatus for measuring relative density of shale (clay) cuttings
Depth and drill rate recorder for determining sample depth and preparation of a rate-of-penetration (ROP) log for lithology and porosity interpretation
Pump stroke counters (2) to record drilling (circulating) time, calculate lag time (tracer test) and indicate arrival-at-surface stroke count
Surface mud pit volume sensor system for use in conjunction with the total hydrocarbon detector to provide immediate recognition of well kicks for well control and rig safety
Mud test equipment for evaluating general physical and chemical mud properties, which will include the following:
Mud balance to determine mud density
Marsh funnel to estimate mud viscosity
Sand test kit to isolate and identify fine solids in circulating mud
Salinity titration equipment to confirm the presence of undesirable or dangerous constituents in returning mud
Test chemicals and glassware to confirm identification of cement, salt, carbonates, sulfates, etc., in cuttings
Processing equipment for sieving, washing, and drying samples
Chemical apparatus to detect trace quantities of dissolved hydrogen sulfide in drilling mud; this includes an automatic hydrogen sulfide gas detector capable of signaling an alarm upon the appearance of such gas in the gas trap. (Generally, this is a minimal requirement; in an area of known hydrogen sulfide occurrence, more stringent safety provisions will probably be required.)
Text processing, log preparation, and related support items, such as typewriter, dyeline or electrostatic copier, drafting supplies and appropriate forms, sample bags, envelopes, boxes, shipping materials, and other materials needed in the routine of mud logging. In some modern conventional mud-logging units this function may include computer storage and plotting capabilities.
Formation Mud Log
An SPWLA recommended formation mud log format is shown in. In this log, as with nearly all formation mud logs, data are presented in vertical, well-profile tracks for easy comparison with wireline and related down hole logs. Mud log headings are similar to those of other downhole logs, but they generally present information that summarizes the well at total depth
(TD).
The typical sequence of tracks from left to right is:
Track One Penetration rate
Track Two Cuttings lithology with depth and show columns
Track Three Total combustible gas
Track Four Hydrocarbon gases and geochemical data
Track Five Descriptive information
Track One
Drilling-related comments and data are also reported descriptively in this column, particularly if they may explain changes in ROP. For example, this column may include (1) bit type, diameter, and jet sizes; (2) bit-operating statistics, such as average weight on bit, rotary speed, torque, and pump pressure; and (3) final bit footage, hours, and grade. Track One commonly records trips and shut-in times, and it may carry directional survey data. This track also denotes the drilling chronology of the well by the placement of each day's date at "midnight" bottomhole depth.
Track Two
In general, Track Two carries three sets of data — depth, lithology, and shows .Depth generally is on the left of this track and is shown numerically and graphically. Standard down hole log scales, such as 2 in = 100 ft or 1 m = 500 m, are used. Cuttings lithology is represented graphically, both in terms of individual rock types and their gross relative percentages. Visible porosity may also be depicted in this track. Hydrocarbon shows and cored intervals are generally indicated by symbols on the right of the track. The former will be numbered and qualitatively rated. Both may reference specific reports.
Track Three
On a five-track log hydrocarbon analytical data typically make up both Track Three and Track Four. On a four-track log , it is common to combine these two tracks and present all geochemical data as the single third track.
Track Three generally carries the type of data that was the basis for early mud-logging services-measurement of total combustible gas arriving at surface in the drilling mud. Such measurements as connection gas and trip gas routinely appear here, as can total cuttings gas. Gas data generally are plotted in percent equivalent methane in air (% EMA). When basic formation-pressure data, such as shale density and mud temperature, are included in the formation log, these typically appear as gradient plots in Track Three for comparison with the total combustible gas curve.
Track Four
The second track of gas analytical data, Track Four, usually contains specific compositional information.The second gas track generally is scaled to show concentrations of individual hydrocarbon compounds, usually in parts per million (ppm), that were recovered from the drilling mud. Concentrations are determined through some form of gas chromatography.
Track Four may also present relative gas wetness by comparing the content of methane with that of heavier gases. In some cases ratios between individual or groups of hydrocarbon gases are plotted in Track Four. Additionally, compositional data plotted in this track may come from cuttings gas analysis. Analytical data for the elemental gas hydrogen
plus nonhydrocarbon gases like carbon dioxide
may also be included in this track; however, it is more common to find the latter on a supplementary log.
Track Five
In virtually all conventional mud logs the right-hand track — Track Five in our example — serves as a concise diary or summary of the drilled well .
This track contains abbreviated sample descriptions of the lithology depicted in Track Two and will indicate cuttings porosity if that is not shown in Track Two. Track Five can include data on drilling mud, such as weight and viscosity, as well as comments and various details on borehole conditions and deviations. Any factors that can influence overall log quality can be entered here for reference. When space is a problem, or convention so dictates, some Track Five data can show up instead in Track One for use with ROP evaluation.
Morning Report
An operator should expect to receive a morning or periodic report from the mud logger once per day, per twelve-hour logger shift, or per eight-hour tour shift, whichever is specified in the mud-logging agreement. All drilling, geologic, and hydrocarbon "events" of the period should be noted on the periodic report, along with more routine items regarding instrument performance and calibration, log print distributions, and sample shipments.
Show Report
The morning report format may be used when reporting an oil or gas show, or the operator or service company may provide a special form . In the gas show report, the background value determined before the show and, if available, after the show should be included; the magnitude of the show can be validly estimated only relative to such established values.
Reports of any special occurrence, such as a show, should always be in writing, even if the wellsite geologist is present during the event. The report should be signed by both mud-logging and operator parties in acknowledgment of transmittal and receipt. This is a basic procedure to ensure good communications and prevent confused or erroneous reporting. It is the type of routine procedure that should be confirmed during the prespud meeting.
Pigtail Logs and Attachments
Certain data, records, and tabulations require more space than is available in the right-hand track of a mud log. These may be drafted or typed onto plain log film or vellum and attached to the end of the mud log after it is completed. These are called pigtail logs. Typical pigtail logs and attachments include zone of interest logs, bit records, conventional core recovery, sidewall core recovery, drillstem test (DST) results, and fishing efforts.
Invoices and Manifests
During drilling, the mud-logging crew must prepare documents for the shipping of logs and samples from the wellsite. The mud logger and operator should take extra care in preparing these invoices and manifests. Copies should be retained at the wellsite until written confirmation of delivery is received.
For "tight hole" samples, description and depth-coding systems may be used for both labels and manifests. These systems must be established ahead of time by the operator and the mud logger, preferably in time to be confirmed at the prespud meeting.
Summary Reports
On completion of well drilling, the mud-logging company normally is required to provide a final report. This is a written geologic, hydrocarbon, and possibly formation-pressure report, summarizing evaluations and recommendations made from the various logs. The final report should be delivered with the final log prints and always filed with the logs.
Additionally, after "rig-down" of the logging unit, the mud-logging crew should prepare an end-of-well report, which should be signed by the wellsite geologist or an operator representative. A copy should be filed by both the operator and the mud logger. This report will be used to prepare final billing for the service, but, more importantly to operator personnel, it will contain details of the final distribution of all logs, samples, and documents kept in the logging unit during well drilling. The listing should include all mud-logging unit copies of reports, worksheets, analog recorder charts, computer disks and tapes, and any offset wireline or mud logs provided for correlation purposes. The end-of-well report is not complete — and the mud logger is not relieved of responsibility — until all listed items are accounted and signed for.
Mud Log Preparation and Presentation
A side-by-side comparison- of a formation mud log and a single wireline log shows that there are considerably more data contained on a mud log. This is partly because many physical, chemical, and operational factors are presented within the mud log format. The main cause, however, is the fact that, unlike wireline logs — which are produced in a few hours, perhaps at interim drilling stages of the well — mud logs are produced over the drilling life of a well. A mud log is built day by day, recording continuously changing drilling, borehole, mud, and ambient conditions. In addition, the mud log contains many supplemental details that are necessary to interpret the basic ROP, geologic, and analytical data accurately.
In years past, all formation mud log data were plotted on the log by hand at the wellsite. Typically they were inked in final form at the end of each shift or prior to the periodic report. Hand drafting often led to poor use of a mud logger's time, particularly if a number of special analyses were being performed during the shift. More recently, simple, relatively inexpensive computers and plotters have been incorporated in mud-logging units as on-site log-drafting machines ( Figure 1 and Figure 2 , Typical product). Such equipment is becoming common where full formation-logging services are involved; consequently, computer-prepared logs may be provided by mud-logging companies in place of more conventional hand-drafted varieties.
Most conventional logging operations that use computers require manual entry of data. From this assemblage of data, selected values may be extracted through routine computer programs, or as needed, for plotting, replotting, or cross-plotting. This flexibility, plus the accuracy and speed inherent in computer manipulation of data, allows broader presentation and use of conventional mud log data while drilling is in progress.
Exercise 1.
What are the functions of the following pieces of mud-logging equipment?
a. total combustible gas analyzer
b. gas chromatograph
c. blender and vacuum line
d. pump stroke counter
e. mud pit volume sensor
f. mud balance
g. ultraviolet light inspection chamber
Solution 1:
a. Detects total concentration of all combustible gases in mud.
b. Separates concentrations of individual hydrocarbon compounds in gas sample.
c. Liberates and extracts gas entrapped in cuttings.
d. Lags mud circulation; determines volume of mud in circulating system.
e. Detects a surge in mud return from well kick
f. Measures drilling mud weight and shale density
g. Checks cuttings and cores for fluorescence (shows)
Exercise 2.
What is the function of a pigtail log?
Solution 2:
The pigtail log adds information that is not routinely plotted on the formation log.
It provides additional details on events and drilling developments that:
- aid in the interpretation of the mud log, or
- provide the operator with information on specific wellsite conditions.
Exercise 3.
List at least three parameters that generally would be plotted or recorded on each track of the following five-track formation log.
(Note: Numerous variations are to be expected; most basic information should be included in final distribution depicted.)
a. ROP track
b. lithology track
c. total gas track
d. chromatography gas track
e. descriptive track
Solution 3:
a. Rate of penetration, bit record, bit operating conditions, directional surveys, trips, midnight date (and a number of other items if not carried elsewhere, such as porosity and shut-in periods).
b. Percentage lithology, shows, porosity, cored intervals, casing points.
c. Total mud gas, basic shale density plot, mud temperature curve, total cuttings gas if taken, nonhydrocarbon gases (H2S, CO2), notations on connections, trips, and lag gas.
d. Concentration of individual hydrocarbons in mud gas and cuttings gas, percentage plot of gases, nonhydrocarbon gases if not in "c."
e. Abbreviated sample description, mud information (e.g., weight, viscosity, chlorides), fluorescence, general information not carried elsewhere.
D.3. Penetration Rate & Lithology
Measurement of ROP
Rate of penetration is simply a measure of how fast the rig is "making hole." One basic measurement needed for ROP, then, is time while drilling on bottom. The other is distance (or depth) penetrated during that period of active drilling ( Figure 1 , Determination of penetration rate).
Rate of penetration can be quantified in two manners:
Distance per unit of time (e.g., 33 ft/hr, or 10 m/hr)
Time per unit of distance (e.g., 2 min/ft, or 6 min/m)
For computation of ROP, individual distance-per-time intervals must be converted to relative percentages of the total time being averaged. Similarly, each time-per-distance segment must be looked at as a relative percentage of the distance being averaged. If ROP is not calculated correctly, errors result that can affect drilling decisions.
Here is a relatively simple example applied to drilling:
Drilling Time | ROP |
3 hours | 10 ft/hr |
2 hours | 5 ft/hr |
2 hours | 15 ft/hr |
2 1/2 hours | 4 ft/hr |
1/2 hour | 20 ft/hr |
These figures produce a depth drilled of 90 feet in ten hours (30 + 10 + 30 + 10 + 10 = 90), or 9.0 ft/hr. A straight arithmetic average of drilling rates for the ten hours will show 10.8 ft/hr ([10 + 5 + 15 + 4 + 20]/5 =10.8). This amount of difference (20% error) may be enough to keep a bit on bottom longer than economically wise.
Rate of penetration is generally determined from some combination of the following four methods of measuring drillstring movement — strapping the kelly, drill-rate circular charts, Geolograph strip charts, or mud-logging sensors.
Strapping the Kelly
The oldest method of determining ROP is by marking or strapping the kelly in selected lengths. As each length is drilled, the time required is recorded by hand in a table. As the table is built, so is the base for ROP. The same kelly markings can be used again and again as each pipe connection is made and drilldown continues. This type of physical ROP measurement generally produces a log based on five- or ten-foot increments.
Drill Rate Circular Chart
In this method, a pen or scribe mechanism notes kelly or block movement and plots it on a circular chart that rotates completely once a day ( Figure 2 , Drilling rate and routine operational features indicated on kelly-height circular recorder charts). The apparatus typically is mounted on the rig floor near the driller's station so that the information is readily available to the drill crew and can be manually transcribed for ROP calculations or driller's log notes.
Geolograph Strip Chart
A second common rig-floor mechanical method for recording footage drilled is the Geolograph plot ( Figure 3 , Geolograph strip chart used for recording kelly movement and determining ROP). Like the circular rate curve, the strip chart is cycled daily by a clock mechanism. Drillpipe movements are monitored by a cable attached to the kelly or block; this cable controls the recording scribe in the Geolograph. During routine drilling, the Geolograph is activated by the driller after each connection as the bit goes back on bottom. When the bit drills a predetermined distance and the kelly has been lowered accordingly, generally one foot, a tick mark is automatically scribed on the strip chart. This daily record of information also is transferred manually to logs and tables for ROP calculations.
Mud-Logging Sensors
Drilldown measurements used in ROP determinations by most mud-logging operations generally are made by using an idler wheel that senses the movement of the cable driving the Geolograph. When activated during drilling, each rotation of the sensor wheel is transmitted to the mud-logging unit where the signal is automatically digitized, displayed, and stored. This one-foot or one-half-meter signal is then combined with time, or pump strokes, to calculate ROP.
Presentation of ROP Data
Graphically, ROP is always plotted by increments of depth. Because depth (penetration) is vertical on the log, rate is plotted horizontally. Where time-per-distance is used for rate, time increments increase to the right; where distance-per-time is used, distance increments increase to the left ( Figure 4 , Plotting of ROP data-- distance/time vs. time/distance). This causes any increase in ROP to plot to the left in the same fashion as the left-hand track of wireline logs responding to the same parameters that affect ROP (e.g., rock type, porosity).
Rate of penetration can be plotted as a bar graph or a continuous line ( Figure 5 , Plotting of ROP data-- bar graph vs. line plot); the horizontal scale can be linear, logarithmic, or proportioned nonlinear ( Figure 6 , Plotting of ROP data-- linear versus non-linear scale). Each type of scale has its advantages and disadvantages. A linear scale, for example, will visually reflect the same amount of ROP change going from 10 to 20 ft/hr as from 50 to 60 ft/hr. However, it is easy to go offscale with a linear grid. Logarithmic or proportioned scales can show visually the
same relative increase of ROP going from 5 to 10 ft/hr as from 10 to 20 ft/hr (a doubling). However, such scales visually emphasize changes at low ROP and diminish them at higher ranges.
Experience shows that the final choice of horizontal scale should be made on the basis of (1) what will keep the expected ROP units on scale, (2) what is common in the geographic area for wireline logs, and (3) what meets the client's practices.
Factors Affecting ROP
Rate of penetration is not a simple reflection of the rock on bottom. A number of factors affect ROP. The principal ones that must be considered when evaluating ROP include the following:
Rock type, porosity, and strength
Bottomhole and bit-face cleaning and differential pressure at bit-rock interface
Bit diameter, type, condition, and jet configuration
Weight on bit and rotary speed
Only the first set of factors is related primarily to rock at depth. The second is more dependent on mud condition and weight; the third is controlled by the bit in use. The fourth set is most related to rigfloor operations and, to a degree, borehole inclination.
It is a simple matter to conclude, then, that an ROP curve can be affected, for example, by rig-floor operations or mud conditions as easily as by rock at depth. An increase in rotary speed can cause the same increase in penetration rate as can a transition to a more drillable lithology. Conversely, an increase in mud weight will slow penetration rate by adversely affecting differential pressure at the cutting interface. Therefore, interpretations concerning ROP should not be made in a vacuum. Consequently, factors such as bit type, mud conditions, hole inclination, and rotary speed are generally recorded or plotted in the ROP track, Track One.
However, once a drilling routine is established with the rig steadily making hole, many of the mud, bit, and rig-floor variables become nearly constant or change systematically. Under these conditions, bottomhole rock can be most influential in determining changes in ROP ( Figure 1 , General effect of rock type on ROP) and thereby be an immediate indication of rock conditions at the bit face.
Use of ROP Data
Under drilling conditions where there is little change in bit, mud, and operating variables, an ROP curve will develop certain characteristics reflecting specific downhole conditions. The most common features in the ROP curve are depicted in Figure 1 (Drilling and geologic conditions often identifiable on an ROP curve, particularly where balanced drilling practices are being observed), and described in Table 1., below. By recognizing such features as compaction trend, drill off-trend, and drilling breaks, some direct interpretation of down hole lithologic and pressure conditions can be made.
The Track One visual plot of ROP can serve as a tool for direct correlation with wireline logs from the same hole or other wells in the area. The most consistent correlations are with porosity logs (e.g., neutron, density, sonic, or in some cases SP and gamma ray). The very best correlation in well-lithified sections usually is obtained with the sonic (Interval Transit Time) log. This does not necessarily hold true, however, in many compacting off-shore Tertiary sections where claystone and mudstone drill as rapidly or more rapidly than sandstone. In older stratigraphic sections, nevertheless, similarities can be so strong between the two logs that it is possible, using normalization techniques, to generate a pseudo-sonic (pseudo-porosity) log that closely duplicates the real thing ( Figure 2 , Comparison of a synthetic (pseudo) sonic log generated by a drilling model with wireline borehole compensated sonic log from the same North Sea section).
The reverse also is possible. Sonic logs from adjoining wells are sometimes used to predict optimum ROP and drill-bit life. In this situation, the projected log can be compared repeatedly to daily formation log ROP and lithology plots to see if bits and drilling procedures are working as was anticipated when preparing the well program.
Table 1. Common Features Appearing in ROP Plots
Shale Baseline — The rate at which a uniform lithology (commonly a thick shale interval) is drilled by a single bit over its useful life. (In a carbonate section a limestone baseline may be established for comparative drillability.)
Drilling Break — An abrupt increase in ROP above the baseline average, generally due to change in lithology ( Figure 3 , General effect of rock type on ROP) or sudden increase (fault intersection) in formation pressure.
Reverse Drilling Break — An abrupt decrease in ROP, generally below the baseline average, and generally associated with change in lithology or the presence of a dense "cap" rock.
Drill-off Trend — A gradual or uniform increase in ROP, typically associated with increasing formation pressure (i.e., a transition zone from normal compaction to overpressured subsurface conditions).
Dulling Trend — A noticeable decrease in ROP due to bit wear near the end of its effective life.
Compaction Trend — A long-term decline in ROP (measured across many bit lives) that reflects progressive increase in rock density due to increasing compaction with depth.
Lithology and Shows
The principal data presented on the depth-lithology-show track, Track Two, are observations and depictions of lagged cuttings. Lithologic descriptions generally are recorded in abbreviated form in the right-hand track of the formation log. A list of these abbreviations may be found under References and Additional Information.
Factors Affecting Cuttings
Cuttings, and the shows they may contain, are influenced by four principal factors: lithology
being penetrated, bit characteristics
on bottom, wall stability
of the borehole, and mud system in
use.
Lithology
Although a principal reason for collecting and describing cuttings is to determine the rock types in the geologic section and their downhole changes, changing lithologies create one set of variables. Not all rock types are recovered uniformly. In some cases, such as in poorly consolidated claystones, almost no usable cuttings will be recovered. Such claystones are often made into a "mush" by the bit and incorporated in drilling mud during uphole travel so that they have lost their identity upon arrival at surface. In other cases, only partially representative cuttings will be recovered. Salts, for example, may be dissolved from evaporitic cuttings by water-base muds. In still other situations, although recovery is good, cuttings samples will not accurately represent what is at depth. A friable sandstone, for example, may disaggregate into individual grains so that features like texture, porosity, and staining cannot be accurately observed.
Bit Characteristics
Different bits and different operating conditions lead to different cuttings recovery in the same lithology.
Drag, or "fishtail," bits work by scraping or shearing the bottom of the hole. When used, they generally work best in poor to moderately consolidated clays, silts, and sands where they can peel the rock or make a mush. This shearing action results in poor cuttings at surface. Tricone roller bits generally produce better cuttings for description. Those with chisel-style, longer teeth, which are used in fairly drillable rock, produce good cuttings where tooth penetration and crushing is adequate. Roller bits with carbide buttons, which are generally used to crush harder rock, typically produce cuttings smaller than those from chisel teeth, but these cuttings will be representative of the rock at the bit face. The newly developed polycrystalline diamond compact (PDC) bits cut by a shearing action similar to that of drag bits, but PDCs can handle harder rock; cuttings from PDC bits are generally smaller than those from roller bits and therefore more difficult to describe and evaluate. Diamond bits, including those used for coring, produce the finest cuttings of all in hard rock. The result is that some rock types will be nearly impossible to describe accurately.
Each bit and rock type combination will have some effect, then, on the quality of cuttings reaching surface. And, of course, the manner in which the bit is operated can add another variable. If, for example, the bit face is not cleaned effectively so that "ball up" occurs, very fine cuttings or "mush" may arrive at surface for many rock types. As rotary table speed increases, cuttings will generally get finer. And some downhole drill systems, like turbo-drilling, can leave cuttings and shows with "cooked" appearances.
Wall Stability
Poor wall stability and high formation pressure can lead to cavings and other incursions into the mud system. Cavings can alter the bulk composition of cuttings reaching surface; these must, therefore, be removed by physical (screening) and interpretive (visual) separation during the logging process.
Mud System
A number of influences can be introduced by the particular mud system in use that affect lithologic and show determinations in cuttings. The effect of these must be removed before accurate descriptions can be made. The mud system, for example, may be oil-base or contain hydrocarbons or organic additives; these may obscure in-place petroleum or coal-bearing lithologies in the cuttings. Such contaminants as lost circulation material, recirculating debris, grease, and pipe dope may also be carried in the mud system. Furthermore, an overbalanced mud system can flush oil and gas from permeable rock so that potential reservoir shows are no longer visible during cuttings inspection ( Figure 1 , Borehole and mud conditions affecting cuttings and mud gas before arrival at surface.). In addition, some differential settling and mixing of cuttings can occur during uphole travel in response to mud weight, viscosity, flow patterns, and flow interruptions. Cuttings composition will be smeared accordingly.
Presentation of Cuttings Data
Observations recorded relative to lithology will differ with the wishes of the client and the skills of the mud logger. In all cases, however, cuttings and shows will be lagged to their true drilled depth. A percentage plot and an abbreviated description of lithology will be shown in Track Two and Track Five, respectively.
In basic formation logging, the Track Two lithology chart is divided into ten columns, each representing 10% of the cuttings recovered after screening for cavings ( Figure 2 , b). At each depth or sample increment, ten symbols will be drawn, typed, or plotted to indicate the gross lithology of the cuttings as recovered at surface. The symbols used will be from the lithology explanation chart
at the top of the formation log.
A more knowledgeable logger may modify the percentages shown in Track Two to reflect an evaluation of mud contaminants, openhole cavings, and uphole mixing. Such loggers will present their interpretations of cuttings as they are considered to have left bottom rather than how they arrived at surface. Small cavings, for example, will be "interpreted out" by the logger. Track Two in this case may be denoted on a formation log as a corrected cuttings log.
If qualified logging geologists are used, they may produce this corrected cuttings log and supplement it with an additional track showing interpreted true lithology. This will be prepared on the basis of cuttings information combined with drill rate, other drilling parameters, and gas and mud analyses. Formation contacts and lithology changes will be "called" more sharply in this situation.
Oil shows generally are denoted in Track Two by symbols at the depth increments at which they were found in cuttings. A brief numerical rating may be given on the log (often in Track One or Track Five), but most details will be carried in a separate show report identified by number in the show column. Such a show report will contain full notation of such factors as odor, staining, bleeding, reaction in acid, fluorescence, reagent cut, and similar specific tests.
Use of Cuttings Data
Lithologic and oil show data of Track Two generally find four uses: rock type and formation identification, reservoir interval characterization, mud and wireline log correlation, and pressure condition and trend recognition.
Rock Type and Formation Identification
Cuttings are the first hard data on rock type and configuration at depth that can be compared to the data inferred during prospect generation. First appearances of cuttings from different rock types, for example, can provide estimates of formation tops. Refined formation identification can be based on such cuttings factors as specific or characteristic rock type, diagnostic microfossils, and sequence of occurrence. The true vertical depth (TVD) lithology plot of Track Two, then, can be used like any rock section to construct or confirm the stratigraphic column and framework of the area.
Depending on the level of lithologic study provided, a number of other uses can be considered. It may be possible, for example, to infer changes in environment of deposition, as from reef core to back reef; this, in turn may give an indication of whether the active prospect is "on trend" or "shoreward" as proposed in prospect generation. It is also possible in some situations to recognize deformation that has duplicated or omitted stratigraphic intervals or resulted in their apparent thickening or thinning.
Reservoir Interval Characterization
The first documentable indication of porosity and permeability conditions related to oil and gas shows recognized by mud logging comes with inspection of cuttings. In some cases, cuttings characteristics may be adequate to characterize show lithology as relatively tight and of no economic interest. In others, cuttings may give first indications of a probable reservoir.
While drilling, cuttings lithology can be applied in many ways to reservoir considerations. As one example, an anticipated change in cuttings lithology arriving at surface sometimes serves as the basis for a "go ahead" on a planned coring program.
Mud and Wireline Log Correlation
Visual examination of the lithology track, combined with other mud log tracks and wireline logs, finds many uses. Final stratigraphic picks, for example, generally are made after a borehole has been fully logged. Formation tops, which are picked early in a well's history from inspection of cuttings, can always be refined with added information.
Conversely, in order to perform accurate interpretation of wireline log data, lithologic and mineralogic information is required. Although this type of information can be deduced from crossplotting wire-line log data alone, results generally are imprecise, and in mixed or complex lithologies there may be insufficient wireline data for conclusive interpretation. The detailed sample descriptions and mineral identifications available from a complete formation log remove some of the variables so that log response can be clarified and more accurately characterized.
Specialists will use combinations of lithology and show descriptions, mud log hydrocarbon data, and wireline log patterns to complete preliminary reservoir characterizations in many wells. They often utilize this combination of data sources for calculation of expected permeabilities and porosities in show intervals, positioning of sidewall core shots to sample reservoir lithologies, and selection of packer sites for drillstem tests.
Pressure Condition and Trend Recognition
The most recent application of cuttings lithology is for early detection of overpressure transition zones. This application finds most use with balanced drilling programs. From a basic formation log, some pressure information can be deduced from cuttings details. Simple density measurements taken during the description process can show a change in gradient suggestive of transition to overpressure. The fact that cuttings have become larger as penetration rate increases through a uniform lithology can also suggest a lowering of mud overbalance as increasing formation pressure comes into play at the bit-hole bottom interface.
Exercise 1.
Calculate the number of feet drilled during the following twenty-four hour period (assume that pipe length is 30 ft and that connections take 5 minutes), then fill in the blanks below.
0:00-2:30 on bottom following connection completion at 24:00; drilling ahead at 35 ft/hr
2:30-3:15 drilling break, ROP increased to 50 ft/hr
3:15-4:15 gas show, circulated bottoms up
4:15-8:00 no oil show, resumed drilling, ROP decreased to 40 ft/hr
8:00-9:15 short trip into Casing
9:15-11:45 on bottom, drilling ahead, ROP 30 ft/hr
11:45-12:00 no. 1 mud pump down, shift to no. 2
12:00-15:45 drilling ahead; ROP 35 ft/hr
5:45-20:30 increased mud weight; ROP 30 ft/hr
20:30-20:45 reverse drilling break; ROP 15 ft/hr
20:45-21:45 circulate bottoms up; no change
21:45-24:00 trip to check bit
The total depth drilled during the twenty-four hour period was approximately ___ ft.
The bit was on bottom drilling for a period of approximately ___hours ___ minutes (total active drilling time minus connection time).
The penetration rate for the 24-hr period was approximately ___ ft/hr or ___ min/ft.
Solution 1:
Total depth drilled is calculated to be about 573.1 feet.
The total active drilling time was 18 hours, 15 minutes, and the total connection time was (19 x 5) 1 hour, 35 minutes.
Hence, the total on-bottom drilling time was 16 hours 40 minutes. The average ROP was 34.3 ft/hr (572.1/16:40) or 1.75 min/ft (1000 min/573.1 ft; 60 min/34.3 ft).
Exercise 2.
The following factors affect penetration rate; what change has to occur in each case to increase penetration rate?
a. rock drillability
b. mud weight
c. rotary speed
d. bit condition
Solution 2:
a. Greater drillability, greater ROP.
b. Lighter mud weight (lesser differential with formation pressure), greater ROP.
c. Higher rotary speed (through normal speeds), greater ROP.
d. Better bit condition (normally in nearly new condition), greater ROP.
Exercise 3.
What do the following characteristics indicate about formation pressure?
a. shale baseline
b. drilling break
c. drill-off trend
d. dulling trend
Solution 3:
a. If well defined, shale baseline probably indicates normal compaction.
b. If not directly related to lithologic break, the drilling break may indicate crossing abruptly into overpressured section.
c. Most likely a drill-off trend is an indication of drilling through transition zone at top of an overpressured section.
d. If well defined, a dulling trend probably indicates nothing about overpressure; it may help confirm normal compaction.
D.4. Gas Measurement and Analysis
Gas Liberated by Drilling
The gas that enters the mudstream as a direct consequence of drilling is termed liberated gas (Mercer and McAdams 1981) in order to distinguish it from produced gas, which enters the annulus out of rock formations exposed in the wellbore; from recycled gas, which is carried into the borehole by circulating mud; and from contaminant gas, which is introduced in the mud stream as a consequence of such actions as using an oil-base mud or adding diesel to a water-base system.
The total volume of gas available for liberation from any drilled increment of rock will be in proportion to (1) the volume of rock drilled, (2) the porosity of that rock, and (3) the gas saturation within that porosity ( Figure 1 , Drilling and rock parameters that determine the volume of liberated gas in the drilling mud for any unit of time).
The process of gas liberation as a consequence of drilling, however, will be neither instantaneous nor complete. Grinding action at the bit cannot expose all pores to the mud system. In addition, the hydrostatic pressure of mud at the bottom of the borehole will commonly be slightly greater than fluid pressure within the rock pores. Thus, much of the gas in exposed pores will be held in place in the cuttings.
Following the grinding action of the bit, further liberation of gases and liquids occurs throughout uphole travel as residual fluid pressure in the cuttings overcomes decreasing hydrostatic containment of the mud. It may continue at surface, as shown by bleeding cuttings. Gas confined within isolated pores, however, will remain in place during uphole travel unless increasing pressure differentials cause fractures to develop in the cuttings.
It is important to remember that the overall composition of the liberated gas that is sampled by the gas trap at surface will be related to — but not the same as — the gas originally in place in the formation, the gas retained within cuttings porosity, and the gas dissolved in pore water and oil. All will have been modified by phase and solubility changes that occurred with uphole temperature and pressure changes and, therefore, cannot be equated directly to conditions at depth.
Influx and Flushing
Fluid flow can occur between the mud system and borehole wall rock at any place along the uncased well annul us where differential pressure and formation permeability are adequate. Influx
occurs when hydrostatic pressure is low enough to permit formation fluids to enter the well bore; flushing
occurs under reciprocal conditions ( Figure 2 , Borehole and mud conditions affecting cuttings and mud gas before arrival at surface).
Consequently, the rate of influx or flushing across the wellbore interface depends principally on the interrelation of two factors — pressure and permeability. In holes where pressures are close to balance or permeabilities are insufficient to sustain a major flow, only minor movements of fluids can be expected across the borehole interface. If pressure differentials are high or permeabilities are great, large incursions of produced gas, oil, and water can enter the mud system ( Figure 3 , Influx and flushing in the wellbore), or conversely, mud and filtrate can enter and flush the formation.
Where high pore pressures cannot be released from impermeable lithologies like shale, the rock can fracture or spall causing caving, sloughing, or collapse of the borehole ( Figure 4 , Common causes of uphole modification of drilling mud. Factors include influx of produced gas from underbalanced permeable intervals and cavings from overpressured impermeable intervals). Overpressured zones may respond in this manner if adequate mud overbalance is not maintained.
Together, produced gases, fluid incursions, and cavings entering from the borehole wall can be added to mud circulating surfaceward in the well annul us. The admixture of fluid influxes and rock cavings can cause serious discrepancies in formation logging data and affect interpretations.
As we have indicated, produced gas, oil, and water incursions may influx at any point from the bottom of the borehole to the casing shoe of a previously set casing run. Influx may result from a small sustained mud underbalance; this will yield a low continuous feed to the background gas reading. Alternatively, influx may result from a major underbalancing event of short duration (e.g., lifting drillpipe during a connection or trip). This results in a single large gas "show" at surface occurring at a predictable lag time after the underbalancing event. These short-lived incursions into the wellbore and mud system are called connection gas or trip gas.
To control influxes and at the same time prevent formation flushing and damage, it is good drilling practice to maintain a mud density sufficiently high to slightly overbalance formation pressure. This is balanced drilling.
If overbalance is not adequate, large fluid incursions can occur when high pressure gas, oil, or water zones are penetrated. Since these fluids are less dense than drilling mud, their presence in the borehole will lower the hydrostatic pressure further and worsen "underbalance." Eventually, there can be an uncontrolled fluid flow into the borehole and an expulsion of drilling mud at surface.
Expulsion of mud up the borehole is called a well kick.
If a strong kick is not controlled by closing the blowout preventers, all of the mud will be expelled from the annulus and formation fluid will flow freely to the surface, possibly resulting in a fire or explosion. This is a blowout. Consequently, an important function of modern formation logging is to monitor mud gas level, mud density, mud flow into and out of the hole, and mud volume in the pit in order to have early detection and alarm in case of a well kick.
When a well is consistently overbalanced, fluid flow or flushing will occur from the borehole into the rock. To prevent deep invasion and damage to formations adjacent to the open borehole, clay solids are incorporated in drilling mud. These particles filter rapidly from flushing muds to form a thick impermeable filter cake on the borehole wall for all but the most permeable formations. When the latter condition is present, lost circulation can occur. Halting this type of influx may require the addition of very coarse and platy "lost circulation material" (LCM) to the drilling mud. Needless to say, this type of addition means that formation logging may, at times, have to take into account LCM contaminants put deliberately into the mud system at surface.
Below the face of the drill bit, flushing is continuous. Filter cake cannot form under the crushing action of bit teeth and the jetting action of high velocity mud. If a very permeable formation is drilled, flushing action may be so great that mud totally displaces all original formation fluids ahead of the bit ( Figure 3 ). When such permeable rock is drilled and carried to surface, the cuttings will contain only mud filtrate. All traces of formation gas and oil will be lost. This may obscure a potential reservoir.
Total flushing such as this seldom occurs except when permeable zones are extremely thin and confined by impermeable beds. Individually, such thin permeable zones rarely contain commercial quantities of gas and oil. If the permeable zone is thicker, then it is possible that the pore fluid flushed back into the rock may be cycled back into the borehole behind the bit and its zone of turbulence. The effect of this can be that the top of the permeable zone will, from its gas show, appear to be a few feet deeper than other evidence (e.g., ROP break, cuttings porosity) indicates ( Figure 3 ).
Sample Lag
As we have just described, the mixture of gas, oil, water, and cuttings in the circulating mud travels from bit to surface along the well annulus. Furthermore, experience shows that during this uphole journey some mixing and preferential settling will occur ( Figure 2 ). However, the viscosity and gel strength of modern drilling muds will maintain a reasonably good order of sample arrival at surface and hold together fluids and solids from a particular drill depth. These representative samples, then, can be projected back to their true drill depth and rock source if uphole transit time, or lag time, is known.
Lag time for both cuttings and fluids is generally determined by a two-step process: (1) the addition of a tracer into the downhole side of the mud circulating system, and (2) the detection of the tracer when it returns to surface on the uphole side ( Figure 5 , One calculation is necessary to compensate for the number of pump strokes required to pump the tracer down the inside of the drill pipe). Tracer material can be any substance, like gasoline or chopped-up rubber bands, that can be detected analytically or visually upon arrival at surface.
The tracer method of lagging is consistently more accurate than that of volumetric or flow calculations based upon pump displacement plus bit, collar, and pipe sizes. This latter arithmetic calculation method cannot readily account for unpredictable hole enlargements, overdrill beyond bit size, and changes in pump output efficiency. However, a combination of tracer lagging and mathematical lagging can give a fair indication of hole condition. If the calculated lag is significantly shorter than the tracer lag, wall sloughing or washout can probably be inferred ( Figure 6 , Determining borehole washout by comparing the difference between calculated lag time an dtracer-test lag time).
It is sound practice to have tracer tests start early in any drilling program. This permits the combined characteristics of mud pump, tophole, and circulating system to be accounted for, so that down-hole conditions can be evaluated as they develop during drilling. It is also sound practice to have tracer tests run on a systematic basis, such as at the beginning of each shift or at predetermined depth increments. It also is routine to run a tracer test when drilling is resumed after a trip.
The most commonly used tracer is calcium carbide, a manmade crystalline solid that reacts spontaneously with water to form acetylene gas:
CaC2 + 2H2O Ca(OH)2 + C2H2
Calcium Carbide + Water Calcium Hydroxide + Acetylene Gas
Procedurally, a small packet of calcium carbide is dropped into the top of the drillstring when the kelly is unscrewed from the pipe to make a connection. As drilling resumes, the material is forced down the drillpipe by circulating mud and then out into the borehole through the jets at the bit. Upon circulating back to surface in the mud, the acetylene gas generated is routinely detected by the mud logging gas detector. Because acetylene is not encountered as a natural product during drilling, its occurrence and detection characteristics, as we note farther on in this unit, cannot be easily confused with a true gas show.
A further consideration in lagging with calcium carbide should be the use of the same amount of tracer in each lag test; subsequent variations in response at the detector can be used to evaluate changing efficiency of the gas trap and sensitivity of the detector. This variation becomes important when gas show data are normalized so they can be compared with one another.
In practice, lag time established by the tracer method is expressed as the number of pump strokes required to move mud from the bit to surface. This is determined by counting the total number of pump strokes required for the tracer's round trip and then subtracting the calculated number of strokes needed to carry the calcium carbide down the inside of the drillstring to the bit. Because the inside diameter of the drillpipe can be accurately determined, very little error is introduced into lagging by this one calculation.
Use of pump, or lag, strokes provides automatic correction in lag time for varying pump speeds and for periods when pumps are turned off, as when making a connection. Sampling of a particular depth or event, in other words, can be predicated on a specific number of pump strokes after that depth is penetrated or that event, such as an ROP break, has occurred.
Lagging is a simple matter when two stroke counters monitoring the same pump are used. One counter is set as "pump tally"; the other is set "lag strokes" behind. When a depth is reached or an event occurs, the numbers on the tally counter are recorded. The sample of the depth or event is taken when the lag counter reaches the recorded number. The only additional step that needs to be made when two counters are used is to add a predetermined number of lag strokes for each few feet drilled. This, of course, is because transit time from bit to surface increases progressively as a hole is deepened.
Once verified lagging has been established, minor adjustments can be made between tracer runs, if deemed necessary, by comparing current lag stroke count with sample arrival from known bottomhole events. A sharp drilling break due to marked change in rock type is one usable event. Connection gas arrival can also be used if the gas is coming from the bottom of the hole and not from uphole influx.
Phase and Volume Changes During Uphole Travel
In traveling from hole bottom to surface, rock debris, natural fluids, and circulating mud experience great changes in temperature and pressure conditions. Mud temperature may decrease by as much as three degrees centigrade for each hundred meters of upward travel (1.65° F/100 ft). In a 3000 m well (about 10,000 ft) this change can exceed 90º C (165º F) It is possible that under this cooling effect, compounds that are gaseous or liquid at depth may change phases and liquefy or precipitate, respectively, with uphole travel.
Pressure changes during uphole travel are also extreme. Hydrostatic pressure in the borehole is a function of the mean density and vertical height of the fluid column:
Ph = f Dv K
where:
Ph = hydrostatic pressure, KPa or psi
f = fluid density, kg/m3 lb/gal
Dv = vertical depth, m ft
K = unit conversion 0.0098 0.0519
From this hydrostatic pressure equation it is apparent that pressure (Ph) will decrease proportionally with vertical depth (Dv) (i.e., pressure is halved if depth is halved). We also know from the gas laws that pressure and volume are inversely proportional. Thus, with each halving of depth in travel to surface the volume of gas will double.
The combined result of temperature and pressure change, as governed by the gas laws, is shown in Figure 7 ( Changes in volume of gas at surface as a consequence of changes in normal pressure and temperature conditions during uphole travel). It can be seen that even low porosity and low gas saturation in rock at depth can produce a very large gas show at surface. Careful monitoring is necessary to discriminate between gas influx or well kick due to underbalanced drilling and the arrival of a large volume of gas-aerated mud resulting from penetration of a gas-bearing zone. To be effective then, gas monitoring must include consideration of ROP and lithology factors (e.g., porosity and permeability).
Hydrocarbon Gases
Hydrocarbon compounds, by definition, include only those made up entirely of hydrogen and carbon. Hydrocarbon gases are the simplest compounds contained in petroleum. They consist almost wholly of individual or short chains of carbon atoms with hydrogen atoms attached to all remaining available bond positions ( Figure 8 , Classification of hydrocarbons: composition of common hydrocarbon gases). They are classified as alkane hydrocarbons.
The fundamental characteristic of all alkane hydrocarbons is that the carbon chains are saturated with hydrogen. Carbon chains may be straight, branched, or cyclic; these patterns form the basis for three series of alkanes ( Figure 9 and Figure 10
, General categories of saturated straight-chain, branched-chain and closed-chain hydrocarbons and unsaturated hydrocarbons).
In mud logging, we are mainly interested in the five lightest alkanes (C2-C4), all of which remain in the gas phase at nearly all ambient temperatures. Various heavier hydrocarbons compounds (C5, C6) ( Figure 9 , Figure 10 and Figure 11 ) also may be present in mud gases and gas shows if the ambient surface temperature is high enough to prevent them from condensing in the mud-logging vacuum system. These also may be plotted on mud logs.
Because hydrocarbons represent carbon in a reduced form, they are all combustible — they react with oxygen, producing carbon dioxide, water, and energy in the form of heat. The oxidation reaction can be expressed in the general form:
Descriptively stated, this means that the quantities of carbon, hydrogen, and oxygen consumed and carbon dioxide, water, and energy produced will depend upon the number of carbon atoms (x) and hydrogen atoms (y) in the hydrocarbon molecules that are oxidized. Consequently, if a mixture of hydrocarbons is burned in oxygen, the total energy produced will be directly related to the individual molecular types present and the relative concentrations of each in the mixture. In other words, the amounts of carbon and hydrogen present to be oxidized determine the energy produced. This energy and some specific combustion products form the basis for the two most common methods of detecting hydrocarbons in mud gas-catalytic combustion and flame ionization.
Gas Sampling
Once mud gas reaches surface a portion of it enters the sampling and analytical cycle. Here, additional variables (e.g., extraction efficiency, ambient conditions) come into play that can affect the final analytical results. The two principal mud gas collecting mechanisms used in conventional mud gas logging are the gas trap sampler and the steam still sampler. A third collecting apparatus, the cuttings gas sampler, is used to extract gas retained in the cuttings arriving at surface. Although cuttings gas is not obtained totally from the mud system, it is analyzed in the same manner as mud gas and often used in conjunction with it as part of a full formation logging program. As such, cuttings gas also can show up in Track Three or Four if the analysis is not part of a separate geochemical program.
Gas Trap Sampler
The first separation step in continuous combustible gas logging is taken at the gas trap. The principal objective of this trap is to extract a relatively consistent gas sample from the mud for continuous analysis.
The typical gas trap is housed in a rectangular or cylindrical metal box installed in the flowline or ditch. In one style of gas trap ( Figure 1 and Figure 2 , Standard gas trap configurations), an internal impeller (1) draws mud into the trap through an upstream port, (2) agitates it to lower its viscosity and free the entrained gas, and (3) discharges it through a downstream port. In another common style ( Figure 3 , Schematic of baffle-type gas trap), returning mud is cascaded down a series of baffles so that gas is released. The former type provides more consistent sampling because it is less affected by varying mud return rates and viscosities.
In both types of gas trap, ambient air enters the trap above mud level and, with the freed gas, is drawn through a moisture trap and vacuum line to the mud-logging unit. Here the sample passes through filtration and further drying steps and is routed and metered to various gas detectors and analyzers ( Figure 4 , Schematic of mud gas flow system, from gas trap through analysis in the mud log unit).
Steam Still Sampler
A supplementary means of intermittent gas sampling that is sometimes used at the wellsite is the steam or vacuum mud still (
Figure 5 , Steam still with mud chamber atop heating unit). For this technique, a sample of drilling mud is caught by hand at the flow line and returned immediately to the logging unit. For gas extraction, the sample is placed in a flask, heated by steam discharge, and placed under vacuum in order to remove all volatilized hydrocarbons. Following cooling and drying, the extracted gas is analyzed by routine mud gas techniques.
Extraction efficiency is very high in the steam still technique; however, the procedure also is time-consuming and may require an additional operator to carry out repetitive analysis. Consequently, the mud still's principal use in most conventional logging programs is to add supplemental information to the evaluation of a specific drilled interval, such as an oil or gas show. It generally is not considered a replacement for the gas trap technique. Systematic use of the still while drilling, however, can provide a baseline for recognizing changes in gas trap efficiency and assisting in the normalization of analytical data from samples taken at the gas trap. The still probably provides the most representative mud gas sample because of its extraction efficiency; as such, it should be weighted heavily when mud gas compound ratios are used to interpret formation fluids at depth.
Cuttings Gas Sampler
The general method used to sample gases still retained within cuttings is to place the cuttings in a closed container, mechanically disaggregate the sample, and then draw off the liberated gas. The most common configuration for a cuttings gas sampler is a blender jar with a cap fitted with gas-sampling tubing ( Figure 6 , Cuttings blender, vacuum tubing and gas detector and Figure 7 , Schematic of cuttings gas analytical flow system).
Procedurally, about one cup of fresh cuttings is taken at the shale shaker, placed in the blender, covered with an equivalent amount of clean water, and blended for a specific number of seconds, generally up to two minutes. The shattering action of the blender blades physically breaks the cuttings down so that all pore walls are fractured and contained gases are liberated.
Once the gas is liberated and available for sampling, it can be processed in the manner of any gas batch sample. Typically, a measured amount of gas is drawn off by vacuum and analyzed. The type and completeness of the analysis (e.g., total combustible gas, individual compound types) will depend upon what uses and comparisons will be made with the analytical data.
Gases contained within cuttings are the most reliable mud-borne samples routinely available at surface to indicate original, if not complete, fluid content at depth. These may be very important in locating the top or bottom of show zones or in detecting first occurrences and trace components. Cuttings gas data can also have application in estimating changes in effective permeability and rock porosity when compared with mud gas data.
The principal limitation of cuttings gas sampling is that, characteristic of all intermittent or batch samples, it is not continuous. In general, it seldom represents sample density any closer than that used for lithologic descriptions. In addition, if an oil-base mud is used, or contaminants are present, these must be rinsed from the cuttings sample prior to blending. This can affect the validity of the analytical data.
Gas Detection and Measurement
Mud gas detection techniques generally are based on a single diagnostic chemical or physical property of a gas molecule. This means that not all gases can be detected by the same technique. This can be easily recognized if we remember, for example, that not all compounds are combustible, or fluoresce, or react with acid. Therefore, each detection technique used in mud logging has specific capabilities and limitations. The combinations of different techniques used by different logging companies generally reflect what their experience has shown to be an effective balance between detection level, reliability, and cost.
Hydrocarbons, as we noted, give off heat and reaction products when burned. The amount of each depends almost entirely on the specific hydrocarbon molecules present. By measuring one of these combustion products it is possible to approximate or quantify the nature of the original hydrocarbons. This approach is the basis for catalytic combustion and flame ionization detection used while logging for combustible gases.
Two other properties commonly used in mud gas detection are based on properties unrelated to combustion; these are thermal conductivity and infrared absorption. Because such properties do not rely on any oxidizing (or reducing) reactions, they are often used to monitor mud gas mixtures that also contain nonhydrocarbon gases; these include dangerous and undesirable gases like hydrogen sulfide and carbon dioxide.
Catalytic Combustion Detector (CCD)
The original mud logging gas detector, and one still widely used in conventional mud logging, is the catalytic combustion, or "hot wire," total gas detector. In this device, the filtered and dried gas sample is passed continuously, at a controlled flow rate, through a combustion chamber containing a heated platinum filament. Filament voltage is adequate to induce total combustion in that small portion of the gas stream that comes into contact with the catalytic platinum surface. In practice, as we discuss below, catalytic combustion detectors may be run in pairs, with the second unit set at a cooler, lower voltage so that combustion of methane does not occur. This produces a "petroleum vapors," "heavies," or, as referred to in this reference, wet gas detector.
An advantage of catalytic combustion is that a uniform, proportional reaction rate is maintained across a normal range of combustible gas concentrations in drilling mud (up to about the equivalent of 6% methane). This yields nearly linear signal response for most hydrocarbon/air mixtures coming from the gas trap and provides good sensitivity to extremely low gas concentrations.
Measurement of hydrocarbon gas content in a sample is obtained in the following manner in a catalytic combustion detector. The platinum filament forms one resistance arm of a Wheatstone bridge circuit in balance with three other arms ( Figure 1 , Schematic of a Wheatstone bridge used as a catalytic combustion detector). When catalytic combustion occurs, energy in the form of heat is liberated in proportion to the content of hydrocarbons (hydrogen and carbon atoms oxidized) in the sample. This, in turn, heats the platinum filament and increases its electrical resistance proportionately. The bridge circuit is unbalanced by this change in resistance and the resultant electrical potential across the bridge can be measured and calibrated in terms of combusted gas concentration.
In mud logging, output from the catalytic combustion detector typically is routed to one or more of three devices: integrator meter, strip chart, and integrator/digital recorder ( Figure 2 , Typical hydrocarbon detector with strip chart recorder. Instruments for monitoring lag time, position of bit, and mud pit volume are incorporated in this detector panel). Generally, the meter is used to monitor the continuous operation of the detector; needle limits are set to sound a signal if gas readings go significantly above background, providing an audible "gas show" alert. The strip chart becomes a continuous trace of gas concentration against sample time and provides a permanent visual record of detector response. It is also used to estimate periodic averages or pick the highest concentrations to be plotted on the formation log. The digital recorder has storage and printout capabilities that find most use in modern systems incorporating computer handling of data.
Let us look briefly at the catalytic combustion detector as a total gas detector. In this higher-voltage, "hotter" configuration, the detector is nondiscriminating. It will respond to all combustible gases, including gaseous hydrocarbons, rare appearances of naturally occurring hydrogen, and acetylene used as a lag-time tracer. Consequently, its single output will depend upon both the concentrations and the compositions of gases reacting at the catalytic "hot wire" surface.
Because heat of combustion and consequent detector response increase with higher concentrations and molecular weights of the hydrocarbons present (Table 1., below), the catalytic combustion detector sums this effect; thus the name total gas detector. Its response may, to a degree, be considered a "richness" indicator. That is to say, an increase in detector response may indicate an increase in gas concentration, an increase in gas molecular weight, or both.
Table 1. Minimum Ignition Temperatures for Various Gases
Gas | TemperatureoC | Ignition Voltage, volts |
Methane | 632 | 0.9 |
Ethane | 520 | 0.6 |
Propane | 481 | 0.45 |
Butane | 441 | 0.3 |
Hydrogen | 580* | 0.2 |
*In the presence of a platinum catalyst, hydrogen will react vigorously with oxygen at much lower temperatures.
As we noted, some conventional logging units may be equipped with a wet gas detector; this is a catalytic combustion detector similar to the total gas detector but operating at a lower bridge voltage and cooler filament temperature. At the lower temperature ( Figure 3 , Response of catalytic combustion (hot wire) detector to different concentrations of hydrocarbon gases. The maximum response of each gas represents the approximate concentration at which that gas reaches saturation with oxygen in air, and above which complete combustion cannot occur), the platinum does not provide sufficient energy to induce combustion of methane; ideally the filament will only detect the presence of heavier gas hydrocarbons like ethane, propane, butane, and isobutane. However, if the combustion effect of the heavier gases passing across the filament is large, surface temperatures may become adequate for some combustion of methane. This is one source of error in the low-temperature configuration.
You are reminded that neither type of detector can be calibrated to measure absolute gas concentrations in the gas/air mixture. This is because more than one hydrocarbon compound type generally is present. Consequently, for total combustible gas logging, catalytic combustion detectors are calibrated to a reference gas. This means that detector output is in units equivalent to the combustion of a specific concentration of a single gas.
The most commonly used calibration gas mixture for total combustible gas logging consists of one percent methane in air (i.e., equals 1% EMA). Using such a standard calibration gas, detector output is generally reported and plotted on the formation log as Total Combustible Hydrocarbons: % EMA or Wet Gas Hydrocarbons: % EMA ( Figure 4 , Total combustible gas track).
Some contractors report mud gas in total gas units. These units generally are specific to a particular type of detector design and calibration gas mixture. If total gas units are used on a mud log, it is advisable to have conversion information recorded on the log heading, (e.g., 100 total gas units = 2% EMA total combustible hydrocarbons). This may be essential when attempting to normalize and correlate responses with other mud logs and is the type of performance level that can be required through contractual specifications or confirmed at the prespud meeting.
Catalytic combustion detectors are not without their limitations. At high gas concentrations, in excess of 6% EMA, the catalytic combustion detector begins to lose linear response; at about 10% EMA, the mixture becomes saturated with hydrocarbon gas and has insufficient oxygen available to induce complete combustion (i.e., air is about 21% oxygen and two units of oxygen are needed to combust one unit of methane: CH4 + 202 CO2 + 2H2O). However, saturation can occur much below 10% total gas (i.e., propane: C3H8 + 5O2 3C02 + 4H20) because we are dealing with methane equivalents, not gas concentrations. Heavier gases require more oxygen per molecule of gas to burn completely ( Figure 3 ). Above 10% EMA concentrations it is necessary, therefore, to dilute the gas sample prior to introduction into the combustion chamber. Dilution results in a progressive loss of accuracy for each decrease in sample size. It is commonly accepted that valid response of a catalytic combustion detector is lost with the level of dilution necessary to accommodate a gas over 40% EMA.
Another limitation related to oversaturation can occur with a catalytic combustion detector operating in the lower temperature, wet gas configuration. An abundance of heavier hydrocarbons in the rich gas mixture may cause the detector to give a greater response than a total gas detector sensing the same mixture. Therefore, a negative difference in measurement between total gas and wet gas is given. A total being less than any of its parts is of course, impossible and is simply a reflection of a greater response to the abundance of larger molecules being selectively combusted as methane is ignored.
A more serious disadvantage of the catalytic combustion detector is that the effectiveness of the catalytic surface declines progressively over the lifetime of the filament; this decreases its sensitivity correspondingly. Twice daily recalibration of the detector and regular performance checks are recommended by many users to assure reliable performance. The response of the detector to acetylene lag gas returning uphole should also be used to check for declining sensitivity.
As a further limitation, the presence of certain "catalyst poisons," such as silicon compounds, hydrogen sulfide, or leaded gasoline used as a tracer, may even totally deactivate the detector in a matter of minutes. Because of this, many catalytic combustion detectors have scavenging systems, such as charcoal filters in the gas flow line, to remove deleterious gases. This should be remembered when using the mud gas flow line to supply other analytical equipment.
Flame Ionization Detector (FID)
Unlike catalytic combustion, the flame ionization detector requires complete combustion of the mud gas sample. This is assured at all concentrations by mixing a small amount of the continuous mud gas stream into a completely combusted hydrogen flame.
Detection depends upon a specific ionization process that takes place when compounds containing carbon-to-hydrogen (C-H) bonds burn in a high temperature flame. This process involves the formation of unstable negative alkyl (alkane functional groups) ions and positive hydrogen cations as an intermediate step in the combustion process:
2H2 + O2 2H2O
Hydrogen Flame
CH4 H+ + CH3
Methane Molecule Hydrogen cation Methyl Anion
Both the methyl (alkyl) anion and the hydrogen cation are violently unstable and under "open-air" circumstances would rapidly combust with oxygen to form the normal reaction products of carbon dioxide and water. However, in the flame ionization detector, a cylindrical anode surrounds the flame (
Figure 5 , General features of a flame ionization detector. Note the position of the anode probe/collector cylinder for gathering anions and the cathode probe for collecting cations. The electric potential between the two probes is a proportional measure of hydrocarbon combustion occurring in the detector flame). The methyl anion (-) is attracted to this anode (+) where it discharges an electron and becomes a neutral methyl radical. The radical then undergoes complete combustion. Similarly, the hydrogen cation (+) becomes neutralized by gaining an electron at the grounded combustion chamber cathode (-) wall before combusting further. When the anode and cathode are held at the correct electrical potential, all ions produced are captured within the detector. This ion flow completes an electrical circuit and appears as a current flow that is measured by a sensitive meter device ( Figure 6 , Schematic of basic flame ionization detector circuitry). The current flow is directly proportional to the volume and types of hydrocarbons in the sample. The output of the detector is amplified to produce a signal that is sent to a meter, plotter, or integrator/recorder in the same manner as for the catalytic combustion detector.
The flame ionization detector, as implied above, responds both to the concentration of hydrocarbons present and to the number of breakable carbon-hydrogen bonds within them. In other words, flame ionization detector response is a richness indicator much like that of the catalytic combustion detector because it sums both concentration and composition. For this reason, its output is also standardized to, and expressed in, % EMA.
The flame ionization detector yields more uniform and linear richness readings and is less subject to progressive loss of sensitivity than the catalytic combustion detector. It also has greater sensitivity to very low concentrations. In addition, it will not respond to the presence of hydrogen gas in the mud stream. However, it is the less rugged of the two detector types and is more susceptible to malfunctions under normal wellsite conditions. Daily or more frequent calibrations with a gas standard are recommended to compensate for electronic baseline drift.
Thermal Conductivity Detector (TCD)
The thermal conductivity detector may be thought of as a catalytic combustion, or "hot wire," detector operating in reverse ( Figure 1 ). This detector consists of a similar Wheatstone bridge circuit, but by using either a tungsten filament or a very low filament voltage, combustion is prevented. In this case, filament temperature and bridge potential will depend on the ability of the mud gas sample to cool the filament as it passes over the heated metal surface. (This cooling effect is also present in the catalytic combustion detector but is very small compared to heat of reaction; it is effectively adjusted out for low gas concentrations when the instrument is set for "zero" gas.)
Thermal conductivity, that is cooling effectiveness, of a particular gaseous compound depends upon the molecular kinetic energy of the gas. This property depends inversely upon the molecular weight of the gas ( Figure 7 , Properties of mud gases, particularly as related to thermal conductivity detectors). Stated another way — the lighter the gas, the more kinetic energy present and the greater the cooling capacity. Methane, having a lower molecular weight than air, for example, will have a substantially greater cooling effect. Therefore, in a pure methane-air mixture, like a standard, the higher the methane content the greater the "positive" (or cooling) response on the detector. This effect is linear with methane concentration and may be so calibrated in % EMA. The fact that linearity extends to 100% concentration makes it a good detector to supplement catalytic combustion detection for high methane concentrations.
As might be anticipated, the thermal conductivity detector responds poorly to heavier hydrocarbon and noncombustible gases. These may even give a "negative" response when their cooling is less effective on the heated filament than pure air or other carrier gas. Conversely, low molecular weight hydrogen and even non-combustible helium have a thermal conductivity response greater than methane. In overall performance, the thermal conductivity detector is the least sensitive of those discussed to this point.
Obviously, the thermal conductivity detector, while ideal for detecting concentrations of a single gas and carrier gas mixture, is too unpredictable in response to be used routinely as the sole detector on the mud gas mixtures coming from the gas trap. As suggested above, this technique finds a common mud-logging use in the detection of very high concentrations of methane; it also is used in the detection of noncombustible gases like carbon dioxide after they have passed through purifying steps.
Infrared Absorption Detector (IRAD)
One additional instrument, the infrared absorption detector, may be used in mud gas logging ( Figure 8 , Schematic of a modern infrared analyzer. The basic concept is to alternate infrared energy of a predetermined wavelength through parallel optical cells (sample cell and comparison cell) and detect the change caused by the sample). The IRAD has been applied recently to hydrocarbon detection, with limited success. The principle of the measurement, whether for detecting hydrocarbon or other compound types, depends upon the fact that any one type of chemical bond within a compound will absorb infrared energy of one particular wavelength. If a gas sample is irradiated with that specific wavelength of infrared energy, the energy should be absorbed in proportion to the number of those bonds present, and, therefore, be a method of detection and measurement.
In practice this does not work accurately for hydrocarbons; all C-C bonds are similar but not identical. The same is true of all C-H bonds. For this reason, there are not two discrete peaks of infrared absorption for hydrocarbons but continuous bands of overlapping absorption wavelengths. These bands do not allow precise determination of hydrocarbon concentrations.
The most effective use of infrared absorption in mud gas logging is for the detection of single gases, specifically carbon dioxide. This is followed by determining concentrations of single pure hydrocarbon compounds after separation by chromatography. When applied to hydrocarbon mixtures it is less effective in estimating total hydrocarbons (% EMA) and light/ heavy ratios than dual voltage catalytic combustion detector systems. Because it responds to nonhydrocarbon gases as well, it is seldom used to replace combustion detectors.
Gas Compound Separation
Gas chromatography is the principal separation method used in mud logging. Infrared absorption, when narrowed to a specific wavelength, also can be used in mud logging to discriminate among and monitor the presence of a few selected individual compound types; most common, as we have said, is carbon dioxide.
Gas Chromatography (GC)
Chromatography is a separation method in which a complex mixture is passed through a medium that retards individual compound types at different rates ( Figure 1 , Basis of gas chromatography). The retardation or retention rate depends upon the specific chemical and physical character of each compound type relative to the medium. Procedurally, the mixture passes along a conduit in a mobile (gas or liquid) state. Identical compounds in the mixture are retarded at the same rate by the fixed-state medium, become grouped together as waves, and ultimately exit the conduit at the same time as a surge. A detector sensitive to that compound makes an accurate measurement of the quantity in the surge.
A variety of chromatographic procedures are available, but the technique commonly used in mud logging is, as we stated, gas chromatography. In this, the compounds to be separated are carried in a gas phase through tubing in which separation occurs. The tubing, or "chromatographic column," can have an exceedingly small internal diameter that is coated with a retarding liquid or can be of larger diameter and packed with porous material soaked with retarding liquid.
The choice of the carrier gas that moves the sample through the chromatographic column is determined by the compounds to be separated, plus the type of detector to be used. If feasible, a carrier gas is chosen to which the detector is insensitive.
In gas chromatography, the column is heated and maintained at a constant temperature. Heating the column speeds up the elution time, thereby allowing a greater number of chromatograms to be obtained during a fixed interval of time, while maintaining the column at a constant temperature "fixes" retention time so that it does not vary between samples. Consequently, component identification remains a direct function of analytical time. Maintenance of constant temperature is essential when the analytical instrument uses an integrator/recorder for data output and compound identification.
In practice, mud-logging gas chromatography encompasses four sequential steps: (1) sample collection, (2) sample injection, (3) chromatographic separation, and (4) compound detection. These are carried out with the sample flow loop, batch sampler, separation columns, and detector.
Sample Flow Loop-This unit collects the mud gas sample. Collection is done by splitting off a portion of the gas coming from the gas trap in the mud gas vacuum system. The diverted portion is passed at a controlled rate and pressure into a continuously refreshed flow loop.
Batch Sampler- This unit isolates the gas sample to be analyzed and triggers the separation phase. Periodically the sampler takes a representative gas sample from the sample flow loop and "injects" it into the chromatographic column to start the analysis. This sampling and injection step is repeated every few minutes as each full analytical cycle is completed.
Separation Columns- This assemblage is the heart of the gas chromatograph. For efficiency, most mud-logging gas chromatographs contain two columns. This permits one column to perform a separation while the other is being backflushed, cleansed, and prepared for its next separation cycle. Two columns also permit two different separations or analyses to be performed alternately.
Detector- After chromatographic separation, the components of interest pass to a suitable detector in predictable order. Each component arrives as a nearly pure sample and may be both identified by its sequence or time of arrival, and quantified by its detector response. Catalytic combustion or flame ionization detectors are commonly used when only the presence and concentration of hydrocarbons are being determined. Thermal conductivity or infrared detectors have more general applications although, as discussed in the text, they are less sensitive in many situations.
An example of two columns set up to make different separations for analysis is offered in Figure 2 (Schematic of a gas chromatograph set up for two-column operation). It is common to make alternating analysis of (1) the lightest combustible gases, hydrogen and methane, by separating them with one column and (2) the combustible gases, methane (plus hydrogen), ethane, propane, isobutane, and butane, by separating them with the other ( Figure 3 , Separation of hydrogen and methane;
Figure 4 , Separation of light hydrocarbon gases (note effect of nitrogen carrier gas);
Figure 5 , Separation of light hydrocarbon gases (note effect of helium carrier gas);and Figure 6 , Separation of light hydrogen gases (note effect of hydrogen sulfide)).
As another example, the first, or primary, column can make a rapid separation of gases to be analyzed from those to be discarded ( Figure 7 , Schematic of gas chromatograph set up for dual-column operation). In this dual-column case, components for which the column was designed, like gaseous hydrocarbons, pass rapidly through the primary column and pass out of the system. Undesirable gases, like hydrogen sulfide, which may damage a detector, or light liquid hydrocarbons, which might contaminate a sensitive column, progress more slowly through the primary column and never reach its exit during this cycle. They are back-flushed and exhausted from the primary column after the separated gases pass into the other, secondary column to complete the full analytical cycle.
In each of these examples, separated components arrive as nearly pure samples that may be both identified by their sequence of arrival and quantified by their detector response. Catalytic combustion or flame ionization detectors are commonly used when only the presence and concentration of hydrocarbons are being determined. Thermal conductivity or infrared detectors have more general applications, although, as we have discussed, they are less sensitive in many situations.
Measurement of individual compounds is intermittent. This is because we are no longer looking at continuous monitoring of the same material, as is the case with total combustible gas analysis. Although a gas chromatograph detector may be providing output almost continuously, it is measuring values for different compounds as they occurred in batch samples taken every few minutes. Therefore, data, whether presented on a meter, a chart, or a digital record are values for a number of individual compounds, with only one value per compound for each analytical cycle. These can be averaged or plotted as points on the formation log, as with continuous total gas measurements.
Chromatographic systems are calibrated in the same manner as simple detector systems — by the use of a standard. In this case, however, the standard contains all of the compounds being measured, and in known amounts. For hydrocarbons, a typical standard consists of one percent of each of the five gases, methane, ethane, propane, butane, and isobutane, mixed with ninety-five percent nitrogen. When a standard is run, the response given by the detector for each compound is recorded and used to calibrate other percentage values for the individual compounds. Some operators require a three-point calibration; when this is carried out, two standards plus air are used.
A calibration cycle should be run at least once a day and also when sensitivity loss or drift is suggested by comparison of chromatographic data with total mud gas or lag gas readings. Care should also be taken in the use of the standard to assure that storage temperature has been high enough to keep all components in a mixed, gaseous phase.
Infrared Absorption Discriminator
In certain situations, it is not necessary to physically separate an individual compound type from a mud gas mixture in order to measure the quantity present. Some detectors can be made so specific that they become, in effect, compound separators. The current principal use of the infrared absorption detector is in such a configuration — the energy source is set for a single chemical bond. That makes it both a detector and a separator, or discriminator; the measurement of carbon dioxide concentration in mud gas samples, as we have said, is a common application.
Calibration of an infrared unit is generally by the use of two gases, one containing no gas to which the discriminator is sensitive — a "zero" gas, and one with a known amount of detectable gas — a "standard" gas. These two provide the baseline and reaction factors needed to set response values. Commonly a meter is used for continuous monitoring and a recorder to provide a permanent record. Output also can be linked to alarm systems and to on-site computer storage systems.
Gas Plots
Two general types of hydrocarbon gas plots appear on the formation mud log. One is the continuous summary type, which is typified by the total combustible gas plot shown on Track Three ( Figure 1 , Total combustible gas track). The other is the intermittent, individual-compound type, which contrasts values from batch sampling; these are found on Track Four of our example ( Figure 2 , Gas Composition track).
Each type has a variety of uses. The continuous plot, for example, provides a gas background level against which to plot shows, trip gas, connection gas, and feed-in from declining mud overbalance responses. The detailed plot, on the other hand, gives insight into changes in hydrocarbon character, such as an increase in propane and butane, which might be associated with an oil show or changing reservoir conditions.
In nearly all cases, however, the points plotted on Tracks Three and Four are representative values; because of vertical scale it is generally impractical, if not impossible to plot all analytical results on the formation log. Presentation and use of gas data generally dictate how the data will be plotted.
Presentation of Gas Data
As is true for the ROP data in Track One, of the formation mud log, all changes in gas volume or composition are plotted horizontally on Tracks Three and Four. In the case of gases, convention dictates that an increase in volume or relative concentration is plotted to the right. This means that factors which, for example, usually reflect increasing porosity on a ROP curve, will be depicted in the opposite direction on the total gas curve. A mirror image presentation then is established on opposite sides of a formation log, much as on many wire line logs.
As with Track One, horizontal scales can be either linear, logarithmic, or proportioned nonlinear. Current practice favors the latter two scales. These can show wide-ranging gas readings, which are common to mud gas logging, without requiring scale changes; at the same time they can show small variations at low concentrations, which also have significance in mud logging. Units selected for the horizontal scale of total combustible gas may be in % EMA or in arbitrary units that are equated to % EMA (e.g., 100 units = 2% EMA). These same units, plus parts per million (ppm), may be used for detailed hydrocarbon gas analysis data carried in Track Four.
When a comparative plot is used, as to depict gas wetness (% not methane), percentages of individual hydrocarbon gases within the analyzed sample are generally plotted on a linear scale. This type of plot shows relative changes in composition but gives no indication of quantity (i.e., combined gas measurements always equal 100%).
Data plots may be in bar graph or continuous curve format similar to ROP. In most cases, the same format will be used for Tracks One, Three, and Four of a single log so that visual comparisons and correlations are easily made.
Because most data points on a gas plot can represent a number of repeated analyses or a period of time of continuous analysis, the significance of a plotted point will vary depending upon the system used to select the plotted value. In some cases, the average or the mode for the number of analyses or length of period is plotted. In others, the highest reading within the same increment is plotted. For some plots, as connection gas, the value plotted may be the total reading or it may be only the value above background. The operator normally designates which values are to be plotted in light of their use and their compatibility with other formation logs from the area.
Characteristics of Gas Data
As gas data are compiled on the formation log during the drilling life of a well, a number of recurrent features become apparent ( Figure 1 , Total combustible gas plot from chart recorder with diagnostic features noted). Many, such as connection gas, lag gas, and down-time gas, result from drill-rig operations; others, such as background gas, are related to downhole changes in lithology.
Once the influences of relatively predictable factors on mud gas data are recognized, then identification and evaluation of unpredictable variables are practical. The two most significant anomalies are:
Gas Show — Any unexpected or anomalous increase in mud gas content. It may result from liberated gas, produced gas, recirculated gas, or mud contaminants. A "true" gas show is from liberated gas coming off bottom.
Increased Feed-In — Progressive increase in the amount of connection gas, down-time gas, or produced gas arriving at surface. This condition probably indicates a declining mud overbalance relative to a permeable open-hole zone.
Repetitive features that may be recognized and annotated on total combustible gas charts
· "True" Zero Gas or Air — The minimum reading obtained when only air is passing through the mud gas detector.
Zero Gas or Circulating Background Gas — The amount of gas present in a circulating mud system while the drillstring is off bottom, rotating, and undergoing no vertical movement.
Background Gas — The relatively consistent mud gas value measured while drilling through any uniform lithology at a uniform rate. The points plotted on the total combustible gas track can approximate this value if an average or mode is plotted.
"True" background gas values have a zero gas factor subtracted from the average or mode used.
Total Gas — The maximum reading during an interval, or the total reading at any one time. Individual points plotted on the total combustible gas track can be these values if no averaging is used for each interval. Total gas includes background gas and any other hydrocarbon gas present.
Connection Gas — The increase in mud gas above background level that occurs as a consequence of making a drillpipe connection. When the mud-circulating system is shut down to make a connection, gas influxing at depth will accumulate in the mud; this connection gas surge will arrive and be monitored at surface when circulated up after drilling resumes.
Generally a background gas value is subtracted from a connection gas measurement so that connection gas is plotted at this lesser value rather than at total reading. Connection gas should arrive one lag time interval after the connection is made if it is coming off bottom.
Survey Gas — The increase of mud gas above background level that results from influx when mud circulation stops during a directional survey.
Down-Time Gas — Any gas that influxes during a period in which circulation has been stopped. (Connection gas and survey gas are two specific types of down-time gas.)
Trip Gas — The increase of mud gas due to the effects of swabbing and no mud circulation (as with connection gas), which occurs while drillpipe is being pulled up the hole. Trip gas may occur from either a short trip (e.g., pulling up into the casing) or from a full trip to surface.
Kelly-Cut or Top-Trip Gas — The added gas response measured as a consequence of a slug of air entering the mud system when a connection is made or a trip to bottom is completed. The incorporated air tends to aerate a small interval of mud and thereby make it more able to entrain gas during its round trip and to break out as the aerated mud expands on return to the surface. A kelly cut should arrive one full mud circulation period after a connection.
Top Connection Gas — An increase in sampled gas that is the result of a temporary accumulation of gas near the bell nipple when the mud system is shut down. This at-surface condition will vary with the configuration of the mud discharge line and the gas-sampling system. It may be avoided by circulating mud past the gas trap before resuming gas analysis after a connection.
Lag Gas — Any artificially introduced gas used to determine mud circulation rate or lag time. Acetylene is a common lag gas; light hydrocarbons like gasoline may also be dumped in the mud system for lagging.
Note: When gasoline is used, it should be white or unleaded to avoid lead damage to detector filaments.
Uses of Gas Data
The two broad uses of mud gas data in formation logging are:
Correlation — recognition of similarities with other logs and wells.
Evaluation — recognition of anomalies in the well being drilled.
In correlation, we are looking for interwell hydrocarbon and rock related data, as in characteristic background gas levels or in drilling breaks caused by anticipated lithologic changes. In evaluation, we are looking for variations in related rock and hydrocarbon data, such as increases in porosity denoted by increases in gas content, or as changes across a reservoir denoted by changes in gas composition.
In the remainder of this section, we generally consider mud gas and cuttings gas data relative to these two aspects as they are reflected in the continuous summary plot of Track Three and the intermittent component plot of Track Four. In the following discussion, remember that correlation and evaluation are, to a degree, end members in the use of gas data and each finds use in the interpretive region between them.
Correlation
Pattern correlation is perhaps the first or most obvious correlative use of mud gas plots as they are developing in a drilling well. The total combustible gas plot combined with the ROP or lithology curve can often be used visually for direct formation correlation with mud gas and wireline logs from adjoining wells. This type of pattern correlation permits bottomhole stratigraphy to be tracked as drilling progresses.
Total mud gas plots will also show a general correlation with wireline porosity logs, and can be used for interfield correlations while drilling is still in progress.
Total cuttings gas plots will closely correlate with SP logs where both are responding to changes in permeability. However, each has some response unrelated to permeability. Thus, a change in pore water salinity can alter and possibly invert SP response without effecting a change in cuttings gas concentration. Conversely, the presence of a low-gravity immobile oil can cause a sharp increase in cuttings gas. The response of the SP log to this occurrence will be small unless oil saturation is very high or the oil is so viscous and immobile that it causes a major permeability reduction.
Very usable correlations occur between total mud gas and shallow and deep resistivity and conductivity logs. Almost all porous rocks contain saline waters with dissolved gases, predominantly methane. Consequently, gas content and water content can closely track each other and porosity. Therefore, the mud gas total combustible hydrocarbon curve will generally correlate well with both shallow and deep conductivity logs and will be a reciprocal of the resistivity curve.
An approximate one-to-one correlation may not always occur between these logs and this also can be useful. When a zone of high hydrocarbon saturation is encountered, the gas curve will most probably increase with the increasing gas saturation. However, this need not be the case. If the mudcake has not built up effectively, mud flushing during drilling may result in the displacement of all hydrocarbons and a "negative gas show" at surface. In this situation, shallow conductivity logging will commonly see only the flushed zone around the borehole. Primarily sensing the mud filtrate, it will remain unaffected by the more distant, true gas saturation and give an unrelated response.
Deep conductivity logging, however, will respond primarily to the original, undisturbed hydrocarbon saturation and be unaffected by permeability and gas and oil mobility. Comparing the three curves can provide a quick-look evaluation of saturation and mobility.
Evaluation
As
presented at the beginning of this section, anomalies within a well are best recognized and evaluated after operational and lithologic variables are considered. Determining the validity of a gas show on the total combustible gas plot, for example, requires a number of adjustments. Specifically, the data should first be corrected for background influences and then normalized with respect to operational influences such as rate of penetration, bit diameter, rate of mud circulation, and gas trap extraction efficiency.
Background is generally established by inspection using the total combustible gas plot ( Figure 1 , Total combustible gas plot from chart recorder with diagnostic features noted). Based on the differences between zero gas points and running or visual averages of background gas, a true background is calculated for the depth at which the show occurred. This true background value is then subtracted from the show value to provide a "rough" quantification of the anomaly. The anomaly is now ready for normalization to give it a "reference" value for classification and comparison with other anomalies in the well or in nearby wells.
Normalization is necessary to remove operational influences that cannot be fully annotated on the gas log and thereby be interpreted out. Let us assume, as an example, that we drill into a porous and permeable zone. Such a zone will be physically weaker than the uphole section and we will recognize it by an increase in ROP, that is, a drilling break. If, after the appropriate lag time, we see an increase in total combustible hydrocarbon readings we might take this as a sign that the interpreted high-porosity zone is filled with gas and oil.
This need not be the case ( Figure 2 , Effect of change in ROP on mud gas detector response). An increase in gas will result, in part, simply from the higher ROP and greater pore volume drilled. We are crushing a larger volume of rock and liberating more gas within any increment of time.
An opposite effect will be seen when bit diameter is reduced, as at a casing point. A smaller volume of rock is crushed for each increment drilled following the bit-size change and, as a consequence, all gas shows will be reduced in magnitude to some degree below the casing point. Similarly, if mud flow rate is increased at any point, then the volume of formation fluid released during a show below that point will be mixed with a larger volume of drilling fluid. Consequently, the gas show will be more dispersed and give the appearance of being smaller than a comparable show occurring before the flow rate increase.
Some wellsite geologists are willing to accept these effects and work with raw data when evaluating a show. If operational variables have remained fairly consistent throughout the show interval, then a rough correction only for background may give a fair indication of the magnitude of the show.
This magnitude, however, will not necessarily be directly comparable to previous uphole or later downhole anomalies drilled under different conditions. Therefore, an increasing number of geologists prefer to work with normalized data. Normalizing can be done either by the geologist or as part of the mud-logging service.
Normalization is generally carried out by using the following mathematical scheme:
where:
Gn = "normalized" ditch total hydrocarbons, % EMA
Go = observed ditch total hydrocarbons, % EMA
Qo = observed drilling fluid pump output, m3/s
Qn = "normal" drilling fluid pump output, m3/s
Sn = "normal" drill bit diameter, m
Bo = actual drill bit diameter, m
Rn = "normal" ROP, m/s
Ro = observed ROP, m/s
Fen = "normal" extraction efficiency factor, dimensionless
Feo = observed extraction efficiency factor, dimensionless
The concept is simpler than the formula appears to indicate. Basically, if mud flow rate increases or bit size or ROP decreases, normalizing must have a positive effect on gas values to compensate for greater gas dilution and lesser ground-up rock. The opposite is true, of course, under inverse drilling changes.
The "extraction efficiency factor" in the formula above is a correction factor used to attempt to remove the effect of variations in gas trap efficiencies resulting from changes in such conditions as mud flow characteristics, mud chemistry, and ambient temperature. Its direction and magnitude can be approximated by comparing the results of cuttings gas values with mud gas values. It can also be estimated as the hole is drilled by monitoring changes in gas detector response to comparable amounts of acetylene lag gas.
When comparing a number of shows, "normal" values may be arbitrarily selected, but should remain the same throughout the normalization program for all shows and wells involved. It is recommended that normal values be chosen that are typical of those encountered when drilling the particular stratigraphic section under evaluation. If this is done, the eventual normalized gas magnitudes will not vary far from their observed values. In this way, they will be more readily understood and accepted by personnel already working in the district but who may be unfamiliar with normalizing techniques.
Another method of normalizing data that is commonly used when hydrocarbon data are evaluated is to make comparisons or ratios between the concentrations of specific hydrocarbon compounds within one sample — that is, measured during one single gas analysis. This normalizing process equates all values within one batch sample to 100%. The resulting ratios that can be established between compounds are independent of the total concentration measured and, therefore, relatively free of sampling and similar variables.
An easy way to visualize this normalizing effect is to imagine diluting a gas sample with different volumes of air or dissipating it into different volumes of mud. Although the absolute concentrations of hydrocarbon gas will drop proportionately to the dispersion, and thereby give a lower total reading, indicating greater dilution or dissipation, the relative concentrations, or ratios, between hydrocarbon compounds within each sample will remain the same. All compounds, in other words, are dispersed by the same amount.
Ratio normalization finds most use in evaluation of mud gas and cuttings gas data from chromatographic analysis. The hydrocarbon ratios obtainable from detailed analysis can provide important clues to the composition of formation fluids giving the show.
Because hydrocarbons have common origins in carbonaceous matter and are relatively soluble in each other, we should expect the liberated gas in a gas show to be of the same origin as the range of hydrocarbons in the show interval as well as reflective of their nature. Experience has shown this to be true; in particular, different hydrocarbon ratios in mud gas and cuttings gas can strongly reflect different compositions of companion fluids at depth ( Figure 3 , Show evaluation scheme using mud-gas compound ratios to interpret show potential).
Mud-logging companies have a variety of methods for interpreting and plotting show and probable reservoir relationships. Several rule-of-thumb guides are applied in most interpretations and evaluations:
Where gas ratios favor the lighter components — methane and ethane — reservoir lithologies are most apt to contain a light fluid — gas and/or condensate.
Where gas ratios favor the heavier gases — propane and butanes — reservoir lithologies are more apt to contain heavier fluid — crude oil.
At either extreme — all methane (dry gas) or predominantly butanes (very wet gas) — reservoir lithologies are probably going to have unfavorable petroleum characteristics. The former implies an immature, possibly biogenic gas, probably of low volume, or simply a water reservoir with dissolved methane. The latter suggests either heavy immature oil or residual oil from which all of the light, more mobile components have migrated.
Where data are adequate, comparison of gas ratios can be used also to evaluate down hole changes between shows. They may also be used as drilling progresses to give early insight as to changes occurring between wells (e.g., oil-water contact versus gas cap).
Naturally, we must assume that the better the data, the better the interpretation. Steam-still and cuttings-gas extractors generally provide better gas samples for the above types of interpretation than the gas trap at the mud tank.
The principal limitation of ratio normalizing for show evaluation is the fact that analytical data for individual hydrocarbon components must be available. Because these come mostly from intermittent or batch analyses, a reliable number may not exist for each show, particularly if sampling frequency is the same for cuttings gas as for lithologic description (e.g., the ten- to thirty-foot range). For this reason, it is good practice to require short-interval cuttings and mud sampling throughout a show, with cuttings and mud gas extraction and detailed analyses run as rapidly as possible.
Exercise 1.
Contrast the following:
a. liberated gas versus produced gas
b. influx versus flushing
c. lag time versus lag strokes
d. hydrocarbon gas versus nonhydrocarbon gas
e. mud gas versus cuttings gas
f. Catalytic combustion detection versus thermal conductivity detection
g. dry gas versus wet gas
h. % EMA vs ppm
i. connection gas versus lag gas
j. gas show versus gas feed-in
Solution 1:
a. The first is liberated by the bit, the second influxes from uphole.
b. The first is formation fluids entering the hole (or mud), generally from mud under-balance; the second is the result of mud fluids entering the drilled formation, generally from mud overbalance.
c. Lag time is that taken for cuttings to come up the annulus; lag strokes are the pump strokes required to bring cuttings to surface. (Chronologic time can be highly variable due to noncirculation, e.g., during connections, but pump strokes will remain relatively constant for mud return to surface.)
d. Hydrocarbon gases consist of molecules containing atoms of hydrogen and carbon only; any gas containing any other atom is a nonhydrocarbon gas, even if it also contains hydrogen and carbon.
e. Mud gases are extracted from mud; cuttings gases from cuttings.
f. Catalytic combustion detection depends upon the heating effect of combustible gas on a heated wire; thermal conductivity detection is dependent upon the cooling effect of any gas on a heated wire.
g. Dry gas is relatively pure methane gas; wet is methane gas mixed with ethane, propane, and butane.
h. % EMA is the gas measurement relative to response equivalent to that given by a known concentration of methane; ppm is the gas volume of individual gas related to entire gas sample.
i. Connection gas is formation gas entering the mud system at depth while a connection is made; lag gas is contaminant gas introduced at surface to measure mud system circulation cycle.
j. A gas show is a relatively short-term influx of gas (its appearance should signify penetration of a gas-bearing horizon); gas feed-in connotes a long-term influx of gas (commonly due to inadequate mud overbalance).
Exercise 2.
Explain why lag strokes determined by tracer test and mathematical calculation need not agree, as well as what application the difference between the two can have.
Solution 2:
The tracer test is an accurate physical measurement of the number of pump strokes required for mud to make one complete circulation down the drill pipe and up the annulus.
Calculated lag is the theoretical number of strokes required to move a theoretical volume of mud through the same system. The latter cannot take fully into account hole-size variations, pump efficiency, and similar variables.
The difference between the lag strokes (volume of mud) determined by the two methods can be used to evaluate hole conditions and some equipment efficiencies.
Exercise 3.
a. Why is total combustible mud gas measured in % EMA for the formation log instead of ppm or some similar, more precise method?
b. Why is mud gas analyzed by gas chromatography not a continuous measurement of gas composition?
Solution 3:
a. Each individual hydrocarbon gas (methane, ethane, etc.) gives off a different response to commonly used detectors. No discrimination can be made because changes in both concentration and composition produce changes in response.
b. Gas chromatography requires time to separate one sample into its individual components. No separation would be achieved with continuous sample injection.
D.5. Supplemental Logging Techniques and Applications
Formation Pressure Evaluation
Pressure evaluation draws from and builds upon many data sources used during conventional mud logging. Formation log parameters typically used include changes in ROP, cuttings character, total mud gas, and shale density. Pressure evaluation also looks at supplemental information such as changes in clay ionization, mud over-balance, and mud temperature differential. We now look at how such data are used in combination to interpret changes in formation fluid pressures at depth.
Geopressure Evaluation Concept
Vertical progression from a normally pressured section into an overpressured or geopressured interval is accompanied by a number of changes that break or reverse normal gradients or patterns. In general, these changes can be recognized as discontinuities in uniform depth-and/or age-controlled trends. For example:
Compaction Trend — a uniform depth-controlled density gradient may be halted or reversed
Porosity and Water Content Trends — both pore-water and matrix-water content in clay minerals may remain constant with depth or may show sudden reversals
Physical Property Trends — rock characteristics such as electrical and thermal conductivities may show dislocations
Fluid Property Trends — characteristics related to fluid migration may be modified by the absence of flow pathways
Drilling into an overpressured zone can also result in —
Change in Penetration Rate and Cuttings Characteristics — improved drillability in response to reduction of differential pressure at bit/rock interface;
Loss of Mud Overbalance — increased mud gas influx due to decline in borehole/formation differential pressure.
Any measurable parameter that reflects or responds to any of these trends and features can be used as a pressure evaluation tool.
ROP and Cuttings Parameters
ROP curve patterns combined with cuttings observations provide some parameters initially used in formation pressure evaluation. Drilling into a geopressured shale will be accompanied by a progressive increase in penetration rate and volume of cavings returning to surface. This is due to the progressive loss of bit face "hold-down" differential that accompanies the decline in mud weight overbalance relative to formation pressure. The drill-off trend will appear on the ROP curve. Cuttings will begin to show a cleaner, fresher appearance. This may cause them to look like cavings; however, they will be smaller in size. Such cuttings characteristics should be noted on the right-hand descriptive portion of the formation log.
Mud Gas Parameters
If a geopressured horizon is penetrated without increase of mud density, there will be a progressive transition from mud overbalance to underbalance. ( Figure 1 , Effect of mud weight on gas show as drill penetrates an overpressured zone. If mud weight is not increased so that a constant overbalance in maintained, gas feed-in will occur) demonstrates the effect by comparing the gas curves from two wells in the same basin. Well A was drilled with mud density held constant; Well B was drilled with regular increases in mud density so that overbalance was maintained.
In the normally pressured upper section, both gas curves, after normalization, are similar. In the lower part of the section, where geopressure is encountered, Well A shows a progressive influx or "feed-in" of gas and connection gases resulting from the loss of overbalance. Such systematic changes in continuous gas plots are diagnostic parameters that have been used in formation pressure evaluation since its inception.
Shale Bulk Density
Under normal pressure conditions, shale bulk density increases with depth as water content declines through the first compaction dewatering phase. If a high enough subsurface temperature is reached, mixed layer clays pass through the second diagenetic phase. Any deviation from either of the two projected normal decline profiles can indicate that dewatering has been halted and overpressure is present. In other words, density is lower than expected because fluid within the pore space has not escaped and is under abnormally high pressure.
When density data are plotted against depth ( Figure 2 , Shale density compaction trend across a normally pressured and overpressured zone), a normal compaction trend should be recognizable. Deviations from this trend (after consideration of geologic and lithologic variations) are indications of a pressure transition zone ( Figure 3 , Examples of various shale density plots reflecting changing downhole conditions). Remember, however, that density variations indicating overpressure may be subtle. An interval of constant density or a decrease in the rate of density change can reflect a significant pore pressure gradient increase.
Several simple wellsite methods are now incorporated in formation logging to determine cuttings density. The most common of these make physical measurements based on either weight/volume calculations or on equilibrium with fluids of different densities. All methods result in density values that can be plotted directly on the formation log.
Mercury Pump Method
This method uses the difference in amount of mercury pumped into the sample vessel when empty and the amount when the vessel contains a weighed quantity of dry, clean cuttings. The mercury is placed under pressure so that air in the cuttings is compressed and nearly true (dense) volume of cuttings sample is being measured. Density of the cuttings is determined by dividing cuttings sample weight in grams by mercury volume displaced in cubic centimeters.
The principal potential sources of error in this method arise from the need to select cuttings that are representative and to clean and dry each batch uniformly.
Mud Balance Method
This method applies Archimedes' principle, using weight change and displacement. In this procedure, clean cuttings are loaded into the mud balance cup ( Figure 4 , Mud balance capable of determining density of shale cuttings) with the scale set at a value of 1000 kg/m3 (8.34 lb/gal) until a balance is reached (with the lid on the cup). The cup is then filled with fresh water, the cap replaced, and the balance reset. Using the new scale reading (W2), the cutting's density may be calculated by the following equation:
where:
WO = density of fresh water, 8.34 lb/gal, or 1000 kg/m3
W1 = constant, 16.68 lb/gal, or 2000 kg/m3
W2 = new scale reading, cuttings plus fresh water
The principal sources of error in this method, as with the mercury pump method, are in the need to select representative sets of samples and to dry each set uniformly.
Density Comparison Method
In this method, the density of cuttings is measured by suspending them in various fluids and finding the one in which particles are in equilibrium (neither sinking nor floating). For determining shale density at the wellsite, mud loggers generally use a series of solutions of tetrabromoethane (a dense liquid that provides a safe alternative to bromoform) in an organic solvent such as chlorethene or trichlorethene. Systematic changes in solution concentrations provide a systematic sequence of densities for comparative purposes.
The principal problems with this method are evaporation of the volatile liquids, contamination by moving cuttings from one mixture to the next, and the noxious vapors given off by the liquids.
Density Gradient Method
In this method, a clear, graduated cylinder is used in which a continuum has been established between two fluids of different densities. For most formation logging applications, tetrabromoethane and chlorethene are mixed to form a density gradient — densest at the bottom, lightest at the top. Beads of known density are dropped into the cylinder; these settle to positions of equilibrium providing a calibration scale that is equated to graduations on the cylinder wall.
Subsequently, shale cuttings from regular sample intervals are set into the column, where they sink to a depth of liquid of the same density. Shale bulk densities are then determined by reading the adjacent graduations and calibration chart. In some cases density beads are left in the column to act as reference points should the solution be disturbed by normal mud-logging activities.
The principal sources of error here are in judgment of equilibrium (density) position, overdrying of samples so they absorb column liquid denser than water, and the need to recalibrate because of temperature changes in the liquid mixture.
Shale Factor
When clay undergoes dehydration and diagenesis during compaction, smectite laminae, which have a high cation exchange capacity, are progressively converted to illite, which has a very low exchange capacity. This systematic reduction in cation exchange capacity is the basis for estimating the compaction gradient; however, the capability to measure changes accurately under field conditions is often questioned.
In cation exchange, electrostatically charged surfaces of clay laminae weakly bind metallic cations. In contact with saline pore waters, cations can be exchanged between clay surfaces and the solution. The number of cations exchanged is a measure of the surface activity or the composition of the clay.
Cation exchange capacity, commonly called the shale factor, is determined by titration with a metal-organic dye, methylene blue. This determination may be referred to as the MBT, for methylene blue test. Shale factor is expressed in milliequivalents per hundred grams of clay ( Figure 5 , Clay mineralogy change with depth, Norwegian Well 2/11-1, and Figure 6 , Cation exchange capacity variation with depth). By measuring and plotting cation exchange capacity against depth it is possible to monitor the clay diagenesis gradient. The increase in geothermal gradient in the transition zone results in an increase in clay dehydration rate and a corresponding conversion from smectite to illite clay.
The principal limitations of cation exchange measurements lie in the selection of representative cuttings samples, the removal of all drilling mud, the ability of the MBT to measure total exchange capacity, the possible absorption of methylene blue on nonclay surfaces, and the ability of the on-site analyst to make consistent, repetitive determinations. Shale factor MBT plots, therefore, are often used subjectively and interpreted in conjunction with density plots.
Differential Mud Temperature
Geothermal gradient is a function of the thermal conductivity of the rocks through which heat is flowing to surface. Although all rock matrix materials have different thermal conductivities, there is a much greater difference between lithic materials and the very low conductivities of pore fluids — gas, oil, and water. Consequently, thermal conductivity and geothermal gradient will reflect porosity and progressive changes in porosity due to compaction and depth.
A zone of high pore pressure within a normally pressured section will constitute a relatively high-porosity thermal resistor that will cause a "jog" in the geothermal gradient ( Figure 7 , A cahnge in geothermal gradient resluts fron insulating effect of fluids entrapped in overpressured interval). This will be seen as an increased gradient within the zone and a decreased gradient for a short distance above and possibly below the zone. It has been suggested that the decreased gradient above the abnormally pressured zone may be due in part to the higher density "cap" found above some over-pressured zones, or may be the result of more mobile gas escaping the over-pressured interval, expanding, and cooling the adjoining rocks.
During drilling, estimates of downhole geothermal gradient are developed from mud temperatures ( Figure 8 , A mud flowline temperature plot can reflect the presence of overpressure as do cuttings parameters). Circulating mud carries heat away from the borehole. The rapid circulation of mud prevents it from equilibrating fully to the temperatures of the deepest formations. However, the temperature of a mud of uniform properties, circulating at a uniform rate, will exhibit a temperature at the surface flow line that is responding to bottomhole temperature and will change proportionately to it. In some cases, downhole changes in compaction trend, such as in the transition zone from normal to abnormal pressures, are directly recognizable in flow line temperatures.
In practice, however, neither mud properties nor circulation rates are ever entirely uniform; also, temperature changes occurring in mud pits at surface will affect the eventual temperature reached in the borehole. To diminish these problems, a dual thermistor probe system is commonly used. This measures the temperature of mud entering and leaving the borehole. Temperatures are lagged downward to the bit and upward to the flow line and a differential temperature calculated and plotted against depth ( Figure 9 , A method of developing geothermal gradient and bottomhole temperature by using drilling-mud temperature readings). Using this method, most surface and circulation variables can be removed and a smooth trend-with-depth curve plotted. Only after pipe trips out of and back into the hole are there shifts in the data trend that cannot be removed in this manner. For basic geopressure recognition, then, a simple comparison of projected mud temperature trend with measured trend can indicate the presence of an overpressure transition zone.
Operational Effects
Several factors related to drilling can also be used when evaluating the possible presence of over-pressure. Although they are not plotted on the formation log, these factors can be included descriptively in its right-hand track. They include:
increased torque on the drillstring as a consequence of additional cuttings coming off bottom;
increased drag on the drillstring while making a connection as a result of more cuttings in the mud system;
decreased replacement mud during a trip as a result of increased hole fill-up from feed-in or hole collapse;
decreased mud weight that is unexplained except by dilution with formation water;
increased concentration of titrated chloride ion in drilling mud that accompanies mud underbalance as drilling penetrates an overpressure transition zone.
And, of course, there are also the at-surface indications that are measurable when an overpressured zone is penetrated, mud overbalance is lost, and a well kick is initiated. In particular, there is the increase in mud volume in the tanks or pits. This final indication should be picked up immediately by the mud-flow-and-pit-sensor system. In such cases, an alarm should automatically sound so that emergency procedures can begin.
Presentation of Geopressure Data
In pressure evaluation, data must be available immediately. Detection of declining overbalance is of little value if the information is not available until after the well has become underbalanced and a well kick has occurred.
A number of parameters that depict influences of downhole pressure are plotted as part of the standard formation log. However, to combine these parameters and trends for pressure evaluation it is customary for mud-logging personnel to produce separate plots and logs of pressure parameters, such as shale bulk density and differential flow line temperature. If calculations such as d-exponent have been made as part of advanced logging services, these also can be plotted. A final summary log containing estimated pore pressure and other results also is normally prepared and can be added as a pigtail log to the formation log. In addition, an "event report," similar to that used in reporting shows, can be required during routine formation logging for special reporting of overpressure conditions.
If wireline logs are available, pressure, porosity, and conductivity response data may be replotted in similar formats and scales to allow correlation with mud-logging pressure logs.
Extended Geochemical Analyses
Refined versions of routine mud-logging gas analysis have been performed in geochemical laboratories for many years. In addition, other analytical techniques exist that further expand the potential application of mud gas and cuttings geochemical analyses. Typically, these more complex geochemical analyses have been performed far from the wellsite in central laboratories. This was necessary to provide the stable operating conditions and cost effectiveness required in the use of sensitive, expensive instruments.
Improvements made in instrument design and microprocessor controls since the 1970s now permit a broader range of exploration geochemistry analyses and screening programs to be performed at the wellsite.
Recent Adaptations
Many additions (e.g., gas chromatographic separators for more discriminating mud and cuttings gas analysis) have been routinely incorporated into traditional formation logging procedures. In other cases, such capabilities as pyroanalyzers and extended-range hydrocarbon analyzers have been added to a few mud-logging units to provide advanced geochemical services. It is also possible, with the proper mud-logging arrangements, to obtain a broad-range hydrocarbon analysis of drillstem test fluids at the wellsite, or to make chemical analyses of pore waters for dissolved ions. In this latter case, tritium and nitrate tracers can also be identified, so that true pore water and mud filtrate water can be distinguished.
Pyrolysis
Pyrolysis, as practiced during routine geochemical analysis, is a progressive heating and gasification process. During pyrolysis, no oxygen is present, so that combustion of organic matter in the sample is inhibited. When samples such as fresh, finely ground well cuttings are used, the analysis generally encompasses four processes.
1. Gases are driven off and carried to a gas detector.
2. Heavier liquids are volatilized to travel in the gas phase to the detector.
3. Portions of the organic matter in the sample are thermally "cracked" into hydrocarbon fragments, volatilized, and carried to the detector.
4. Organic matter is broken down so that carbon dioxide is liberated, trapped, and subsequently routed to a detector.
The basic output from pyroanalyzers is a pyrogram. The analytical data plotted on this chart appear roughly as a series of broad peaks or surges ( Figure 1 , Note conventional terminology and assumptions applied to the peaks). These are given sequential "S" designations, although some instruments may combine surges or omit their collections.
S0 — Gases liberated by initial low-temperature heating. These are considered to be free, or indigenous, gas and very light liquid hydrocarbons contained in the sample in its natural setting. (Where S0 is critical to an analysis, special handling to keep free gases in the sample may be needed. This is one advantage of a wellsite location for pyrolysis.)
S1 — Gases liberated due to increase of temperature to baseline or operating level. These are considered to be from heavier-range petroleum (liquid hydrocarbon and related nonhydrocarbon [asphaltic] compounds) indigenous to the sample. (When no S0 is provided by a particular instrument, S1 generally includes whatever S0 is liberated from the sample.)
S2 — Gases liberated during the intermediate portion of progressive temperature increase. These are considered to represent the broad range of petroleum-like products (both gas and liquid hydrocarbons and asphaltics) generated from organic matter in the sample.
S3 — Gases liberated during the heating cycle, mostly carbon dioxide, resulting from the breakdown of oxygen-bearing portions of organic matter.
S4 — Gases liberated during very high-temperature heating in the presence of oxygen. This is mostly carbon dioxide resulting from combustion of organic matter. (This peak is attained by only a few pyroanalyzers, which introduce oxygen to the system at very high temperatures; when it is recorded, it may also include S3.)
An additional measurement, Tmax, is also taken from the pyrogram. It represents the temperature at which S2 gas liberation (or petroleum-like generation) was maximum ( Figure 1 ).
Guidelines for the evaluation of analytical results for screening and interpretation generally follow the pattern ( Figure 2 , Example of a pyrolysis data plot with typical interpretations of values and ratios).
S0 through S2 compared to S3 and/or S4 is a measure of overall source potential of the sample
S0 and S1 compared to S2 is a measure of the degree of hydrocarbon development or maturation (often called productivity index or transformation index) of the sample
S2 compared to S3 is an evaluation of oil-prone, gas-prone, or nongenerative source character of the organic matter in the sample
Tmax compared to a fixed temperature range of approximately 430º to 470º F indicates immature (<430º), mature, or postmature (>470º) thermal alteration of organic matter
Disproportionately high contents of S1 can indicate migrated or reservoir petroleum
Because some differences occur between analytical instruments and data gathered, comparisons and relationships can vary slightly among the S peaks.
When a sequence of pyrolysis analyses is run on samples in well profile, maturation patterns and source variations can generally be plotted. This is useful both for geochemical source rock interpretation and for screening for subsequent detailed analysis. In some facilities, it also is feasible to separate and analyze for individual hydrocarbon compounds within peaks S1 and S2 through gas chromatography. These results can also be evaluated for source character and maturation level.
Nonhydrocarbon Gas Monitoring
We use the topic nonhydrocarbon gas monitoring as opposed to nonhydrocarbon gas logging for a specific reason. The main emphasis of much of this type of on-site work is to recognize when these gases appear in the mud system, rather than to plot continual variations in their content. This is because the mere presence of some gases can be harmful or dangerous to personnel on the rig floor or detrimental to drilling equipment. Also, the presence of any noncombustible gas will decrease the economic value of petroleum in a reservoir. By monitoring the mud system and recognizing when an undesirable gas first appears, it is often possible to initiate steps that can reduce its presence (e.g., casing off) or neutralize its effects (e.g., treating the mud) before a critical situation develops.
Properties and Occurrences
The nonhydrocarbon gases most commonly encountered in exploration drilling are:
hydrogen H2
helium He
nitrogen N2
carbon dioxide CO2
hydrogen sulfide H2S
Hydrogen is extremely reactive and active. It is highly combustible (remember the Von Hindenburg zeppelin; 2H2 + O2 2H20 + lots of heat) and diffuses readily, even through rocks of low permeability. Its natural occurrence in significant quantities is rare and usually associated with deep-seated structures.
Helium and nitrogen may occur in significant amounts in mud gas, although, like hydrogen, their occurrences are rare and generally restricted to a few geographic areas. Helium accumulations may have economic importance. Nitrogen, in direct proportion to its concentration, serves only to dilute and reduce the thermal quality of hydrocarbon gas accumulations.
Carbon dioxide and hydrogen sulfide like natural gas and crude oil, are natural products of biogenic and thermogenic alteration of buried organic debris. Therefore, they can be common components of petroleum accumulations. Their presence in the mud system, however, can result in degradation of drilling equipment (e.g., embrittlement, etching, corrosion) and be hazardous to personnel (e.g., brain damage, asphyxiation). Early detection and treatment of hydrogen sulfide is particularly essential to the safety of rig personnel.
As with nitrogen, determining both carbon dioxide and hydrogen sulfide concentrations is a critical part of the economic evaluation of a commercial petroleum reservoir. Their presence also can have strong impact on "downstream" refining and petrochemical decisions.
General Characteristics
Hydrogen is close to methane in many physical properties, and, therefore, the two gases may be inadvertently detected by the same technique. This can give an anomalously high "methane" reading. Catalytic combustion and thermal conductivity detectors, in particular, can give this summation effect in total gas measurements. The flame ionization detector, however, ignores hydrogen gas because this gas does not ionize when burned. (That is why hydrogen gas can be used as the combustion source in flame ionization detection.)
Helium is chemically inert and nitrogen is generally nonreactive in natural occurrences. Both are poorly soluble in either formation water or oil. When contained in the mud stream, they are readily released at surface in the gas trap. As noncombustible gases, they produce no response on either the catalytic combustion or the flame ionization detectors common to formation logging.
Carbon dioxide and hydrogen sulfide have somewhat different chemical properties from helium and nitrogen. In addition, their solubilities are the opposite of hydrocarbons. They have very low solubility in oil and, therefore, are readily evolved from oil-bearing pore fluids and released from oil-base drilling muds. Conversely, they are very soluble in water and ionize to form corrosive acid solutions in water-base drilling muds.
These acidic solutions are hazardous to drilling operations for two reasons:
1. Concentrations can accumulate progressively and be present for long periods of time in water-base mud systems before saturation is reached and detectable gas is liberated at the gas trap. These high concentrations will lower the acidity (pH) of the mud and do damage to its stability. And, as was indicated, their presence also can lead rapidly to hydrogen embrittlement and corrosion damage to the drillstring, casing, and other steel components in the mud system.
2. Particularly in the case of hydrogen sulfide, the dissolved gas poses a potential toxic hazard to personnel working at the wellsite ( Figure 1 , Hydrogen sulfide toxicity chart), even though it is not present in the air. This is because the mud can become totally saturated before gas will be evolved either at the gas trap or from mud at surface. In this situation, large amounts can be released rapidly with a change in mud conditions or an addition of more gas from depth.
Nonhydrocarbon gases are both combustible and noncombustible, and therefore some of the detector techniques used in combustible gas logging are not applicable to all of the nonhydrocarbon gases. Like helium and nitrogen, carbon dioxide is not amenable to detection by catalytic combustion or flame ionization detectors. In fact, this lack of significant response to the noncombustible gases is a major advantage of the use of these detectors in formation logging. Remember, however, that their inability to sense these gases also has its drawbacks; some nonhydrocarbon gases may rapidly degrade the sensitivity of catalytic surfaces and adversely affect detectors using them.
Because nonhydrocarbon gases are in mixtures in the mud gas, they normally require some sort of separation to be identified just as individual hydrocarbon gases must be separated before they can be identified and quantified. One method is to use a detector combined with a separator; another is to use a detector that is sensitive to only one compound; still another is to use a chemical reaction that is specific to one gas.
The most common wellsite instruments applying these methods for isolating and monitoring nonhydrocarbon gases in
air are infrared analyzers, gas chromatograph/ thermal conductivity detectors, dry chemical indicators, and electronic sensors. Methods generally used for detecting nonhydrocarbon gases dissolved in mud involve laboratory wet chemistry, a procedure not readily handled under well-site conditions. However, there is a mud-pit apparatus, the mud duck, that uses ion-selective electrodes.
Detection in Air
Infrared detection is most commonly used in mud logging for monitoring carbon dioxide in mud gas. Its output, as previously described, can be routed to electrical meters, chart plotters, computer storage, and audio signals.
A gas chromatograph equipped with a thermal conductivity detector is a versatile general purpose gas detector. The detection process does not require combustion or the completion of any particular chemical reaction in order to function. The normal wellsite configuration is to use (1) a chromatographic column designed to separate the desired gases in the mud gas mixture and (2) a carrier gas that has a sufficiently different thermal conductivity from the separated gases to cause no interference or loss of sensitivity.
For example, to detect hydrogen, with its high thermal conductivity, argon is used as the carrier; conversely, to detect carbon dioxide, helium would be used as the carrier ( Figure 2 , Properties of mud gases, particularly as related to themal conductivity detectors).
As with most thermal conductivity detectors, output can be in many forms. Where monitoring is carried out repetitively at the wellsite, a gas log or plot may be the final product.
Dry chemical indicators that use lead acetate and hydrazine are common well-site detectors for hydrogen sulfide and carbon dioxide gases, respectively. If we use hydrogen sulfide gas as our example, the basic chemical detector ( Figure 3 , Hand-operated tubular gas detector used to detect the presence of specific gases in the atmosphere) consists of a glass tube containing lead acetate precipitated onto a substrate of porous silica. During monitoring, a controlled volume of gas sample is drawn through the detector tube, either manually, using a hand pump, or automatically, using an electrical pump and a timer. The white crystalline lead acetate reacts rapidly with hydrogen sulfide to produce brownish-black lead sulfide by the following reaction:
(CH3COO)2Pb + H2S 2(CH3COOH) + PbS
The reaction and its discoloration proceed from the inlet end along the tube in direct proportion to the quantity of hydrogen sulfide present in the sample. Therefore, for a known volume of gas sample drawn through the system, the tube can be graduated in terms of hydrogen sulfide concentration.
It should be apparent that systems using tubular-type dry chemical indicators have no automated output. When a reaction occurs, it must be estimated visually and recorded or plotted by hand. The pump system, however, is very portable and samples can be taken at any critical location at the wellsite. This portability makes the gas passage or tubular type of device a simple and reliable means for detecting or confirming first release of hydrogen sulfide from drilling mud or for monitoring work and evacuation sites during an emergency. However, to maintain a continuous record of gas concentration, it is necessary to continuously replace and reload detector tubes.
Although it is not a mud-logging function, we would like to note that personal hydrogen sulfide monitors, using the lead acetate reaction, are available and can be worn by rig personnel. These paper and granule detectors are exposed to the air at all times and discolor if hydrogen sulfide is present in the work area.
A more conveniently operated, though more complex, version of the tubular dry chemical indicator uses paper tape coated with lead acetate. The device resembles a tape recorder with the tape running slowly from one reel to another. Between the two reels the tape passes through a gas-flow cell where it is exposed to the sample gas stream. The tape then passes by a light source and photocell that quantitatively measure the degree of discoloration of the tape. This version gives a continuous measure of changing hydrogen sulfide concentration and its output can provide a permanent record. However, the sensing process involves a complex and delicate mechanism that is not really suitable for rough wellsite conditions.
Some electronic sensor detectors are also specific to hydrogen sulfide. This monitoring depends upon the reversible reduction of metallic oxides to sulfides in proportion to the amount of hydrogen sulfide in the atmosphere surrounding them. The reaction follows the general path
(Metal)O + H2S (Metal)S + H20
(Metal)S + O2 (Metal)O + SO2
The detector consists of a gas-flow cell containing a conductive element made up of a mixture of metallic oxides (the exact composition is proprietary to the manufacturer). The oxidation reaction is precisely and rapidly reversible, so that at any specific time the chemical Composition of the element — its sulfide/oxide ratio — is governed by the sulfide/oxygen ratio of the gas sample flowing over it.
Electrical conductivity of the element changes in a similar manner with the chemical composition, providing a simple electrical means of monitoring and displaying hydrogen sulfide concentration.
Monitors using electronic sensors are rugged and compact with one detector per monitor. A console may be installed in the mud-logging unit to sample mud gas coming from the gas trap and at various locations around the rig for safety monitoring ( Figure 4 , Hydrogen sulfide monitors and schematic of detector system).
Detection in Mud
None of the detectors that monitor gases, though reliable, solves the major problem inherent with acidic hydrogen sulfide and carbon dioxide — they dissolve readily in water-base drilling fluids and, therefore, cannot be detected by gas analyzers on their first occurrence.
Various types of chemical analysis — for example, titration for pH, sulfide, or carbonate concentration — can be used to detect the presence of dissolved acid gases. However, these analyses are time-consuming. In addition, mud-logging experience has shown that such analyses generally cannot be performed regularly or consistently enough using a standard formation logging crew to monitor continuously changing downhole and mud conditions.
To resolve this problem, a number of mud-logging companies now provide a device called a mud duck to continuously monitor hydrogen sulfide ( Figure 5 , Muc duck hydrogen sulfide monitor). This device uses electrode probes immersed in the drilling mud to sense mud properties electrochemically.
Using three separate electrodes, the mud duck can measure the mud acidity, the concentration of hydrosulfide ion in solution, and the temperature of the mud. With these three measurements and a knowledge of the interdependent ionization and solution characteristics of hydrogen sulfide, it is possible to calculate the concentration of all forms of the compound and its ions.
The principal forms quantified by the mud duck are hydrogen sulfide in solution (H2S), hydrosulfide ion (HS-), and sulfide ion (S=) ( Figure 6 , Example of a hydrogen sulfide well-profile plot based on mud duck data). In addition, it is possible to calculate the maximum potential hazard if all of the dissolved gas were to be instantly released to the atmosphere.
With mud duck usage, these calculations are performed simultaneously and continuously by a microprocessor. Displays and alarms in the logging unit show present and potential hazards.
Exercise 1.
What is balanced drilling?
Solution 1:
Balanced drilling is drilling with a minimum of mud weight overbalance relative to formation pressure.
Exercise 2.
What two major conditions must be kept in mind when raising mud weight while drilling into an overpressured interval? How do you generally resolve the problem?
Solution 2:
The mud weight must be kept high enough to counterbalance formation pressure at bottom of the hole; mud weight must be kept low enough not to damage formations in open hole above the over-pressured zone.
To resolve, set casing in the transition zone.
Exercise 3.
How do each of the following factors respond to effects of an overpressured zone?
a. bottomhole temperature
b. shale density
c. ROP
d. cuttings
e. connection gas
Solution 3:
In an overpressured zone
a. bottomhole temperature increases at higher rate (lower heat conductivity gives higher geothermal gradient in over-pressured interval);
b. shale density decreases relative to normal compaction (density) gradient;
c. ROP increases because of weaker mud "hold-down" differential and possibly greater porosity;
d. cuttings will probably get larger and fresher appearing;
e. connection gas increases if mud overbalance declines, but will show little effect if overbalance is maintained.
D.6. Advanced Mud Logging and Advisory Practices
Pressure Evaluation
The basic pressure-determination data plotted on formation logs are generally derived from physical measurements made at the wellsite. These include such parameters as ROP, shale and mud densities, and connection gas fluctuations. When mud-logging programs lock in more detail at pressure evaluation, they generally emphasize two aspects — mathematical treatment of drilling data for quantifying the effects of downhole pressure changes and integrated trend evaluation, in which a variety of surface and down hole parameters are mutually considered to obtain a "best fit" interpretation of true formation pressure conditions.
Mathematical Treatment
The common mathematical approach used by mud-logging companies in advanced pressure-evaluation programs is to remove the effects of such variables as rock type and bit condition from penetration rate so that anomalous drilling responses can be recognized and equated to pore pressure. This may be thought of as normalizing ROP to quantify overpressure in much the same manner that cuttings gas is normalized to quantify the magnitude of a show. Through usage, the mathematical variable obtained following such a normalization, or modeling, generally is referred to as the "d-exponent" (d, d-exp).
The d-exponent was first applied by Bingham (1965) to the empirical definition of the relationship between rock strength, work done by the drill bit, and ROP. This can be expressed in the general form
(1)
where:
R = penetration rate, ft/min
N = rotary speed, rpm
W = weight on bit, lb
D = diameter of bit, ft
K = matrix strength constant, dimensionless
d = formation drillability exponent, dimensionless
Drillability of rock at the bottom of the borehole is related to two factors, (1) rock strength and (2) confining stress supplied by drilling mud density — the overbalance.
Jordan and Shirley (1966) approximated a solution to Bingham's equation for a single unknown, the d-exponent, by eliminating variable K (assuming it to be constant as in a uniform shale). They also inserted constants in the equation to in-corporate American oilfield units of measurement.
(2)
where:
R = penetration rate, ft/h
N = rotary speed, rpm
W = weight on bit, lb
D = diameter of bit, inches
Other modifications or variations have been made by individual logging companies to the d-exponent for specific uses.
In a uniform lithology, with constant bit type and mud overbalance, the d-exponent will increase with increasing depth — that is, with increasing compaction or rock strength. Overall, it will have an inverse relation with ROP. A break or reversal in slope of this increasing d-exponent trend will be seen when overpressured zones are entered ( Figure 1 , General relationships between d-exponent, drill depth, mud column length and ROP while drilling through a uniform lithology with both normally pressured and overpressured intervals).
Unfortunately, d-exponent deviations will also result whenever overbalance is changed by varying mud density. Conversely, a deviation in d-exponent caused by a change in pore pressure will be exactly reversed if mud density is increased sufficiently to restore the original overbalance. This can be encountered routinely where mud density is very accurately controlled, as in a drilling optimization program.
Rehm and McClendon (1971) proposed a correction (dxc, dcs, dc) to the d-exponent that removes the effect of mud-density changes. Although without theoretical basis, there is much empirical evidence for the utility of this correction.
(3)
where:
dxc = mud density corrected d-exponent
d = d-exponent
(nfb) = normal pore fluid pressure gradient, lbs/gal
(ec) = actual drilling fluid effective circulating density, lbs/gal (which is dependent both on mud density and mud resistance to flow in the annulus)
The general value used in mud logging for (nfb) is 9.0. If the mud system is in good condition, (ec) is generally considered equivalent to mud weight (MW). Therefore, the approximation reads
(4)
After correction for mud weight, the dxc-exponent will respond predictably to pore pressure gradient. It is also at this point in advanced pressure-evaluation programs that the dxc-exponent is normally used to determine mud density requirements to regain mud overbalance. Determination of down hole pore pressure is made by use of a graphic plot ( Figure 2 , Example of graphic determination of downhole pore pressure and appropriate mud weights) or by mathematical calculations, applying the formula
(5)
where:
Ppa = actual pore pressure (or pore pressure gradient) at depth of interest
Ppn = normal formation pore pressure (or pore pressure gradient) at the same depth
dxcn = normal dxc value at the same depth
dxco = observed dxc value at the depth of interest
It is essential to point out that any mathematical treatment of subsurface pressure is relatively imprecise unless consistent balanced-drilling practices are used throughout the drilling phase. If excessive mud density is used, as an example, it is easy to see from equation 3 that an overly high pore pressure will be predicted because the denominator in the fraction is higher than should be. A comparably erroneous high pressure also will be predicted using mud with poor flow properties because of a large annular pressure loss. However, it is practical to recognize excessive mud density by cross plotting both d-exponents and dxc-exponents.
Remember that the dxc-exponent adjusts only for mud overbalance under one set of conditions; this is because it has been derived from the d-exponent (eq. 2). As has been stated, changes in such variables as lithology will be accompanied by changes in rock strength. Different bit types, bit conditions, or bit hydraulics will change drill bit efficiency. These variables will produce offsets to dxc-exponent plots ( Figure 2 ) unless they are continually incorporated in d-exponent normalization calculations as the bit extends the drillhole.
Integrated Trend Evaluation
Recognition of overpressure conditions by wellsite geologists and engineers can prove to be difficult in many situations where only a few measurements are available for evaluation, or where data prove to be contradictory. The task is further complicated by the need to make comparisons between continuous plots, such as ROP or shale density curves, and isolated events, such as hole sloughing or mud surges. Advanced mud-logging pressure-evaluation programs improve this situation by gathering more data, storing them for ready reference and trend projection, and weighing one variable against another to determine the most probable conditions at depth.
A set of parameters integrated into a pressure trend evaluation is generally selected from:
· Formation Log Data — ROP; depth; lithology; shale density; mud gas concentration and composition; connection and trip gas values; rotary speed and torque; weight and time on bit.
Mud System Data — mud properties; pump strokes; lag time; pit volume and level; system volume; circulating pressure; mud weight, flow rate, temperature, and chloride content in and out; resistivity.
Analytical and Observation Data — cation exchange capacity; calcimetry; cuttings size, shape, and volume over shaker; hole fillup on trips; drag on drill pipe.
Generated Data — d-exponent; lithology factor; pseudoresistivity, sonic, or conductivity logs.
Outside Data — regional fracture gradient; MWD or adjoining well wireline log trends (gamma ray, emissions increase with compaction; resistivity, resistance increases with compaction; density response increases with compaction; sonic, transit time decreases with compaction).
Mud-logging companies providing advanced pressure-evaluation services commonly select from these data and present them on specialized logs, plots, or tables. Typically, presentations are of two types, (1) working logs prepared continuously at the wellsite for quick recognition and response to changing downhole pressure conditions and (2) comprehensive logs prepared intermittently as wireline and other data become available for thorough formation pressure characterization.
Working logs typically include selections from such first-generation parameters as ROP; total combustible, connection, and trip gas; shale density and shale factor; mud weight and viscosity; flowline temperature or in-and-out differential; mud conductivity or in-and-out differential; estimated pore pressure based on shale density or dxc-exponent; and drill rig operating conditions.
The primary emphasis of working logs is to provide the operator with immediate indications of formation pressure conditions at bottomhole and, if necessary, to provide warning when overbalance is being lost and a well kick is possible. These logs find direct use in the selection of casing points and in determining the mud weights needed to maintain overbalance while still avoiding formation fracture damage. They can be used to project the hydrostatic head that will be needed during trips and to control kicks. The working log also can be used to determine if the well is drilling as projected from comprehensive logs based on adjoining wells and to decide when a deviation from the planned drilling program should be made.
Comprehensive logs are broader in nature and prepared intermittently as wider ranges of data become available. Typically included in this presentation will be selected parameters from the formation or working log, such as ROP, shale density, and cuttings gas; calculated data, such as drilling porosity or pseudo-density; plus outside information, such as pore pressure, permeability, and fracture gradient from offset logs, laboratory analysis, and regional studies.
Primary use of this more encompassing pressure log is for overall hole evaluation (e.g., pore pressure profile, rock drill strength, fault location), areal over-pressure characterization, and "next hole" planning ( Figure 3 , Stylized pressure evaluation comprehensive log used to plan an offset well).
Petrophysical Evaluation
Many data on formation logs are qualitative in nature and not capable of providing precise numerical measurements of such values as porosity, permeability, or fluid saturations. This is primarily because of the imprecise and contaminated condition of mud gases and cuttings samples available at the shale shaker.
However, there are occasions when reliable samples are available for petrophysical evaluation. For example, relatively pure samples of formation gas, oil, and water can be recovered through a drillstem test (DST). The data collected from the DST may be handled directly by some on-site computer facilities as part of well-test programs.
Less reliable, but still relatively pure subsurface samples will be available from cores. These are the preferred samples for determining rock mineralogy, structure, porosity, and permeability.
On-site core analysis cannot rival the services provided by a specialized core analysis laboratory. Wellsite evaluation, however, does offer the advantage of providing analytical results within hours of a core being cut. This, in turn, makes the data immediately available for incorporation into advanced logging programs.
In addition to conventional core analytical procedures available through mud-logging services at the wellsite, the pulsed nuclear magnetic analyzer (pNMR) technique provides accurate measurements of total and effective porosity and reliable estimates of permeability using very small fragments of core sample or even well cuttings. Several versions of this device are available, but the most practical model for wellsite use incorporates a microcomputer that automates the analytical procedure and the calculation of results. This minimizes operator time and increases the accuracy and repeatability of results.
As with all core analyses, only a small number of measurements can be made over the short interval of rock that has been cored. Even the pNMR method applied to sidewall cores or well cuttings typically provides intermittent readings at only three- to five-meter intervals. It is also difficult to correlate such results with wireline porosity measurements that are less accurate but consist of continuous measurements averaged or normalized over small depth or time increments.
An advanced mud-logging method is available to improve the usefulness of the intermittent pNMR porosity measurements. This involves using second-generation, extended drilling models related to the d-exponent but incorporating more variables and more complex relationships among them. This type of model also requires the use of automatic drilling data acquisition and processing at the wellsite. However, in addition to computing changes in pore pressure, it will compile rock strength variations resulting from changes in porosity.
The speed of automatic data acquisition allows this "drilling porosity" to be calculated at very small depth increments and to have a response similar to or more precise than the wireline logs. As a rock strength indicator, drilling porosity shows closest correlation with the sonic (interval transit time) porosity log. However, drilling porosity calculation can be integrated with measured porosities from pNMR analysis to yield very accurate, continuous logs of total porosity and effective porosity.
Only a few advanced mud-logging units are currently equipped to provide this level of service. Commonly, this petrophysical service will be combined with MWD logging services.
Systems-Monitoring and Data-Acquisition Services
With the advent of miniaturized sensors and on-site computer facilities, many rig systems and functions can be monitored routinely ( Figure 1 , Schematic of typical rig monitoring system). In addition, data can be formatted and stored systematically for recall or transmission to offsite locations. This permits the "pulse" of the drilling program to be taken nearly continuously and reviewed anywhere within a telecommunications network.
Wellsite Apparatus
In the following list, we summarize the operating variables that may be continually monitored by advanced mud-logging units. Some have specific application to offshore and/or measurement-while-drilling operations only; some may be fitted with automatic alarms to signal unsafe or unacceptable conditions.
Rig Operations — drill depth; hook load (with calculated weight on bit); rotary speed and torque; kelly height; rig heave; worksite gases (H2S, CO2).
Mud System — pump, standpipe, and casing pressure; pump strokes; mud weight, flow, temperature, and resistivity/conductivity in and out; total pit(s), active pit, and trip tank volume; H2S in solution (mud duck).
Mud Gas System — total combustible gas; wet gas; individual hydrocarbon gases; H2S, CO2, and H2 gases.
MWD Downhole System — hole direction (azimuth) and inclination (drift); tool-face orientation; gamma ray and resistivity properties; bottomhole temperature; bottomhole weight, force, and torque on bit.
Data from these various monitors, when handled mathematically by computer programs, immediately provide values for such wellsite operating conditions as ROP, time on bottom and bit; time off bottom; probable bit condition; neutral point in drillstring; wear on cable; total pump strokes; lag time down and up; mud loss, gain, or weight change; and water loss.
Accumulation of the data over time also permits determination of such averages, means, or trends as weight on bit versus drill rate; mud flow rate and volume change; bottomhole temperature, formation fluid salinity, and pore pressure gradients. It is also practical to develop such outputs as a simulated SP log.
Presentation and Transmission Networks
Computerized data in advanced mud-logging programs can be presented in the standard log formats and tables. They can also be summarized on status monitors or printed out at rig workstations. As mentioned, the presentation of data is no longer limited to the wellsite; transmission can be direct to headquarters and field office locations ( Figure 2 , Example of a telecommunications system used between a drill rig, offshore New Zealand, and an oil company's headquarters, Dallas, Texas) when telecommunication capabilities are available in the mud-logging unit.
Workstation and remote displays commonly present the following features:
Drilling Conditions — date and time; ROP; drill depth; rotary speed; torque; hook load; weight, feet, and time on bit; pump pressure; total mud volume; mud weight, temperature, and flow in/out; total cuttings gas, individual gases, background level, and last connection gas. Descriptive information like lithology can also be shown.
Trip Conditions — date, time, and projected completion time; hole depth and bit depth; stands done and stands to go; anticipated hook load and measured hook load; expected pit volume and measured pit volume; swab pressure; pipe volume.
Well-kill Conditions — date, time, and start time; total depth; pump strokes, mud flow in, and mud weight in; running chronology of kill-tabulating time (interval), pump strokes, casing pressure, and mud pit volume.
All such presentations of conditions can be monitored off-rig through telecommunication of data to compatible receivers. In addition, hard copies of data, program computations, and interpretive values can be obtained from printers located anywhere in the network.
Interactive Programs
Numerous programs are now available through the major mud-logging companies to make immediate use of drillsite data. Some programs, like drilling optimization, are broad-based; others, such as hydraulics analysis, are quite narrow in scope. In some cases, advisory programs are long term and function from well planning to total depth; others are called upon to handle intermittent or crisis situations. We list here examples of interactive programs that can be provided by advanced mud-logging units; a general summary is included in Table 1., below.
Table 1. Interactive Programs
Hydraulics Evaluation-Effective mud flow properties and mud flow rates are prime requisites for the efficient removal of drill cuttings from the borehole. Insufficient cleaning at bit face can reduce rate of penetration. Insufficient carrying capacity can cause cuttings to accumulate in the borehole and the drillstring to become trapped. Conversely, excessively rapid and turbulent mud flow will erode the mudcake and damage formations exposed in the borehole wall.
Interactive mud hydraulics programs monitor mud properties, flow rate, and other mud system variables to approximate pressure losses throughout the hole. Outputs commonly are in the form of calculated flow rates and jet sizes needed for optimum impact at the dill face and hydraulic horsepower. These are based on downhole simulations carried out by the program.
Hydraulic evaluation exemplifies operational advisory services that can be provided by advanced mud logging throughout the drilling life of the well.
Directional Control — Another advanced mud-logging advisory service that generally runs throughout the life of a well, or even a well platform, is directional control. During the drilling of a routine exploration well, mud loggers, although they do not take the measurements, generally record deviations and make simple calculations necessary to correct drill depth and formation tops to true vertical depth on conventional logs. Drilling on an offshore production platform presents a much more complex situation.
On a platform, most wells are drilled at high angles of deviation and at variable well paths from the rig. This means that more variables and constraints must be considered. For example, it is necessary to monitor the proximity of a drilling well to previously drilled wells and to plan a corrected well path to prevent intersection of well bores. Advanced mud-logging facilities perform the calculation and three-dimensional compilation functions required of such a situation by using routinely monitored operational data and input from directional surveys. In the case of MWD drilling, direction and inclination data are also provided by the mud-logging service. Output typically is in the form of horizontal and vertical plots (Figure 6.11) showing the relationship of the active well to completed wells.
Trip Monitoring — Despite hazards encountered as the drill bit extends the hole, many problems occur while tripping to replace the bit. Well kicks may occur because the borehole is not kept filled with drilling fluid, or swabbing with the drillstring may cause the influx of large volumes of pore fluids. Conversely, excessively overbalanced mud emplaced for a trip may stress a weak formation to the point of hydraulic fracture, resulting in the loss of drilling mud from the borehole.
Other serious problems that alter downhole conditions can develop at any point in the roundtrip operation. The drillstring may be pulled through or run into a crooked section of borehole — a dog leg; the string may encounter a section of hole in which clay swelling or accumulated cuttings have reduced the hole diameter — a bridge. Either can result in a slowdown or stoppage of the trip. This, in turn, permits more time for uncirculated mud in the hole to be modified by formation fluids. Worse, the drill-string can become stuck in the borehole and, if there is a weak point in the string, may break in the hole. In this case, numerous factors can affect downhole conditions before circulation is reestablished.
Trip-monitoring interactive programs are intermittent advisory programs generally designed to recognize trip problems before they become serious, rather than propose solutions to them after the damage is done. Typically a trip-monitoring wellsite program makes continuous or stand-by-stand comparisons between anticipated and measured values for such variables as hook load, swab and surge pressures, and mud fill-up. When actual conditions go out of bounds from projected conditions, the alarm is given and possible corrections simulated.
Casing Calculations — The running of casing is essentially a trip into the borehole with a "drillstring" that is larger and weaker than usual. All of the problems discussed above for trips apply to an even greater extent during casing operations. The importance of monitoring and sounding alarm is similarly increased.
During casing operations, casing programs draw on wellsite data acquisition and storage systems to calculate cement composition and volume and to monitor the placement and displacement of cement. This problem is similar to that addressed in the drilling hydraulics program and uses many of the same data sources.
Kill Analysis — Nothing and no one is perfect and despite the best planning and control, a well kick may occur and the well will have to be shut in. The interactive kill-analysis program is an example of an on-site, on-demand advisory service available through advanced mud logging.
The killing of a well involves the displacement of light mud and formation fluid from the borehole with denser drilling mud that is capable of controlling formation pressure and the further influx of formation fluid. Although the solution is a relatively simple problem in hydrostatics, the dynamics of the situation are such that quick and effective action must be taken before conditions are beyond control.
Historically, well-control worksheets used to calculate kill-mud density, flow rate, and circulating pressure have included a number of safety, or "overkill," factors allowing for error. In addition, the driller's control panel and the variable choke control panel were not always within sight of each other. Similarly, personnel working at the mud pit to raise mud density could be out of sight of both. All of these factors increased the possibility of formation damage or ineffective response.
The advanced mud-logging unit and kill-analysis program resolve a number of these problems. The unit provides a crisis center with visible displays of rig-operating parameters. As a well kill takes place, mud adjustments can be recommended almost immediately based on current data at hand. During the kill, a chronological record of the shut-in and displacement period is maintained and can be printed or displayed minute by minute or barrel by barrel. Using on-site computer hardware and kill-evaluation software, it also is possible to run simulations of different well-kill scenarios in order to test them for practical and theoretical validity before initiating remedial action.
Well-Test Evaluation — Decisions concerning whether to complete or abandon a well, where to perforate, or what production system to prepare for often must be made in a short period of time following well "TD." The DST is a common method used to measure downhole conditions for decision-making. To be of timely value, however, DST data must be processed rapidly. This is the purpose of the on-demand well-test evaluation programs available with some advanced logging services.
Data typically utilized are those from the DST combined with general down hole parameters obtained from the monitoring and storage systems. Evaluation can be performed on both oil and gas, and single-and multiple-rate buildup and drawdown tests. In the case of gas wells, on-site programs have the capability to evaluate interrelations of pressure, viscosity, and compressibility to provide Output in gas pseudopressures.
Drilling Optimization — Drilling models that are used to normalize all drilling factors and to determine pore pressure and porosity can be used in a reverse manner to effect drilling efficiency. Using a base of anticipated lithology, compaction profile, and planned casing points, it is practical to calculate the combinations of bit types, weights on bit, rotary speeds, and mud densities that are most likely to optimize drilling as the well is deepened-that is, the combinations that will cause the well to be drilled at the overall minimum cost.
This approach is commonly used in well preplanning and involves the balancing of all drilling cost factors. For example, diamond bits have a much longer operational life than tricone bits, hence save on rig time required to trip. This must be balanced against the fact that they cost more and do not make footage as quickly. As another example, increasing weight and rotary speed on a tricone bit will generally increase rate of penetration; it also will increase rate of bit wear and shorten bit life.
Mathematically, a computer program to minimize the cost-per-foot function is relatively simple to devise, assuming that all other factors are known. This is the assumption used in the preplanning phase. Unfortunately, since nothing below (or above) the rotary table is entirely certain, it is necessary to have detailed and continuous wellsite monitoring to confirm that all factors, geological and manmade, are coinciding with the original plan. This aspect of drilling optimization relies on advanced mud-logging capabilities.
Wellsite drilling optimization programs are put into effect when the well is spudded. They are designed to recognize a deviation from the plan as soon as it occurs, consider variables involved, select and test alternative corrections, make recommendations to regain optimized drilling, and update the plan.
Measurement-While-Drilling Functions
The most comprehensive level of advanced mud logging currently available incorporates MWD capabilities. Most of the major mud-logging contractors now offer some version of this type of service. In addition to data and services discussed at other mud-logging levels, an MWD unit is capable of rapidly gathering and evaluating measurements made only a short distance behind the bit.
Instrumentation placed in MWD tools ( Figure 1 and Figure 2 , Examples of configurations and capabilities of measurement-while-drilling (MWD) tools) generally consists of short-normal resistivity (or conductivity) and gamma ray logging units (in some assemblages a neutron tool is available), plus devices capable of measuring annular temperature, hole direction and inclination, bit face orientation, and weight and torque on bit. In addition, the MWD tool will contain some method of obtaining power, such as mud turbine or storage batteries, and a method of encoding and transmitting data to the surface or storing them for later recovery. If transmission is involved, some form of mud pressure signal generally is used. In the alternate situation, data are recorded against time, stored internally, and recovered from the tool on the next trip to surface to replace the drill bit. In the delayed-recovery system, although measurements are made while drilling, data are not processed until the MWD tool returns to surface.
From the instrumentation listed, it can be seen that the types of MWD data that go into advanced mud-logging programs can include ( Figure 3 , Configuration ofa typical MWD data system):
Wireline Log Equivalents — formation (short normal) resistivity, (inductive) conductivity, gamma ray activity, and (neutron) porosity.
Directional Survey Equivalents — borehole inclination, azimuth, and drilling toolface.
Mud Log Interpretive Equivalents — bottomhole mud resistivity, temperature, and hydrostatic pressure.
Rig Interpretive Equivalents — true force and torque on bit.
Formational, directional, and operational MWD data are plotted in a variety of formats. Log formats permit immediate comparisons with logs and directional surveys from adjoining wells and subsequent comparisons with the same products from the active hole when it is next logged. Planometric and cross-sectional plots permit bottomhole position to be tracked and the borehole to be placed in three-dimentional perspective to other wells in the vicinity or from the same platform. When advisable, special presentations, such as anticollision plots, can be developed from current MWD data and stored data from other platform wells.
The data also can be used in the same capacity as that from many other down-hole logs; this includes lithologic characterization, correlation, pressure detection, casing seat selection, directional control, and porosity determination.
MWD is a long-term program that involves the measurement of data from early in the drilling of the well until total depth is reached. Full interpretation of the data requires incorporation of short- and long-term variations of drill rig and drill mud parameters. An MWD evaluation should not be considered complete until the well is at TD and other log and test data are available for correlation and confirmation purposes. Nevertheless, many operational conclusions and decisions can be made at the wellsite with MWD data. Responsive directional control and drilling optimization are prime examples.
D.7. Selection of Services and Equipment
Selection of Mud-Logging Services and Equipment
When an exploration or production well is to be drilled, it is standard planning procedure to use the economics of the drilling program to select the different services and/or "stand-alone" equipment, or both, to be used. As with most wellsite services and leased equipment, the anticipated costs of mud logging are balanced against resulting benefits.
Exploration and production departments make estimates of cost-per-interval drilled (e.g., cost per meter) and balance the effect of one cost factor against another, using a general formula such as:
where:
C = cost per interval drilled, ($/m or $/ft)
B = bit and other relatively fixed well costs, ($)
R = rig and services costs, ($/hr)
T = time spent drilling, (hrs)
t = time spent not drilling, (hrs)
H = interval drilled, (m or ft)
Mud-logging and leasing costs are included in rig-operating costs (R). Addition of any mud-logging service and leased equipment increases this cost and hence the cost per each interval drilled (C) of the well.
Obviously, to be cost-effective, the addition of any service must reduce other costs so that interval cost (C) is returned to its original or a lower figure. This can be done by decreasing the total "fixed" cost of products and tools used during the drilling life of the well (B) (e.g., reducing the amount of mud additivies used or the number of bits required to reach total depth). Alternatively, expenditures can be lowered by reducing other operating costs (R) (e.g., decreasing the number of wireline logs, DSTs, or outside safety services needed). Savings can also be made by reducing overall drilling and nondrilling time (T and t) or by maintaining all costs and times while increasing the interval of hole drilled (H) per unit of time.
While all of these types of savings are possible if mud-logging data are gathered and acted upon in a timely fashion, the most effective means of reducing expenditures through mud-logging functions is to reduce rig time (T and t).
Most day-to-day reductions in rig time using mud-logging data are through the maintenance of proper mud overbalance and optimum drilling practices, which includes determining the most efficient weight on bit, rotary speed, and bit-replacement schedule. In addition, large amounts of rig time can be saved if any potential drilling stoppage, such as hole instability, geopressure, acidic gases, or a kick, is recognized early enough to respond to remedial treatment while drilling continues.
Mud-Logging Programs
Mud-logging services vary from simple combustible gas analysis to complex down hole measurements made while drilling. The most basic capabilities are represented by contractors using units that are essentially identical to mud-logging units introduced in the 1940s and 1950s. These may still be adequate for low-risk production wells. At its highest level, mud logging can incorporate technology as sophisticated as any other equipment regularly operated at the well-site. Such highly automated and computerized services generally find use on expensive, deep, high-risk wells or on multiwell platforms.
Conventional Mud Logging
The basic level of mud-logging services provided by large companies is generally classified as formation logging. The formation-logging unit should have the equipment necessary to make full visual examination of cuttings and shows, and provide total hydrocarbon detectors for both mud stream and cuttings samples, as well as a gas chromatograph/flame ionization detector for determining individual hydrocarbon gases. To assist in plotting and interpreting cuttings and gas analyses, the unit should have a total depth recorder, a pump stroke counter, and drafting and reproduction capabilities.
With this minimal configuration, a single technician may be responsible for around-the-c lock operation. If this is the case, the wellsite geologist or engineer will have to perform or arrange for some sample collection, description, and monitoring functions. At the single-operator level, only passive geopressure recognition should be anticipated and no rapid response capabilities should be expected.
Preferably, two qualified technicians will share responsibility for operation of the mud-logging unit at the formation-logging level. In this situation, each technician generally takes a daily twelve-hour shift. Many logging companies use a fourteen-day-on/seven-day-off rotation so that three individuals may be involved in a two-man crew during the drilling life of a well. A very practical consideration is that these logging personnel be familiar with local geology and experienced in drilling practices of the area.
At the two-operator level, continuous, up-to-the-hour plots of basic geopressure parameters, such as shale density and connection gas, should be available at the wellsite.
When comprehensive pressure, geochemical, and nonhydrocarbon gas evaluative programs are to be provided as part of formation logging, a third, on-site technician probably will be required. In addition, some computer capabilities and supplemental mud monitoring and analytical equipment will be needed.
Advanced Mud Logging
Many modern mud-logging units provide additional sensors or services beyond those of the conventional, formation-logging level. The most advanced units provide advanced mud gas, geopressure, and petrophysical evaluations, plus drilling-data monitoring, acquisition, and interpretation. An analytical or interpretive specialist probably will be needed to carry out functions required by these programs. This technician may serve as the third on-site logger in the unit or be a fourth member of the crew.
When MWD systems are added, costs increase to cover equipment required to handle receipt of downhole data. In addition, leasing costs of down hole tools must be added to the drilling cost analysis. In general, two mud-logging crew members will have to be drilling specialists.
Stand-alone Equipment
Stand-alone instruments, displays, and apparatus that duplicate those of many mud-logging services and units generally are of two types: equipment that measures one specific wellsite condition( Figure 1 , Examples of basic stand-alone equipment for monitoring routine drilling variables) and equipment that monitors one rig system or more (e.g., driller's console) ( Figure 2 , Examples of multiple-function stand-alone equipment for monitoring and evaluating drilling operations). The following are examples of stand-alone equipment generally available for performing independent mud-logging functions.
· Basic Equipment:
Total hydrocarbon gas analyzer
Carbon dioxide monitor
Hydrogen sulfide monitor
Revolutions/minute and strokes/minute counters (rotary table, pumps, etc.)
Mechanical, pneumatic, and hydraulic multichannel recorders
Trip tank monitor
Mud volume totalizer
Mud flow/fill indicator
Mud density/temperature sensors
· Systems Equipment:
Mud system monitor (mud pump strokes, mud pump pressure, total mud volume, trip tank volume, total fill strokes, return mud flow, mud volume deviation)
Drilling controls monitor (equipment in mud system monitor plus weight on bit, total hook load, rotary speed, rotary torque)
Rig data processor (the equipment already mentioned, plus instruments and computer to provide standpipe and annulus pressure, accumulated fill, ROP, mud temperature in/out, drill depth, d-exponent, stands in hole, total trip time, total drill time, total system time)
Contracts and Leases
Selection of specific mud-logging services or equipment for a pending well starts at the time authorization-for-expenditure (AFE) procedures begin. In most drilling situations, the geologist defines the mud-logging or stand-alone program to be used at the wellsite. This program will be, in part, based on a cost-effectiveness formula.
When a mud-logging contractor is to be used, the program outlined by the geologist will include such items as the level of mud logging and log preparation to be carried out, the number of personnel to be provided by the contractor, and rigup and rigdown conditions. The latter should specify at what depth mud logging is to be fully operational and at what point, such as after final wireline log runs, the mud-logging unit and crew can move off. It also is advisable to include in the program a well-end debriefing requirement at which wellsite logging personnel review and summarize the various mud-logging plots and logs for the geologist and engineer.
When stand-alone equipment is to be used, the list of equipment and specifications is prepared together with an outline of the operator's personnel who will be responsible for equipment use.
The conditions to be met by the mud-logging contractor or stand-alone supplier are given to the engineer preparing the drilling specifications of the AFE. The engineer, in turn, provides these specifications to potential contractors and suppliers for bids or quotations. When the outside service companies have responded to the operator, their bids or quotations are reviewed by the engineer and geologist to determine how adequately they meet the specifications and anticipated costs of the drilling program. In the case of stand-alone equipment, the supplier probably will have made a visit to the drill rig prior to responding in order to determine the nature of instrumentation already at hand and to assure that all leased equipment will be compatible with rig systems.
After a final mud-logging or stand-alone program and its service company have been selected, a contract or lease agreement is drawn up between the participants specifying details of work and/or equipment to be provided. This is reviewed by the geologist and engineer.
At the time that all outside service contracts and agreements have been made (e.g., mud logging, mud engineering, bit supply, wireline logging), the operator holds a prespud meeting with contractors and suppliers to review the total drilling program. At this meeting, or more commonly at a subsequent prespud meeting in which only interested parties are involved (i.e., geologist, engineer, mud log contractor), any unclear conditions concerning mud-logging requirements or stand-alone configurations are answered. In particular, if a new mud-logging service company or setup is being used, this prespud meeting is the time to reaffirm such stipulations as log scales, sample interval, sample type(s), reporting frequency, reporting chain, shipping procedures, tight-hole procedures, and lag requirements.
When a mud-logging service is to be used, the first meeting between the geologist, engineer, and full mud-logging crew probably will occur when the mud-logging unit is moved on the site or platform. This generally is a day or two prior to reaching the specified depth at which full logging is to start. Prior to this point in the drilling program, all contractual obligations should be clear to both the operator and the contractor; any significant change in the mud-logging program that adds to contractor costs will have to be covered under "change" orders. Such program changes and added costs also will alter the projected cost-per-interval figure.
As observed previously, when stand-alone equipment is to be used, delivery and installation generally is made by the supplier. Setup will be prior to spudding. Because training in use of leased equipment generally is part of the setup service, operator personnel generally have to be at the drillsite for prespud familiarization with stand-alone equipment.
Exercise 1.
What do the following stand for?
a. MWD
b. d-exp
c. H2S
d. well-kill
e. stand-alone
Solution 1:
a. MWD is measurement while drilling; it generally indicates that sensors have been placed behind the bit in the drillstring.
b. d-exp is a calculated drillability of rock that removes some drilling operation variables.
c. H2S is hydrogen sulfide.
d. Well-kill is a procedure used to control a well kick.
e. Stand-alone is the name commonly applied to equipment supplied without an operator.
D.8. References and Additional Information
References
The following list of texts can provide a more detailed and technical account of specific technologies involved in modern mud logging.
Anadrill. 1984a. Drilling engineering and logging training for Anadrill (DELTA) manual. vol. 1. Sugar Land, Texas: Anadrill, Inc.
Anadrill. 1984b. Techniques for we/I-site logging, pressure detection and M. W. D. Sugar Land, Texas: Anadrill, Inc.
Anderson, G. 1975. Coring and core analysis handbook. Tulsa: Petroleum Publishing Company.
Baroid. 1985a. Mud logging service descriptions. Sugar Land, Texas: NL Baroid Logging Systems, NL Industries, Inc.
Baroid. 1985b. Measurements-while-drilling technical specifications. Sugar Land, Texas: NL Baroid Logging Systems, NL Industries, Inc.
Belotti, P., and D. Giacca. 1978. Pressure evaluation improves drilling programs. Oil and Gas Jour. Sept 11: 76-85.
Bingham, M. G. 1965. A new approach to interpreting rock drillability. Tulsa: Petroleum Publishing Company.
Calmer, S. H. 1979. H2S detector aids drilling safety, data. Oil and Gas Jour. Nov 19:
Clementz, D. M., G. J. DeMaison, and A. R. Daly. 1979. Wellsite geochemistry by programmed pyrolysis. Offshore Technology Conference Proceedings. OTC 3410. Houston
Coope, D. A., and W. E. Hendricks. 1984. Formation evaluation using measurements recorded while drilling. SPWLA Twenty-Fifth Annual Logging Symposium (June).
Core Lab. 1979a. Hydrocarbon well logging basic manual. Dallas: Well Logging Training Services, Core Laboratories, Inc.
Core Lab. 1979b. Identification of cuttings samples. Dallas: Well Logging Training Services, Core Laboratories, Inc.
Exlog. 1985a. Field geologist 's training guide (ed. A. Whittaker). Boston: IHRDC.
Exlog. 1985b. Formation evaluation: Geological procedures (ed. A. Whittaker). Boston: D. Reidel Publishing Company/IHRDC.
Exlog. 1985c. Mud logging Principles and interpretation (ed. A. Whittaker). Boston: IHRDC.
Exlog. 1985d. Theory and application of drilling fluid hydraulics (ed. A. Whittaker). Boston: IHRDC.
Exlog. 1985e. Theory and evaluation of formation pressures: A pressure detection reference handbook (ed. A. Whittaker). Boston: D. Reidel Publishing Company/IHRDC.
Exxon. 1985. Mud log and strip log: Standards, instructions, examples. Denver: Western Exploration Division, Exxon Company, U.S.A.
Gary, M., R. McAfee, Jr., and C. L. Wolf (eds). 1972. Glossary of geology. Washington, D. C.: American Geological Institute.
Gill, J. A. 1983. Hard rock drilling problems explained by hard rock pressure plots. IADC/SPE 11377. New Orleans drilling conference (February).
Goldsmith, R. G. 1972. Why gas cut mud is not always a problem. World Oil. 175(5):51-54, 101.
Haworth, J. H., M. Sellens, and A. Whittaker. 1985. Interpretation of hydrocarbon shows using light (C1 -C5) hydrocarbon gases from mud-log data. AAPG Bulletin 69(8): 1305-10 (August).
Hopkins, E. A. 1967. Factors affecting cuttings removal during rotary drilling. Jour. Pet. Tech. (June) 807-814; Trans AIME, 240.
Jordan, J. S., and 0. J. Shirley. 1966. Application of drilling performance data to overpressure detection. Jour. Pet. Tech. 18(11):1387-1394.
Magcobar, 1976. Data engineering manual. Houston: Dresser Magcobar Data Systems.
Martin, C.A., 1986. Wellsite applications of integrated MWD and surface data. IADC/SPE Dallas meeting (February).
Mercer, R. F., and J. B. McAdams. 1981. Hydrocarbon well logging (mud logging): Basic principles and needs for standards. SPWLA Speakers' Notes, Houston chapter (February).
Rehm, B., and R. McClendon. 1971. Measurements of formation pressure from drilling data. SPE Reprint Series. 3601(6a). (rev. 1973).
Robertson. 1985. Geochemical evaluation of a hypothetical well illustrating graphical representation of geochemical data. Report #483. Houston: Robertson Research (U.S.), Inc.
SPWLA. 1983. Recommended practices for hydrocarbon well logging. Houston: Society of Professional Well Log Analysts.
Swanson, R. G. 1981. Sample examination manual. Tulsa: AAPG.
Taylor, K. 0., and W. Anderson. 1984. Electronic system speeds drilling time. Oil and Gas Jour. (September).
Waples, D.W. 1985. Geochemistry in petroleum exploration. Boston: IHRDC.
Whittaker, A. 1985. Sample and core handling and analysis. Boston: IHRDC.
Zoeller, W. A. 1978. Instantaneous log is based on surface drilling data. World Oil (January).
Zoeller, W. A. 1974. Rock properties determined from drilling response. Petro Eng. (July).
Standard Abbreviations for Lithologic Descriptions
(Note: Abbreviations for nouns always begin with a capital letter.)
Word | Abbreviation |
about | abt |
above | ab |
absent | abs |
abundant | abd |
acicular | acic |
agglomerate | Aglm |
aggregate | Agg |
algae, algal | Alg, alg |
allochem | Allo |
altered | alt |
alternating | altg |
ammonite | Amm |
amorphous | amor |
amount | amt |
and | & |
angular | ang |
anhedral | ahd |
anhydrite (-ic) | Anhy, anhy |
anthracite | Anthr |
aphanitic | aph |
appears | ap |
approximate | apprx |
aragonite | Arag |
arenaceous | aren |
argillaceous | arg |
arkose (-ic) | Ark, ark |
as above | a.a.. |
asphalt (-ic) | Asph, asph |
assemblage | Assem |
associated | assoc |
at | @ |
authigenic | authg |
average | Av, av |
band (-ed) | Bnd, bnd |
basalt (-ic) | Bas, bas |
basement | Bm |
become (-ing) | bcm |
bed (-ed) | Bd, bd |
bedding | Bdg |
bentonite (-ic) | Bent, bent |
bitumen (-inous) | Bit, bit |
bioclastic | biocl |
bioherm (-al) | Bioh, bioh |
biomicrite | Biomi |
biosparite | Biosp |
biostrom (-al) | Biost, biost |
biotite | Biot |
birdseye | Bdeye |
black (-ish) | blk, blksh |
blade (-ed) | Bid, bid |
blocky | blky |
blue (-ish) | bl, blsh |
bore (-ed, -ing) | Bor, bor |
bottom | Btm |
botryoid (-al) | Bot, bot |
boulder | Bid |
boundstone | Bdst |
brachiopod | Brach |
brackish | brak |
branching | brhg |
break | Brk, brk |
breccia (-ted) | Brec, brec |
bright | brt |
brittle | brit |
brown. | brn |
bryozoa | Bry |
bubble | Bubl |
buff | bu |
burrow (-ed) | Bur, bur |
calcarenite | Clcar |
calcilutite | Clclt |
calcirudite | Clcrd |
calcisiltite | Clslt |
calcisphere | Clcsp |
calcite (-ic) | Calc, calctc |
calcareous | calc |
caliche | cche |
carbonaceous | carb |
carbonized | cb |
cavern (-ous) | Cav, cav |
caving | Cvg |
cement (-ed, ing) | Cmt, cmt |
cephalopod | Ceph |
chalcedony (-ic) | Chal, chal |
chalk (-y) | Chk, chky |
charophyte | Char |
chert (-y) | Cht, cht |
chitin (-ous) | Chit, chit |
chlorite (-ic) | Chlor, chlor |
chocolate | choc |
circulate (-ion) | circ, Circ |
clastic | clas |
clay (-ey) | Cl, cl |
claystone | Clst |
clean | cln |
clear | clr |
cleavage | Clvg |
cluster | Clus |
coal | C |
coarse | crs |
coated (-ing) | cotd, cotg, Cotg |
coated grains | cotd gn |
cobble | Cbl |
color (-ed) | Col, col |
common | com |
compact | cpct |
compare | cf |
concentric | cncn |
conchoidal | conch |
concretion (-ary) | Conc, conc |
conglomerate (-ic) | Cgl, cgl |
conodont | Cono |
considerable | cons |
consolidated | consol |
conspicuous | conspic |
contact | Ctc |
contamination (-ed) | Contam, contam |
content | Cont |
contorted | cntrt |
coquina (-oid) | Coq, coqid |
coral, coralline | Cor, corln |
core | c, |
cove red | cov |
cream | crm |
crenulated | cren |
crinkled | crnk |
crinoid (-al) | Crin, crinal |
cross | x |
cross-bedded | x-bd |
cross-laminated | x-lam |
cross-stratified | x-strat |
crumpled | crpld |
crystocrystalline | crpxln |
crystal (-line) | Xi, xln |
cube, cubic | Cub, cub |
cuttings | Ctgs |
dark (-er) | dk, dkr |
dead | dd |
debris | Deb |
decrease (-ing) | Decr, decr |
dense | dns |
depauperate | depau |
description | Descr |
detrital | detl |
devitrified | devit |
diabase | Db |
diagenesis (-etic) | Diagn, diagn |
diameter | Dia |
disseminated | dissem |
distillate | Dist |
ditto | "or do |
dolomite (-ic) | Dol, dol |
dominant (-ly) | dom |
drilling | drlg |
drilistem test | DST |
drusy | dru |
earthy | ea |
east | E |
echinoid | Ech |
elevation | Elev |
elongate | elong |
embedded | embd |
equant | eqnt |
equivalent | Equiv |
euhedral | euhd |
euxinic | eux |
evaporite (-itic) | Evap, evap |
excellent | ex |
exposed | exp |
extraclast (-ic) | Exclas, exclas |
extremely | extr |
extrusive rock, extrusive | Exv, exv |
facet (-ed) | Fac, fac |
faint | fnt |
fair | fr |
fault (-ed) | Fit, fit |
fauna | Fau |
feet | Ft |
feldspar (-athic) | Fspr, fspr |
fenestra (-al) | Fen, ten |
ferruginous | ferr |
fibrous | fibr |
tine (-ly) | t, fnly |
fissile | fis |
flaggy | fIg |
flake, flaky | FIk, flk |
fiat | ti |
floating | fltg |
flora | Flo |
fluorescence (-ent) | Fluor, fluor |
foliated | fol |
toot | Ft |
foraminefera (-al) | Foram, foram |
formation | Fm |
fossil (-iferous) | Foss, toss |
fracture(-d) | Frac, frac |
fragment (al) | Frag, frag |
frequent | freq |
fresh | frs |
friable | fri |
fringe (-ing) | Frg, frg |
frosted | fros |
frosted quartz grains | F.Q.G. |
fucoid (-al) | Fuc, fuc |
fusulinid | Fus |
gabbro | Gab |
gastropod | Gast |
gas | G |
generally | gen |
geopetal | gept |
gilsonite | Gil |
glass (-y) | Glas, glas |
glauconite (-itic) | Glauc, glauc |
Globigerina (-inal) | Glob, glob |
gloss (-y) | Glos, glos |
gneiss (-ic) | Gns, gns |
good | gd |
grading | grad |
grain (-s, -ed) | Gr, gr |
grainstone | Grst |
granite | Grt |
granite wash | G.W. |
granule (-ar) | Gran, gran |
grapestone | grapst |
graptolite | Grap |
gravel | Grv |
gray, grey (-ish) | gry, grysh |
graywacke | Gwke |
greasy | gsy |
green (-ish) | gn, gnsh |
grit (-ty) | Gt, gt |
gypsum (-iferous) | Gyp, gyp |
hackly | hkl |
halite (-iferous) | Hal, hal |
hard | hd |
heavy | hvy |
hematite (-ic) | Hem, hem |
Heterostegina | Het |
heterogeneous | hetr |
high (-ly) | hi |
homogeneous | hom |
horizontal | hor |
hydrocarbon | Hydc |
igneous rock (igneous) | Ig, ig |
impression | imp |
inch | in |
inclusion (ded) | Incl, incl |
increasing | incr |
indistinct | indst |
indurated | ind |
Inoceramus | Inoc |
in part | I.P. |
insoluble | insl |
interbedded | intbd |
intercalated | intercal |
intercrystalline | intxln |
intergranular | intgran |
intergrown | intgn |
interlaminated | intrlam |
interparticle | intpar |
intersticies (-itial) | Intst, intst |
intraclast (-ic) | Intclas, intclas |
intraparticle | intrapar |
intrusive rock, intrusive | Intr, intr |
invertebrate | Invtb |
iridescent | irid |
ironstone | Fe-st |
irregular (-ly) | irr |
isopachous | iso |
jasper | Jasp |
joint (-ed, -ing) | Jt, jt |
kaolin (-itic) | Kao, kao |
lacustrine | lac |
lamina (-tions, -ated) | Lam, lam |
large | lge |
late rite (-itic) | Lat, lat |
lavender | lav |
layer | Lyr |
leached | lchd |
lens, lenticular | Len, lent |
light | it |
lignite (-itic) | Lig, lig |
limestone | Es |
limonite (-itic) | Lim, lim |
limy | lmy |
lithic | lit |
lithographic | lithgr |
lithology (-ic) | Lith, lith |
little | Ltl |
littoral | litt |
local | loc |
long | lg |
loose | lse |
lower | l |
lustre | Lstr |
lutite | Lut |
macrofossil | Macrofos |
magnetite magnetic | Mag, mag |
manganese, |
|
manganiferous | Mn, mn |
marble | Mbl |
marl (-y) | Mrl, mrl |
marlstone | Mrlst |
marine | marn |
maroon | mar |
massive | mass |
material | Mat |
matrix | Mtrx |
maximum | max |
medium | m or med. |
member | Mbr |
meniscus | men |
metamorphic rock, | Meta |
metamorphic (-osed) | meta, metaph |
mica (-ceous) | Mic, mic |
micrite (-ic) | Micr, micr |
microcrystalline | microxln |
microfossil (-iferous) | Microfos, microfos |
micrograined | micgr |
micro-oolite | Microol |
micropore (-osity) | Micropor, micropor |
microspar | Microspr |
microstylolite | Microstyl |
middle | Mid |
miliolid | Milid |
milky | mky |
mineral (-ized) | Min, min |
minor | mnr |
moderate | mod |
mold (-ic) | Mol, mol |
mollusc | Moil |
mosaic | mos |
mottled | mott |
mud (-dy) | md, mdy |
mudstone | Mdst |
muscovite | Musc |
nacreous | nac |
nodules (-ar) | Nod, nod |
north | N |
no sample | n.s. |
no show | n/s |
novaculite | Novac |
no visible porosity | n.v.p.. |
numerous | num |
occasional | occ |
ochre | och |
oil | O |
oil source rock | OSR |
olive | olv |
ooid (-al) | OO, oo |
oolicast (-ic) | Ooc, ooc |
oolite (-itic) | Ool, ool |
oomold (-ic) | Oomol, oomol |
oncolite (-oidal) | Onc, onc |
opaque | op |
orange (-ish) | or, orsh |
Orbitolina | Orbit |
organic | org |
orthoclase | Orth |
orthoquartzite | O-Otz |
Ostracod | Ostr |
overgrowth | ovgth |
oxidized | ox |
oyster | Cyst |
packstone | Pkst |
paper (-y) | Pap, pap |
part (-ly) | Pt, pt |
particle | Par, par |
parting | Ptg |
parts per million | PPM |
patch (-y) | Pch, pch |
pebble (-ly) | PbI, pbl |
pelecypod | Pelec |
pellet (-al) | Pel, pel |
pelletoid (-al) | Peld, peld |
pendular (-ous) | Pend, pend |
permeability (-able) | Perm, k, perm |
petroleum, petroliferous | Pet, pet |
phlogopite | Phlog |
phosphate (-atic) | Phos, phos |
phyllite, phyllitic | Phyl, phyl |
phreatic | phr |
pink | pk |
pinkish | pkish |
pin-point (porosity) | p.p. |
pisoid (-al) | Piso, piso |
pisolite, pisolitic | Pisol, pisol |
pitted | pit |
plagioclase | Plag |
plant | Plt |
plastic | plas |
platy | pity |
polish, polished | Pol, pol |
pollen | Poln |
polygonal | poly |
porcelaneous | porcel |
porosity, porous | Por, , por |
possible (-ly) | poss |
predominant (-ly) | pred |
preserved | pres |
primary | prim |
probable (-ly) | prob |
production | Prod |
prominent | prom |
pseudo- | ps |
pseudo oolite (-ic) | Psool, psool |
pumice-stone | Pst |
purple | purp |
pyrite (-itized, -itic) | Pyr, pyr |
pyrobitumen | Pybit |
pyroclastic | pyrcl |
quartz (-ose) | Qtz, qtz |
quartzite (-ic) | Qtzt, qtzt |
radial (-ating) | Rad, rad |
radiaxial | Radax |
range | rng |
rare | r |
recemented | recem |
recovery (-ered) | Rec, rec |
recrystallized | rexlzd |
red (-ish) | rd, rdsh |
reef (-old) | Rf, rf |
remains | Rem |
replaced (-ment) | rep, Repl |
residue (-ual) | Res, res |
resinous | rsns |
rhomb (-ic) | Rhb, rhb |
ripple | Rpl |
rock | Rk |
round (-ed) | rnd, rndd |
rounded, frosted, pitted | r.f.p. |
rubble (-bly) | Rbl, rbl |
rudist | Rud |
saccharoidal | sacc |
salt (-y) | SA, sa |
salt and pepper | s & p |
salt water | S.W. |
same as above | a.a |
sample | Spl |
sand (-y) | Sd, sdy |
sandstone | Sst |
saturation (-ated) | Sat, sat |
scarce | scs |
scattered | scat |
schist (-ose) | Sch, sch |
scolecodont | Scol |
secondary | sec |
sediment (-ary) | Sed, sed |
selenite | Sel |
shale (-ly) | Sh, sh |
shell | Shl |
shelter porosity | Shlt por |
show | Shw |
siderite (-itic) | Sid, sid |
sidewall core | S.W.C. |
silica (-iceous) | Sil, sil |
silky | slky |
silt (-y) | Sit, sit |
siltstone | Sltst |
similar | sim |
skeletal | skel |
slabby | sib |
slate (-y) | Sl, sl |
slickenside (-d) | Slick, slick |
slight (-ly) | sli, slily |
small | sml |
smooth | sm |
soft | sft |
solution, soluble | Sol, sol |
somewhat | smwt |
sorted (-ing) | srt, srtg |
south | S |
spar (-ry) | Spr, spr |
sparse (-ly) | sps, spsly |
speck (-led) | Spk, spkld |
sphalerite | Sphal |
spherule (-itic) | Spher, spher |
spicule (-ar) | Spic, spic |
splintery | splin |
sponge | Spg |
spore | Spo |
spotted (-y) | sptd, spty |
stain (-ed, ing) | Stn, stn |
stalactitic | stal |
strata (-ified) | Strat, strat |
streak (-ed) | Strk, strk |
striae (-ted) | Stri, stri |
stringer | strgr |
stromatolite (-itic) | Stromlt, stromlt |
stromatoporoid | Strom |
structure | Str |
stylolite (-itic) | Styl, styl |
subangular | sbang |
sublithic | sblit |
subrounded | sbrndd |
sucrosic | suc |
sulphur, sulphurous | Su, su |
superficial oolite (-ic) | Spfool, spfool |
surface | Surf |
syntaxial | syn |
tabular (-ate) | tab |
tan | tn |
terriginous | ter |
texture (-d) | Tex, tex |
thick | thk |
thin | thn |
thin-bedded | t.b. |
thin section | T.S. |
throughout | thru |
tight | ti |
top | Tp |
tough | tgh |
trace | Tr |
translucent | trnsl |
transparent | trnsp |
trilobite | Tril |
tripoli (-itic) | Trip, trip |
tube (-ular) | Tub, tub |
tuff (-aceous) | Tf, tf |
type (ical) | Typ, typ |
unconformity | Unconf |
unconsolidated | uncons |
underclay | Uc |
underlying | undly |
uniform | uni |
upper | u |
vadose | Vad, vad |
variation (-able) | Var, var |
varicolored | varic |
variegated | vgt |
varved | vrvd |
vein (-ing, | -ed) |
Vn, vn |
|
veinlet | Vnlet |
vermillion | verm |
vertebrate | vrtb |
vertical | vert |
very | v |
very poor sample | V.P.S |
vesicular | ves |
violet | vi |
visible | vis |
vitreous (-ified) | vit |
volatile | volat |
volcanic rock, volcanic | volc, Volc |
vug (-gy) | Vug, vug |
wackestone | Wkst |
washed residue | W.R |
water | Wtr |
wavy | wvy |
waxy | wxy |
weak | wk |
weathered | wthd |
well | WI, wi |
west | w |
white | wh |
with | wi |
without | w/o |
wood | Wd |
yellow (-ish) | yel, yelsh, |
zircon | Zr |
zone | Zn |
(From Swanson, 1981, reprinted by permission of AAPG).
Comments :
0 comments to “Mud Logging ”
Posting Komentar