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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume V – Reservoir Engineering and Petrophysics

Edward D. Holstein, Editor

Chapter 3F – Mud Logging

Dennis E.Dria, Shell Intl. Exploration and Production Inc.

Pgs. 357-377

ISBN 978-1-55563-120-8
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Mud logging, in its conventional implementation, involves the rig-site monitoring and assessment of information that comes to the surface while drilling, with the exclusion of data from downhole sensors. The term mud logging is thought, by some, to be outdated and not sufficiently descriptive. Because of the relatively broad range of services performed by the geologists, engineers, and technicians traditionally called mud loggers, the term "surface logging" is sometimes used, and the personnel performing the services may be called surface-logging specialists. Additional specialist designations may include pore pressure engineer, formation evaluation engineer, logging geologist, or logging engineer. For the sake of generality, the terms mud logging and mud logger are used here with the understanding that the hybrid discipline encompasses much more than monitoring the mud returns and that the trained specialists perform engineering and geological tasks that span several traditional disciplines.

There are several broad objectives targeted by mud logging: identify potentially productive hydrocarbon-bearing formations, identify marker or correlatable geological formations, and provide data to the driller that enables safe and economically optimized operations. The actions performed to accomplish these objectives include the following:

  • Collecting drill cuttings.
  • Describing the cuttings (type of minerals present).
  • Interpreting the described cuttings (lithology).
  • Estimating properties such as porosity and permeability of the drilled formation.
  • Maintaining and monitoring drilling-related and safety-related sensing equipment.
  • Estimating the pore pressure of the drilled formation.
  • Collecting, monitoring, and evaluating hydrocarbons released from the drilled formations.
  • Assessing the producibility of hydrocarbon-bearing formations.
  • Maintaining a record of drilling parameters.

Mud logging service first focused on monitoring the drilling mud returns qualitatively for oil and gas content. [1][2] This included watching the mud returns for oil sheen, monitoring the gas evolving from the mud as it depressured at the surface, and examining the drill cuttings to determine the rock type that had been drilled, as well as looking for indication of oil on the cuttings. Detection of the onset of abnormal formation pressures using drilling parameters was proposed with the introduction of the d exponent. [3] Gas chromatography, which was developed early in the 20th century, saw its introduction in mud logging in the 1970s when electronics became sufficiently compact, rugged, and robust to be used at rig sites. The literature provides excellent reviews of the early history. [4][5]

Computerized data acquisition and the ability to routinely transfer continuously acquired data to the office data center enabled the broader application of more sophisticated interpretive techniques and the integration of data from different sources into the geological and reservoir model, in near real time. This, coupled with the blossoming of measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools, moved the mud-logging unit into a new role as a hub for rig-site data gathering and transmission. [5] Starting in the 1980s, significant improvements to existing technologies, as well as major technical breakthroughs, have given the geologist and petroleum engineer a great number of powerful mud-logging tools to interpret and integrate geological, drilling, and geochemical data. These tools are discussed in subsequent sections of this chapter.

The traditional products delivered by a mud-logging vendor include geological evaluation, petrophysical/reservoir formation evaluation, and drilling engineering support services. In this overview, we consider that these products support three basic processes associated with drilling and evaluation of wells: formation evaluation (building or refining the geological and reservoir models), drilling engineering and operations (the planning and execution of the well construction process), and maintaining drilling and evaluation operations with appropriate health, safety, and environmental (HSE) consideration. The following section describes the path that drilling fluid follows during the drilling operation to explain where the logger obtains data.

Mud Logging Data Acquisition

Fig. 3F.1 schematically shows the components of a drilling operation that have a part in mud logging. The most critical component is the drilling fluid (drilling mud), which, in addition to its role in drilling mechanics, carries most of the information from the formation up to the surface where it is acquired, decoded, or extracted from the mud stream by various techniques. Drilling liberates gas and liquid formation fluids, and circulation of the drilling fluid carries these to the surface (except during riserless drilling in a deepwater offshore environment, in which the drilling returns circulate only up to the sea floor). Cuttings, pieces of formation rock, are also carried in the circulated drilling fluid. MWD and LWD data are frequently encoded as pressure pulses and transmitted to the surface. Mud temperature is not a direct indicator of subsurface formation temperature, but monitoring the trend is important to understanding gas extraction efficiency and recycling. In deepwater drilling environments, the mud can be cooled significantly on the trip from the sea floor to the surface.

Drilling fluid is stored in the mud pit, drawn into the mud pumps, and pumped into the drillpipe via the kelly. Mud travels down the drillpipe, through any MWD tools and drill motors, and through the bit nozzles where its discharge aids drilling mechanics. At this point, the drilling fluid carries away rock fragments from drilled formation, along with any liberated reservoir fluids (water, oil, or gas). Cuttings and reservoir fluids are transported to the surface. Any gaseous components are dissolved in the base fluid of the drilling mud under most overbalanced drilling conditions. Drilling mud continues its flow up the wellbore drillstring annulus, through the casing-drillpipe annulus and the BOP stack, and, in the case of an offshore well, up the riser. At the bell nipple, the returning drill fluid is exposed to atmospheric pressure and flows down the mud return line. If an underbalanced drilling operation is being used, there is a rotating seal around the drillpipe, and the pressurized drilling returns stream moves through the "blooey line" to a separator and flair.

The return mud stream continues down the return line to the shaker box or "possum belly." This is the standard location for the "gas trap" gas extractor. Mud pours over the shaker screens, with cuttings getting discharged off the top of the screen, while the drilling fluid that falls through the screens travels on through the degasser, desander, and desilter to the mud pits. The mud logger takes samples or acquires data at the following points in the process.

  • Whole mud samples are taken at the mud suction pit and at the possum belly and are used to do whole-mud extraction using a steam still. They may be taken on an occasional basis during coring and wireline logging to assess the effects of mud filtrate and solids.
  • Drill cuttings samples are taken off the shaker screen and off a "catch board" where cuttings fall from the screen to disposal. These are used for lithological and mineralogical description, paleo description, and sometimes "canned" for laboratory-based carbon-isotope analysis, detailed geological examinations such as thin-section preparation and analysis, chemostratigraphy, and source rock evaluation.
  • Gas sampling is done through an extractor at the possum belly, in some cases at the bell nipple or off the mud return line to minimize losses to the atmosphere, and at the mud suction line or mud pit to monitor recycle gas content of the mud. After extraction, gas analysis may be performed at the sampling location, [6] or, more routinely, the gas is continuously transferred via a vacuum line to the logging unit where it is passes through the manifold of analytical instruments (total HC, GC, MS, H2S, etc) and may be captured for laboratory-based analysis (carbon isotope, molecular composition). [7]

  • Mud temperatures are monitored at the mud suction pit and mud return line.

The mud engineer collects mud samples for analyses that are used to determine any adjustments to mud properties needed for drilling.

Contamination is defined here as any material that does not come from the formation that has been drilled at the time that a specific volume element of mud exits the bit. Mud contamination has several potential sources:

  • Air, which can enter the top of the drillpipe when the Kelly-drillpipe joint is broken during a connection.
  • Pipe scale and pipe dope from inside the drillpipe (pipe dope fluoresces and may interfer with show identification or description).
  • Rock sloughing or rubbing off formations further up hole.
  • Cuttings that have bedded or built up because of improper hole cleaning dynamics that are mobilized by changes in mud viscosity, pumping rate, or drillpipe or collar rotation.
  • Uphole fluids that flow or are swabbed into the annulus.
  • Cuttings that have built up on the shaker screen or in the possum belly.

The logger should be watching for any change in cuttings or mud-conveyed hydrocarbon fluids that indicate contamination. Mud additives such as weighting agents and lost-circulation material are not considered contaminants, but must be monitored because some of these interfere with analytical observations and descriptions or give interfering instrument responses. Some base mud fluids, particularly some of the synthetic fluids, create challenges for the mud logger, as do some chemical additives (e.g., some sulfate or sulfonate wetting agents may give a false positive H2S indication).

Samples of the drill cuttings are taken at the shale shaker. Wellsite geologists or engineers should specify the appropriate procedure for collecting samples, which may be done by the mud logger or the mud logger’s sample catcher. Cuttings have a relatively short residence time on the shaker screen. Sampling protocol should include taking a composite sample with portions from different areas of the screen, combined with cuttings that have been retained on a "cuttings board." A cuttings board is a wooden board, steel angle iron, or other such device that is hung just below the base of the shaker screens to catch cuttings as they fall off the edge of the screen. Immediately after samples are collected, the screen and catch board should be washed down with clean drilling mud base fluid. The logger should mix this composite sample and take divided portions for cleaning, interpretation, and bagging. The wellsite planner should specify the sampling frequency (typically a composite over 10-, 30-, or 90-ft intervals or on a timed basis).

Gas sampling is traditionally done with a mechanical degasser, generically called a "gas trap." Fig. 3F.2 shows an example. [8] Typically placed in the shaker box, the trap pulls in drilling mud through the centrifugal action of the stirrer. The mechanical action of the stirrer, combined with a slight vacuum pulled in the trap head space, allows the gas to partition between the liquid and gas phase. The head-space gas is pulled by vacuum through tubing, into the logging unit, and on through the gas analysis manifold.

Alternative methods for sampling gas may be accomplished by continuously operating controlled-volume mechanical or thermomechanical slip-stream gas extractors[9][10] and membrane-type extractors. [6] The mud logger may place the sampling point for these gas extraction devices at the bell nipple, the mud return line, or in the shaker box. Other methods require taking discrete samples, followed by thermal extraction techniques [such as the steam still, where samples of the whole mud are collected and portions heated in a steam-distillation apparatus (Fig. 3F.3)] and microwave heating methods. [8]

The gas manifold may include provisions for a portion of the gas stream to be pumped into sample containers, either laminated gas bags or stainless steel tubes *

(see Fig. 3F.4). These gas samples are then shipped from the rig for laboratory analyses. There are new mass-spectrometer-based techniques that may not require a bulk extraction of the gas from the mud for analysis. [11]

Once gas is extracted from the drilling fluid, various analytical techniques determine properties of the gas at the rig site. The basic measurements include a determination of the "total" gas concentration and the composition and concentrations of the constituent components.* Personal communication with D. Coleman, IsoTech Laboratories, Champaign, Illinois (2002).

Total Gas Analysis

The total gas analyzer (TGA), also referred to as the total hydrocarbon analyzer (THA), measures the total amount of gas, typically the total amount of combustible gas. The usual unit of TGA measurement is total methane equivalents (TME), which is essentially the BTU content of the gas extracted from the drilling fluid, expressed as that which would be obtained from an equivalent concentration of pure methane in air. The TGA, while giving an undifferentiated indication of gas entrained in the drilling fluid, has the advantage of operating in a continuous mode. Today, most TGAs use either a thermal conductivity detector (TCD) or a flame ionization detector (FID).

Component Analysis

There are several analytical techniques used at the rig site to measure the molecular composition and component concentrations of the reservoir fluids entrained to the surface in the drilling fluid. These techniques are the gas chromatograph (GC), the mass spectrometer (MS), and the infrared spectrometer.

Gas Chromatograph

The most widely used technique, and among the more accurate, is the GC (Fig. 3F.5). This instrument separates components from a mixture by selectively adsorbing and desorbing each compound at different rates, either on the surface of a granular packing contained in a column made of small-diameter tubing or on the internal surface of the tubing itself. A small, usually submilliliter, volume of the mixture (i.e., the gas extracted from the drilling fluid) is injected into a carrier gas stream, which carries the sample into the GC column. Components start to separate, depending on their affinity for the active surface of the packing or the column tubing. At the end of the column, components elute, each with a unique retention time, and pass into a detector. The different detectors used to analyze the compounds eluting from the GC column include the FID, the TCD, the catalytic combustion detector (CCD), the MS detector, and the infrared (IR) absorption spectrometer.

Flame Ionization Detector. The FID uses a flame of burning hydrogen to combust the eluting compound. As the compounds undergo combustion, ionized single-carbon intermediates are captured by the collector electrode. Very sensitive circuitry (the electrometer) measures the extremely small, microamp-level current generated by this flow of ions, which is proportional to the total number of carbon atoms in the combusting gas mixture. Fig. 3F.6 shows the FID device schematically. The hydrocarbon species present are known because the operator, by design, knows which hydrocarbon component is eluting; therefore, concentration of that component may be calculated.

Thermal Conductivity Detector. The TCD (or hot wire detector) measures the thermal conductivity of the gas mixture passing over a filament. The typical TCD uses a Wheatstone Bridge circuit to measure the resistance of a platinum filament. The filament is heated to a constant temperature. As a gas passes over the filament, the temperature is reduced by an amount that is related to the thermal conductivity of the gas and the gas-flow rate. The resistance of the filament changes with temperature. At a constant flow rate through the sensing cell, gases of different composition and, hence, different thermal conductivity cool the filament by different amounts. In most TCD devices, there are two cells: a reference cell through which the pure carrier gas (in these cases, usually air) flows and a sample cell through which the gas mixture extracted from the drilling fluid flows. The filaments from the cells form two of the four arms of the Wheatstone Bridge (Fig. 3F.7).

Catalytic Combustion Detector. The CCD measures the temperature change in a platinum filament when the gas mixture is combusted. Rather than using a flame, the CCD device has the filament imbedded in a catalytic bead, which catalyzes the combustion chemical reaction, allowing it to occur at temperatures lower than normal flames. Heat is released according to the "heat of combustion," and this released heat increases the filament temperature and, hence, its resistance. The resistance of the sample filament is compared with the resistance of a reference filament, in a fashion similar to the TCD, and provides an output that is a function of the composition of the gas mixture. This device provides an output signal that is more or less related to the BTU content of the gas mixture it is measuring.

Mass Spectrometer Detector. The MS detector measures the quantity of a particular compound by determining the amount of material with a specific molecular weight. (Fig. 3F.8 shows the magnetic-sector MS.) This is done by ionizing a small quantity of material, during which multiple fragments of the molecule may be produced. Each fragment has a specific mass-to-charge ratio. Ionized fragments are separated in space or time, on the basis of their respective mass-to-charge ratio, and are then quantified by an ion detector. These devices have been used only in laboratory-based analyses until recently, when compact, robust MS detectors have been introduced for rig-site use. [10] The MS has commonly been used to quantify components eluting from a GS (the GC-MS system) and has the advantage of being able to differentiate mixes of several components that may coelute, as long as the individual molecular species differ sufficiently in molecular weight. By principle of detection, this advantage allows simultaneous analysis of saturated and aromatic hydrocarbons, as well as the acid gases CO2 and H2S and inert gases such as nitrogen.

Recent advances in MS instrumentation and methods may allow its use at the rig site to measure directly the amounts of specific paraffinic and aromatic hydrocarbon compounds, CO2, and H2S without the need for chromatographically separating the components. This would replace the function of the GC for HC component analysis, along with in-mud hydrogen sulfide detectors. These specific methods[11] are in relatively early stages of development and are not described here in detail.

Infrared Absorption Spectrometer. On input of IR energy to a molecule, its bonds will vibrate in any of a variety of modes, such as stretching, bending, rotating, and twisting. The mode of vibration will vary depending on the specific bond and the wavelength of the exciting radiation. IR radiation passes through a cell filled with the gas mixture. Portions of the incident IR spectrum are absorbed by the molecules in the gas, according to the characteristic absorption wavelengths of the specific molecules comprising the gas. The amount of IR radiation absorbed is a function of the path length and the concentration.

For a variety of physical reasons, the absorption spectrum is not manifested as a series of discrete wavelengths, but rather as a series of broader bands that, particularly in hydrocarbon systems, overlap to the point of being difficult to explicitly deconvolve. Because IR sensors also tend to have poor resolution compared with band. When comparing differences in principles of operation, relative accuracy over a wide dynamic range of gas concentrations and operational robustness under rig site, for most applications the FID is the preferred detector system for both the GC and the THA.

Cuttings Analysis

Cuttings provide the first opportunity and, in some wells, the only opportunity to actually look at the rock that has been drilled. Cuttings give the geologist information about the formation lithology needed for geologic correlation, the mineral composition for marker beds, input for the petrophysicist or log analyst, and, in some cases, enough hydrocarbon to allow some oil-quality measurements to be performed. Cuttings are also a source for microfossils used in biostratigraphy.

Sample Lagging

Proper sample collection and preparation is of paramount importance. The first step is to know where the cuttings are from, which is done by performing a lag calculation. "Lagging" is performed by any of several methods. The most accurate method is to inject a tracer of some sort into the drilling fluid stream at the surface and time its exit as it is circulated out. The volume of the mudlines and drillpipe, from the point of injection to the bit, can be calculated from the pipe measurements (inside diameter and length). The total tracer residence time in the drill fluid is


and RTENOTITLE....................(3F.2)

so that


where tan = the lag time from the bit to the point at the surface where the tracer is measured (usually the shaker box), tt = the total elapsed pumping time from injection to measurement, q = the mud pump flow rate, Vdp = the internal volume of the drillpipe and drill collars, and Vs = the internal volume of any surface lines from the point of tracer injection to the kelly. Commonly used tracers include calcium carbide, air, and injected reference gas.

Solid carbide is put into the drillpipe when making a connection and pumped down with the circulating mud. Calcium carbide chemically reacts with water in the drilling fluid to form acetylene, which is then detected with the THA as it circulates out. Ease of handling and injection into the circulating mud system makes carbide lagging a popular choice. Disadvantages include the need for a manual operation, particularly the need for an additional person on the drill floor during the busy operation of making a connection, and the requirement that there be ample free water in the drilling fluid, which is not always the case with oil-based and synthetic mud systems.

Other materials may be injected into the drillpipe while making a connection. Virtually any benign pulverized solid that can be seen in the mud returns, such as ground-up bricks. If a high-viscosity sweep is being pumped, that can also be used to measure lag. These methods do require that logging personnel carefully watch the shaker screens to catch the appearance of the lag tracer.

When the kelly reaches the rotary table, the drillpipe is raised slightly so that the current connection between the kelly and the top pipe can be broken. This action reduces the mud pressure at the bit and can "swab" some formation fluids into the wellbore. The gas dissolved in this fluid is carried to the surface with circulation, appearing as "connection gas," and may be used as a lag indicator. Swabbing at connections may also bring gas in from locations above the bit, depending on pore pressure gradient, drilling fluid rheology, and annular geometry. If this occurs, an erroneous lag results.

A less frequently used method for lag determination involves the injection of a reference gas into the mud pump intake. [12] Reference gas injection, by its original design, serves primarily as an internal standard for quantifying mud gas concentration. A noninteracting gas is injected at low rates into the mud pump intake line, which is controlled to maintain a constant concentration of the referencing gas in the drilling fluid. Momentarily increasing or decreasing the injection rate results in a subsequent increase or decrease in gas concentration in the drilling fluid. This concentration perturbation is noted while monitoring the mud gas using the logger’s gas analyzer, and its residence time in the system is used in the lag calculation. Advantages of this measurement include that it can be done on demand without waiting for a connection, it is independent of drilling fluid composition (no need for water in the case of nonaqueous drilling fluids), and that it can easily be automated.

Cuttings Collection

Samples of drilled cuttings are normally taken at the shaker screens, although some have proposed and tested devices for diverting a small stream of cuttings-laden mud from the return line. [13] At predetermined depth or time intervals, the logger or sample catcher collects a composite sample that contains cuttings representative of the entire interval drilled since the previous collection. Very typically, cuttings samples will be taken every 30 ft (10 m), until target bed boundaries are approached, such as thin marker beds, anticipated reservoir sections, casing points, or coring points.

By placing a board at the base of the shaker screen in line to catch cuttings as they fall off the end of the screens, the sample catcher assures that a composite sample accumulates. At the desired sampling time, the sampler scrapes cuttings off the board into a sampling bucket and adds additional cuttings from several locations across the screen (the latter, to catch the very latest drilled material circulated up). This collection yields a composite sample that is fairly representative of the formations drilled since the last collection. Immediately after sampling, the sampler should hose down the screen and catching board with water for aqueous drilling fluids or with the appropriate base fluid for nonaqueous drilling fluids. Proper cleaning of the composited cuttings calls for placing the cuttings on a fine mesh screen and flushing with the base drilling fluid.

Cuttings Sample Examination and Description

Proper handling, examination, and description guidelines should be specified when contracting mud-logging services. This section is not meant to replace an experienced professional geologist’s interpretation of cuttings, but serves as a guide to the important "high points" that the logger should remember in applying procedures presented in appropriate geological guidelines and manuals. Several excellent references are available. [14][15][16] Swanson’s thorough summary[17] is presented as a detailed manual.

Scanning a series of samples laid out on the counter allows the logger to get a good overview of trends, to highlight sample differences that may be the result of quality variation or contamination, and to help identify bed boundaries. Individual samples are then examined under a low-power stereomicroscope (10 to 50X) with either ample natural light or a lamp with a "blue" light or blue filter. Proper illumination is required so that the true colors of the sample constituent minerals are not distorted. Digital image capture of select samples adds significantly to the end-of-well documentation. A quick examination should identify all material present in significant quantity, including contaminants, metal, drilling additives, lost-circulation material, and suspected caved material, in addition to the drilled-formation rock cuttings. This examination should include an assessment of sample quality.

The well databases containing the cuttings log should include an estimate of the percentage of each rock type, which is an assessment of what is actually seen in each individual sample, as well as an interpretation of the lithology, which is based on all the data available to the logger. The logger’s manual should call for a standardized description protocol containing rock type (with classification), color, texture (grain size, roundness, sorting), cement and/or matrix material, fossils, sedimentary structures, and porosity and oil shows. Standard abbreviations should be used in the description, as well as standard symbols as the log is being drawn. [17]

Many special tests are run on rock samples to make on-the-spot determination of specific minerals. These tests vary from such standard chemicals as alzarin red for calcite detection to calcimetry for quantitative determination of carbonate content. A qualified logging geologist will have experience in suggesting and implementing them.

The sample should be viewed under ultraviolet (UV) light, and any fluorescence noted (mineral or hydrocarbon). Certain types of hydrocarbons, in the rock pores or "stained" on the grain surface, may not fluoresce. To test for these, the rock samples may then be treated with an appropriate organic solvent while being viewed under UV light. "Streaming" fluorescence may be noted (streamers or wisps of hydrocarbon) as it moves from the rock cutting into the solvent surrounding the cutting. As the solvent dries, "residual cut" may be observed as a fluorescing ring or residue in the examination dish. These are examples of "cut fluorescence."

Sometimes there will be more extraneous material present in the cuttings sample than actual drilled formation fragments. Commonly seen nonformation solids include the following:

  • Cavings from uphole, previously penetrated beds. These will be recognized as formation material logged earlier and individual cuttings may have shapes that distinguish them from bit cuttings.
  • Recirculated cuttings. These are usually smaller, individual grains or microfossils.
  • Lost circulation material. Extraneous solids, which have a size to plug up lost circulation zones, are added to the drilling fluid. These may be as unusual as cotton seed hulls, ground-up pecan shells, and shredded rubber.
  • Cement fragments. Close attention should be paid to the drilling record.
  • Drilling mud. Washing samples using procedures and solvents that are appropriate for the specific mud system. Consideration for the health of the logger and the environment is critical.
  • Pipe dope. This contaminant may fluoresce, giving a false show indication.

This list of contaminant examples is not all inclusive, and judgment, combined with close attention to the drilling and mud engineers’ records, is critical.

Maintaining Data Quality

Many different data are available, obtained through technologies that range from tried-and-true classical "wet chemistry" techniques through high-tech sensors that use procedures established after countless years of thoughtful research, development, and field testing. Even the best planned operations may, from time to time, provide data of poor quality or even totally miss data from important geologic intervals. Proper planning of surface data logging operations should include provisions for "whole-system" qualification before starting the operation, as well as a plan for the occasional quality audit. Details will vary widely depending on the location of the operations, availability of staff, project magnitude, and economics. An appropriate quality assurance program may be as simple as receiving a weekly e-mail or fax with GC calibration information or as intensive as scheduling rig-site audits, depending on the exact circumstances and well logging objectives.

Formation Evaluation

Formation evaluation, for this discussion, is the process of describing a geologic formation, and any fluids contained within, in terms of their constituent properties and determining the properties of the rock to assess the total and recoverable volume, value, and producibility of the fluids and the placement, and the engineering design and economics of drilling and completing the wells that are needed to produce the fluids. Many data are interpreted to evaluate a petroleum-bearing formation, and we discuss the interpretations of data acquired through surface data logging in terms of the rock formation and fluid properties they help determine.

Fluid Type

The logging engineer or geologist gets information about the formation fluids directly from fluids that are released into the wellbore while drilling and circulating out suspended immiscibly in the drill fluid or remaining in the pores of larger cuttings that may not have been flushed. They receive information indirectly from remnants of the fluid that remain in pores of rock cuttings, as stains on the grain surface, or in solution in the drilling fluid.

Oil may be identified as a sheen on the surface of water-based drilling fluid. If the circulating fluid density is sufficiently low as to render an underbalanced drilling condition, oil may be produced in large enough quantities that a sample may be skimmed off a whole mud sample. Similarly, the underbalanced penetration of a gas-bearing formation yielding only a small quantity of free gas in the mud system at the bit will expand according to the real gas law as it is circulated to the surface, where it may be detected and possibly sampled (although, in an uncontrolled situation, this results in hazardous safety and environmental conditions). These are all fairly obvious, direct indicators.

The ratio of various mud-gas components (e.g., the molar or volumetric ratio of methane to ethane) may be crossplotted or correlated with fluid type. [18][19][20][21] The modified Pixler method, [19] for example, plots ratios of methane (C1) to, respectively, ethane (C2), propane (C3), butanes and heavier (C4+), and pentanes and heavier (C5+):




and RTENOTITLE....................(3F.7)

Through a correlated analysis, ranges of these ratio values had been determined that were representative of productive and nonproductive gas and oil (see Fig. 3F.9).

The Haworth et al. "wetness" method[20] defines several correlatable ratios: wetness, Wh; balance, Bh; and character, Ch.




The values of these ratios determine, through the interpretation shown in Fig. 3F.10, whether the hydrocarbon is gas or oil, very dry gas, and, with enough data, whether the oil is tending towards being a light oil, heavy oil, or residual oil.

These ratio methods tend to work robustly only within the basins in which they are calibrated, the number and quality of data from the basin within which they are calibrated, and the errors inherent in obtaining the calibration set as well as the unknown data set. Examples of these inherent errors include the unknown or varying extraction efficiency at the gas trap and the accuracy of the gas-measurement system. Normalization techniques, [22][23] either against an internal standard or other parameters, can improve the consistency and robustness of the ratios.

Fluid Properties

If determining fluid type is difficult because of errors and unknowns in measuring the composition of formation hydrocarbons entrained in the drilling fluid, even more difficulty can be anticipated in estimating the fluid properties, such as viscosity or API gravity. The more robust methods involve either quantitatively measuring the methane-through-pentane composition of the drilling fluid returns and correlating these with the HC fluid properties[24] or involve spectroscopy techniques to get particular spectra and correlating these to oil properties or type. [25][26]

The QGM™ process[8] involves the use of a gas-trap extractor that was characterized and field tested extensively. This trap, when used in a controlled fashion, can give a quantitative measurement of gas-trap extraction efficiency when calibrated with a measurement of thermally extracted mud-gas composition. With proper control and calibration, this process gives highly accurate gas-in-mud compositions. With these, correlations have been developed that relate composition parameters to oil properties.

An enhanced quantitative UV-fluorescence technique[26] monitors the intensity of two emission wavelengths resulting from exciting an oil sample with UV radiation. The ratio of the intensities varies according to the oil composition or, more exactly, according to the concentrations of certain aromatic compounds in the oil sample.

Formation Porosity

Formation porosity is estimated by visually inspecting rock cuttings, which requires a sufficient description and classification of the rocks. Several references supply discussion. [14][15][16][17] The requirement of rock fragments with intact pore systems eliminates the use of this method when drilling poorly consolidated or unconsolidated sands and when bit types, such as the PDC, reduce most of the potential reservoir cuttings to grain-sized fragments.

The method described by Boone[27] calculates the rock porosity that would be required to liberate the specific amount of gas measured when a set volume of formation is drilled. This assumes low fluid spurt loss while drilling (near-zero flushing of the rock ahead of the bit), which is frequently violated except in near-balance drilling and low-permeability formations.

Formation Permeability

The formation permeability may be estimated visually by the logger from the grain size and sorting. At best, this may give order of magnitude estimates, but, frequently, the smaller, clay-sized particles, which may control the permeability if present in appreciable amounts, cannot be quantified with any confidence. Another limitation occurs because the cutting sample is acquired over a relatively large depth interval, and "smearing" of the data occurs in zones where grain size, sorting, and clay content vary significantly.

Pore Pressure

Pore-pressure variations, particularly transitions from normal to geopressures, trend with several measurable parameters. These parameters are discussed more in the Drilling section.

Geological or Petrophysical Information for Evaluation Away From the Wellbore

The correlation of geologic strata relies on determining certain characteristic properties or constituents of a particular geologic formation. Geologists use these properties in one of several techniques to correlate formations from well to well within a field as well as in broader, basin-wide studies. Particular formations may serve as "markers" by having one or a set of distinguishing characteristics. Mud-logging services provide rock-cutting samples for the determination of these characteristics and, in some cases, may acquire the data on site. The acquisition of cuttings samples for these tests may impact the cuttings sampling or preparation techniques and should be considered when specifying a mud-logging service.

Microscopic fossils identified and correlated by paleontologists yield "biomarkers," which become the working data for biostratigraphy. These biomarkers frequently appear in the cuttings in very low quantities because of the grinding and abrasion the cuttings see under the action of the drill bit and transport uphole in the returning mud stream. Their preparation calls for consistently applied cleaning with the use of a screen or sieve with openings small enough to retain the microfossils.

Specific mineral assemblages may be present in a particular geologic formation with compositions nearly constant or in relative abundances that are nearly constant over an extensive areal. The use of such mineral compositions as stratigraphically correlatable parameters is called chemostratigraphy. The ratio of concentrations of these certain minerals, as well as of other compounds associated with the deposition and diagenisis of the particular formation, must then be determined relatively quickly and cheaply. It has been shown that the ratios Ca/Al, Na/Al, and K/Al are related to clay mineral concentration ratios, and that relative amounts of such elements as Ti, Cr, and Zr are frequently associated with the clay minerals. [28][29][30] Chemostratigraphers determine the amounts of these elements using laboratory or rig-based instruments such as inductively coupled plasma spectrometry and laser-induced breakdown spectroscopy.

Pore fluids present during diagentic processes become crystallographically trapped in small volumes called fluid inclusions. These tiny drops of fluids, sealed in cavities typically 2 to 20 μm in size, are thought to be representative of the pore fluid composition that existed at the time of their formation. [31] After appropriately cleaning portions of the drill cuttings, geologists chose grain samples containing fluid inclusions for analysis, which includes heating to volatize the fluids and rupture the inclusion walls. Liberated vapor passes to an MS, which measures fluid composition for hydrocarbons, and other geochemical species such as H2S, CO2 acetic acid, and aromatics. Occasionally, a crude-oil fluid inclusion volume may be large enough to characterize the crude sufficiently to assess physical properties and the degree of biodegradation and thermal alteration. [32] Fluid inclusion stratigraphy, which uses included-fluid composition as the correlating parameter, has been proposed to assess the location of fluid contacts, identify migration pathways, characterize compartmentalization, and determine distance to pay zones. [31][32][33]

Drilling Engineering and Operations

There is significant overlap between data gathered for geological, petrophysical, and reservoir engineering needs vs. data gathered for the driller. Information about pore pressure, formation gas, and rock type and strength are an integral part of well planning. Continuously tracking these parameters as a well is drilled and comparing the actual data with what was used in the well plan allows for quick response by the driller when trouble occurs. It also allows the driller to "fine tune" his operations to optimize drilling performance, which is measured by drill rate, trouble time and cost, and delivery of well specifications (e.g., in terms of being a producing asset, an exploration well, or an appraisal well). We will leave these items in the "evaluation" bin, with the acknowledgement that they could just as easily be lumped into the drilling engineering category. This section discusses the data types and processes that are used to a large extent, and in some cases exclusively, by the driller.

Any measurable parameter that gives an indication of pore pressure provides the driller with an estimate of the degree of overbalance, which directly affects the rate of penetration (ROP). Mud weight will be adjusted to be within the desired window for a well’s particular set of drilling dynamics and rock strengths on the basis of modeled drill rate. The various measurements described in other sections of this chapter become important, to some degree, to the driller. These services may be provided by the mud logging contractor.

Weight on Bit And Rate of Penetration

These data are collected to indicate drilling performance. The driller would like to know how to predict his drilling or penetration rate. Bourgoyne et al.[34] describes several models that have been developed and used. Jorden[3] proposed modifying the Bingham model and defined a normalized parameter called the drilling exponent (the d-exponent):


where R = the penetration rate in ft/hr, N = the rotary speed in rpm, W = the weight on bit in Mlbf, and db = the bit diameter in inches. The d-exponent is sometimes corrected for mud density changes[35] by considering the effects of ρn, the mud density equivalent to a normal formation pore pressure, and ρe, the equivalent mud density at the bit while circulating:


Mud Pit Level

Indicators specify changes in the volume of mud in the pit. The total volume of mud changes continuously with depth as the hole volume increases. Rapid increases in pit volume may mean an influx of reservoir fluids, and well control measures may need to be implemented. A rapid decrease in volume indicates a downhole loss of mud, and lost-circulation material will probably be added to the drilling fluid.

Mud Chloride Content

Mud chloride content is monitored in all systems, along with the water content in nonaqueous drilling fluid systems. Significant changes in content may indicate influx of formation water, which means that an underbalance condition may be close, and mud weight may need to be increased.

Lithology and Mineralogy

Lithology and mineralogy may change as a fault is approached. Warmer water, with higher concentrations of dissolved salts, can flow along faults during some phases of their development. As the water moves into cooler zones, salts will precipitate, plugging pores and showing up in the cuttings. Indication of an approaching fault may warn of a potential jump across the fault, which, in some areas, is accompanied by a significant change in pore pressure. Advance knowledge of this allows the driller to adjust the mud weight before he encounters problems.

Total Gas

Concentrations in the drilling fluid returns indicate the degree of overbalance or underbalance between the equivalent mud density and the formation pore pressure. The total gas concentration measured while drilling shales establishes a baseline or background level that is useful in tracking pore pressure, with the assumption that the shale pore fluids are in equilibrium with any neighboring permeable sands.

Fig. 3F.11 indicates how trends of several parameters vary with pore pressure and depth. Monitoring and plotting these can give indications of the transition from normally pressured zones to geopressures. The ROP, drilling exponent, shale cutting density, and background total gas all follow a normal trend with depth. Attempts to calibrate these measurements directly to pore pressure have been somewhat successful and usually are on the basis of establishing the trend for normally pressured formations. When a deviation from the normal trend occurs, correlations specific to the basin or geographic region are used to estimate the formation pore pressure. Most logging companies offer pore pressure service, which requires experienced pore pressure engineers who, frequently through experience, add subjective input to the model as well as the objective parametric inputs.

While the accuracy of these particular methods will vary from site to site, such plots are extremely useful in identifying the transition into geopressures (i.e., when passing from normally pressured to abnormally pressured zones). At the transition to geopressures, the trend lines change slope. Because some of the changes may be subtle, looking at all the available data helps pinpoint the transition.

Connection Gas

As Sec. 3F.5.1 describes, connection gas is a good indicator of swabbing the wellbore at the bit (i.e., reducing the mud pressure at the bottom of the hole to below the pore pressure). If the pore pressure is less than the swabbed bottomhole pressure, little or no connection gas is seen. Some knowledge of the dynamic rheology of the drilling fluid is needed to perform input into a "swab model."

Normal Geothermal Gradient

The normal geothermal gradient may shift on transition into geopressures. Other thermal nomalies, such as proximity to subsurface salt bodies, may interfer with this phenomenon. A more thorough discussion of these techniques and their application to detect overpressure may be found in several references. [3][4][34][35]

Monitoring the Rate of Cuttings Return

As a formation is drilled, the cuttings should be circulated to the surface. Improper hole cleaning results in the downhole retention of cuttings, frequently as a cuttings bed on the low side of the hole in inclined wells. This causes an increased drag on the drillpipe and, if buildup is severe, may pack off the drillpipe, causing it to stick. Monitoring the rate of cuttings production from the drilling fluid returns indicates an approaching problem and warns the driller, which allows for remedial action before the pipe sticks. Watching for an increase in cuttings return rate can flag sloughing or extruding shale conditions, which call for an adjustment of mud density, as well as extreme washout conditions. Naegel et al.[36] describe a device for continuously weighing the cuttings as they come off the shaker screens and comparing this with what would be expected for a given ROP and mud pump rate.

Health, Safety and Environmental Considerations

Various parameters measured for formation evaluation and to monitor drilling operations and equipment are also indicators of conditions that could pose health, safety, and environmental concerns. Pore pressure changes that result in loss of well control pose obvious safety concerns. Any loss of control that results in a hydrocarbon release also poses serious environmental issues. Ambient monitoring for natural gas is done for health and fire safety. Monitoring hydrogen sulfide (H2S) is essential in areas in which the potential has been shown historically to exist, as well as in rank wildcat wells in which the characteristics of the geological basin are poorly known.

Hydrogen sulfide is detectable by GC but can not be measured with an FID. Thermal conductivity, MS, and solid state sensors detect H2S. The Delphian Mud Duck, which uses an electrochemical sensor, monitors dissolved H2S, HS-, and S2- ionic concentrations to give total sulfide content of the drilling fluid. This tool continuously follows sulfide trends before its concentration increases to the point that gaseous H2S is released from the mud. Draeger tubes are used for spot measurement of hydrogen sulfide, as a backup or as a check on other sensing equipment.


Bh = balance ratio
C1 = methane
C2 = ethane
C3 = propane
C4+ = butanes and heavier
C5+ = pentanes and heavier
Ch = character ratio
db = bit diameter, L, in.
dc = corrected drilling exponent, dimensionless
dexp = drilling exponent, dimensionless
N = rotary speed, rpm
q = mud pump flow rate, B/D
rg = residual gas
ro = residual oil
R = penetration rate, ft/hr
tan = lag time from the bit to surface, min
tdp = lag time in the drill pipe, min
ts = lag time in surface lines, min
tt = total elapsed pumping time from injection to measurement, min
Vdp = internal volume of the drillpipe and drill collars, bbl
Vs = internal volume of any surface lines tracer injection point to kelly, bbl
W = weight on bit, k-lbf
Wh = wetness ratio
ρe = equivalent mud density at the bit while circulating, m/L3, g/cm3
ρn = mud density equivalent to a normal formation pore pressure, m/L3, g/cm3


The author thanks Shell Intl. E&P Inc. for permission to publish this chapter and is very grateful to Geoservices, Datalog, and Halliburton for the help and advice he has had in gathering gas-sensing information. The reference list provides excellent sources for general information. [37][38][39][40][41][42]


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SI Metric Conversion Factors

ft × 3.048* E – 01 = m


Conversion factor is exact.