Mud logging, also known as hydrocarbon well logging or gas logging, entails gathering qualitative and semi-quantitative data from hydrocarbon gas detectors that record the level of natural gas brought up in the mud. Chromatographs are used to determine the chemical makeup of the gas.

Other properties such as drilling rate, mud weight, flowline temperature, oil indicators, pump pressure, pump rate, lithology (rock type) of the drilled cuttings, and other data are recorded. Sampling the drilled cuttings, usually under the direction of the wellsite geologist,  must be performed at predetermined intervals.

The main purpose is to identify all hydrocarbon indications from the rock samples and from the oil and gas entrained in the drilling mud. Gas detected in the mud can be interpreted to be:

  1. liberated gas
  2. recycled gas
  3. produced gas
  4. contamination gas
  5. trip gas

Only liberated gas indicates a possible prospect; the others merely confuse the analyst. This data, combined with the gas composition determined from a chromatograph, assists in the location of oil and gas zones as they are penetrated. The breakup of the gas shows into these categories reduces the chance of misinterpretation of a gas kick on the mud log.

Another important use of these logs is well safety, since overpressured zones, lost circulation, and
gas kicks will be recognized quickly and remedial action taken.

Total gas in the mud is measured in units of parts per million, but does not represent the actual quantity of oil or gas in the reservoir. Total gas is separated in a chromatograph. The most common gas component is methane (C1). Heavier hydrocarbons, such as  C2 (ethane), C3 (propane), and C4 (butane) may indicate an oil or a "wet" gas zone. Heavier molecules, up to C7 may be recorded. An example of a sample description log with the gas mud log is shown below.

Modern mud log with drilling mechanics, sample descriptions, and mud gas readings, showing two
potential gas zones.

Gas in the mud system may indicate the penetration of either an oil or a gas reservoir. The first objective is to detect the presence of the gas with some form of total gas detector. The second step is to break down the gas into its components with a gas chromatograph to see if the gas comes from an oil or gas show.

For many years the simple hotwire, or as it is properly called, catalytic combustion detector, has been the cornerstone of all gas detection service. This device was the first mechanical replacement for canaries in mines and is characterized by its simplicity and reliability.

Several other detecting devices have been utilized from time to time including the mass spectrometer, infrared analyzers, thermal conductivity, and gas chromatographs. Regardless of which gas detecting instrument is used, they are all limited by the amount of gas in the mud that can be extracted and fed into the instrument.

If gas is seen on the log in quantities larger than the average background, the question arises, "Is this a significant increase and does it indicate a gas or oil zone?" Similarly, "How much fluorescence in the cuttings indicates an oil zone?" The simple and quick answer to both of these questions is, "We don't know, yet!"

Generally speaking, extremely dry gas should give mostly C1 and not much C2, C3, or C4. If ratios are presented on the log, each of C1/C2, C2/C3, C1/C4, and C1/C5 will be greater than 50. Wetter gas will have ratios between 20 and 50. Oil zones will have ratios between 2 and 20. Local knowledge should be used to refine these cutoffs.

Spectroscope waveforms on computerized gas
 mud logging unit (Illustration courtesy
Petro Log International, Inc.

Usually, there is enough empirical control from offset well histories to make a positive interpretation, but there are so many variables involved that this is not always possible immediately. After drilling is completed, the mud log, sample log, open hole logs, and drill stem tests are used to come to a final analysis.

These results are used on the next hole in the same area as guides to more immediate interpretation on that well. To achieve the best possible interpretation, it is vital to integrate all of these tools at the very earliest point in the evaluation process. Integration of all the petrophysical data is the key to success.

To be useful, any log must be calibrated. Mud logs are no exception, and most modern mud logs have been calibrated to a local or API standard. However, many older logs in the well file have not. This makes it even more difficult to determine what the gas kicks mean.

Depth information is obtained from the driller's log, which records depth versus the time of day. However, these depths cannot be used directly. We wish the mud log data to be presented at the depth of the drill bit, but the mud log measurements are made at the surface. The time it takes for the mud to move from the bit to the surface must be accounted for in positioning samples and gas kick data on the log. This time is called the lag time and depends on the velocity of the mud in the annulus between the drill pipe and the rock. This in turn depends on the mud pump speed and displacement, which are usually constant for reasonable periods of time.

The lag time can vary from a few minutes in an air drilled hole, to hours in a deep mud filled hole. If lag time is much shorter than expected or multiple lags are found, it usually means a leak in the drill pipe which must be repaired immediately. The most reliable method of establishing the lag time is to use a tracing material such as oats, corn, paint, or calcium carbide. Carbide will produce a bubble of acetylene gas. Typically, a sample of tracing material is introduced into the drill pipe during a connection and circulated down through the bit jets and back up the annulus. The use of calcium carbide as a lag tracer has a secondary benefit. It permits verification that the entire gas detection system is functioning. Since it is necessary for the gas detector to extract, pump to the logging unit, and sense the acetylene gas, it verifies the integrity of the entire system.

This is only part of the story, as the time it takes the tracer to go down the inside of the drill pipe must first be calculated from the pump displacement, pump speed, pipe diameter, and pipe length. The calculated downward time is deducted from the total measured time to find the lag time.

The total gas detector provides the basic quantitative indication as to how much gas is being extracted from the drilling mud by the gas trap. Total gas detection and analysis equipment in use throughout the world
incorporates one of two standard detectors, the catalytic filament detector, also called a hotwire detector, and the hydrogen flame ionization detector.

Schematic diagram of a mud gas detection system for total gas.

The hotwire operates on the principle of catalytic combustion of hydrocarbons in the presence of a heated platinum wire at gas concentration below the lower explosive limit. The increasing heat due to combustion causes a corresponding increase in the resistance of the platinum wire filament. This resistance increase is measured through the use of a Wheatstone bridge circuit and recorded as "units of gas".

The common hotwire detector responds to all combustible gases. It is limited in its range since there must be sufficient oxygen present in the sample mixture to enable all of the hydrocarbons present to be catalytically oxidized by the platinum filament.

Schematic diagram of hotwire gas detector

The hydrogen flame ionization detector functions on the principle of hydrocarbon molecule ionization in the presence of a very hot hydrogen flame. These ions are subjected to a strong electrical field resulting in a measurable current flow, which is then amplified and recorded as "units of gas".

Detailed analysis of the hydrocarbon mixture is usually performed by a gas chromatograph. The principal difference between a total gas detector and a gas chromatograph is the partition column, which breaks the gas stream into its component parts.

Most oilfield gas chromatographs are rapid sampling, batch processing instruments that provide an accurate proportional analysis of the paraffin series of hydrocarbons from methane through pentane. Occasionally, special features are built into chromatographs to enable them to identify and measure hydrogen and various air components. The information produced by the chromatograph is reported in units or in mole percent of each component of the gas detected.

Schematic diagram of gas spectrometer, showing retention chamber to segregate the gases.

Gas chromatograph columns vary in design, but have several characteristics in common. They start with a long, small diameter, metal tube which is filled with a particulate material. This filling material is referred to as the solid phase or support phase. Its purpose is to provide a large surface area within the column. In many instances, a liquid phase is laid down over the surface of each of these grains or particles in order to increase its surface activity. It is desirable to have highly active surface characteristics so that there is a strong attraction between the various gas molecules and the surface of the support material.

The degree of attraction between the active surfaces of the column and the different gases passing through varies as a result of different physical and chemical characteristics. By selecting the proper column, it is possible to separate almost any suite of gases. Typically, oilfield chromatographs are designed to separate the paraffin series of hydrocarbons at room temperature, using air as a carrier.

The carrier gas applies the energy required to keep the molecules of a gas mixture moving through the column. It flows at a constant rate. Since each different molecule is attracted in different degrees to the the surface active material in the column, they will be propelled at different rates.

The time of transit for a given gas to pass through a particular column under specified flow conditions is referred to as the retention time. Retention time is the principle method of identifying various gases in a mixture. Since each column has different permeability characteristics, it is necessary that known gas standards be passed through the column and that their retention times be established if this analytical method is to be reliable.

The partition column separates a slug of gas into its components by delaying the passage of the heavier compounds. The amount of each component must still be detected by devices similar to the total gas detectors, or other more elaborate devices. Some are as simple as measuring the gravity of the gas coming out. Other common types involve measuring combustion ratios, thermal conductivity, and carbon content.

Since the retention times and response characteristics of each chromatograph are unique, it is necessary that standard blends of calibration gases be introduced into the instrument on a regular basis to establish the instrument's response characteristics. Once the response graph has been established for a particular instrument, then raw readings can be easily entered into the graph and read out in percent. With modern computer controlled equipment, the conversion factors are applied automatically.

Operators are often interested in detecting hydrogen sulfide for personnel safety or to initiate treatment to prevent deterioration of drilling equipment. Hydrogen sulfide in drilling mud has an erratic and detrimental effect on the continuous gas detector. H2S is easy to detect, however, and can be removed from the gas sample to prevent adverse effects without influencing hydrocarbon detection. A preset alarm indicator on the continuous H2S detector announces the presence of potentially dangerous concentrations. A quantitative determination of H2S in the air from any sample point may also be made for personnel safety and recorded on the driller's console and on the log.

Non-combustibles gases, such as helium, carbon dioxide and nitrogen, can be detected. Carbon dioxide may be detected in conjunction with logging for hydrocarbons on the continuous gas detector. By applying the steam still reflux unit and gas chromatography techniques, quantitative analyses for other non-combustible gases can be made.


Mud log from early 1980's.

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