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Cuttings analysis during mud logging

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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....................(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. [1] 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. [2] 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. [3][4][5] Swanson’s thorough summary[6] 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
  • Suspected caved material
  • 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
  • Porosity and oil shows

Standard abbreviations should be used in the description, as well as standard symbols as the log is being drawn. [6]

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.


q = mud pump flow rate, B/D
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


  1. Amen, R. 1994. Quantifying Hydrocarbon Shows Using On-Line Gas Referencing. Paper HH presented at the 1994 SPWLA Annual Logging Symposium, 19–22 June.
  2. Williams, R.D. and Ewing Jr., S.P. 1989. Improved Methods for Sampling Gas and Drill Cuttings. SPE Form Eval 4 (2): 167-172. SPE-16759-PA.
  3. Low, J.W. 1951. Examination of Well Cuttings. Quarterly of the Colorado School of Mines 46 (4) 46.
  4. Archie, G.E. 1952. Classification of Carbonate Reservoir Rocks and Petrophysical Considerations. AAPG Bull. 36 (2): 278-298.
  5. Dunham, R.J. 1962. Classification of Carbonate Rocks According to Depositional Texture. In Classification of Carbonate Rocks, W.E. Ham ed., Memoir 1, 108-121. Tulsa: AAPG.
  6. 6.0 6.1 Swanson, R.G. 1981. Sample Examination Manual. Tulsa, Oklahoma: American Assn. of Petroleum Geologists.

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See also

Mud logging

Hydrocarbon analysis during mud logging

Formation evaluation during mud logging