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Formation evaluation during mud logging

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Formation evaluation, for this discussion, is the process of:

  • Describing a geologic formation and any fluids contained within in terms of their constituent properties
  • Determining the properties of the rock to assess the total and recoverable volume, value, and producibility of the fluids
  • 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. [1][2][3][4] The modified Pixler method, [2] for example, plots ratios of methane (C1) to, respectively, ethane (C2), propane (C3), butanes and heavier (C4+), and pentanes and heavier (C5+):




and RTENOTITLE....................(4)

Through a correlated analysis, ranges of these ratio values had been determined that were representative of productive and nonproductive gas and oil (see Fig. 1).

The Haworth et al. "wetness" method[3] defines several correlatable ratios: wetness, Wh; balance, Bh; and character, Ch.




The values of these ratios determine, through the interpretation shown in Fig. 2, 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, [5][6] 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[7] or involve spectroscopy techniques to get particular spectra and correlating these to oil properties or type. [8][9]

The QGM™ process[10] 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[9] 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. [11][12][13][14] 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[15] 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

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. [16][17][18] 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. [19] 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
  • 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. [20] 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. [19][20][21]


Bh = balance ratio
C1 = methane
C2 = ethane
C3 = propane
C4+ = butanes and heavier
C5+ = pentanes and heavier
Ch = character ratio
Wh = wetness ratio


  1. Pixler, B.O. 1969. Formation Evaluation by Analysis of Hydrocarbon Ratios. J Pet Technol 21 (6): 665-670. SPE-2254-PA.
  2. 2.0 2.1 Ferrie, G.H., Pixler, B.O., and Allen, S. 1981. Well-Site Formation Evaluation by Analysis of Hydrocarbon Ratios. Presented at the 1981 Annual Technical Meeting of the Petroleum Society of CIM, Calgary, 3–6 May.
  3. 3.0 3.1 Haworth, J.H., Sellens, M., and Whittaker, A. 1985. Interpretation of Hydrocarbon Shows Using Light (C1-C5) Hydrocarbon Gases from Mud-Log Data. AAPG Bulletin 69 (8): 1305-1310.
  4. Whittaker, A. and Sellens, M. 1987. Analysis Uses Alkane Ratios from Chromatography. Oil & Gas J. (18 May): 42.
  5. Whittaker, A. and Sellens, G. 1987. Normalization of Gas Shows Improves Evaluation. Oil & Gas J. (20 April): 53.
  6. Amen, R.M. 1995. Technique Uses Reference Gas to Assess HC Shows. The American Oil & Gas Reporter (April): 57.
  7. Wright, A.C. 1996. Estimation of Gas/Oil Ratios and Detection of Unusual Formation Fluids from Mud Logging Gas Data. Paper CC presented at the 1996 SPWLA Annual Logging Symposium, 16–19 June.
  8. Delaune, P.L. 1992. Surface Techniques to Measure Oil Concentrations While Drilling. Paper KK presented at the 1992 SPWLA Annual Logging Symposium, June.
  9. 9.0 9.1 Delaune, P.L., Spilker, K.K., Hanson, S.A. et al. 1999. Enhanced Wellsite Technique for Oil Detection and Characterization. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1999. SPE-56802-MS.
  10. Wright, A.C., Hanson, S.A., and Delaune, P.L. 1993. A New Quantitative Technique for Surface Gas Measurements. Paper A presented at the 1993 SPWLA Annual Logging Symposium, 13–16 June.
  11. Low, J.W. 1951. Examination of Well Cuttings. Quarterly of the Colorado School of Mines 46 (4) 46.
  12. Archie, G.E. 1952. Classification of Carbonate Reservoir Rocks and Petrophysical Considerations. AAPG Bull. 36 (2): 278-298.
  13. 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.
  14. Swanson, R.G. 1981. Sample Examination Manual. Tulsa, Oklahoma: American Assn. of Petroleum Geologists.
  15. Boone, D.E. 1985. Gas Volumetric Analysis. Petroleum Engineer Intl. (August).
  16. Beeunas, M.A. et al. 1996. Application of Gas Geochemistry for Reservoir Continuity Assessment, Gulf of Mexico. Presented at the 1996 AAPG/EAGE Research Symposium on Compartmentalized Reservoirs: Their Detection, Characterization and Management, 20–23 October.
  17. Ehrenberg, S.N. and Siring, E. 1992. Use of Bulk Chemical Analyses in Stratigraphic Correlations of Sandstones: An example from the Statfjord Nord Field, Norwegian Continental Shelf. J. of Sedimentary Petrology 62 (2): 318-330.
  18. Pearce, T.J. and Jarvis, I. 1992. Applications of Geochemical Data to Modeling Sediment Dispersal Patterns in Distal Turbidites: Late Quaternary of the Madeira Abyssal Plain. J. of Sedimentary Petrology 62 (6): 1112-1129.
  19. 19.0 19.1 Hall, D., Shentwu, W., and Sterner, M. 1997. Using Fluid Inclusions to Explore for Oil and Gas. Hart’s Petroleum Engineer Intl. (11): 29.
  20. 20.0 20.1 Hall, D.L., Bigge, M.A., and Jarvie, D.M. 2002. Fluid Inclusion Evidence for Alteration of Crude Oils. Presented at the 2002 AAPG Annual Meeting, Houston, 10–13 March.
  21. Barclay, S.A. et al. 2000. Assessment of Fluid Contacts and Compartmentalization in Sandstone Reservoirs Using Fluid Inclusions, An Example from the Magnus Oil Field, North Sea. AAPG Bull. 84 (4): 489-504.

Noteworthy papers in OnePetro

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See also

Mud logging

Hydrocarbon analysis during mud logging

Cuttings analysis during mud logging

Formation testing while drilling (FTWD)