Applying wireline logs to estimate source rock maturity

Robert A. McTavish
Frontier Petroleum Services
St. Helier, Jersey, Channel Islands

The use of wireline logs to estimate source rock richness in petroleum geochemistry has received steady interest during the past 20 years,¹ but the estimation of source rock maturation from wireline logs has not progressed through the same period. Slimhole wireline logs were already used more than 20 years ago to evaluate coal deposits.^2-3 Quantitative determinations of coal maturation parameters, rank, density, moisture content, ash content and calorific value were possible, along with other coal properties of importance for coal mining.

In more recent years, interest in evaluation of coal-bed methane has brought an advance in the application of wireline logs to compute ash content, fixed carbon content, volatile matter, and moisture content of coal.⁴ This evaluation is based on the use of modern conventional wireline logging tools, especially the compensated neutron log (CNL), Natural Gamma Ray Spectroscopy (NGS) tool, and Litho-Density tool, and specific computer programs. Further coal analysis is based on use of the Geochemical Logging Tool (GLT) or Induced Gamma Ray Spectrometry (GST) tool. With these tools, the elemental composition of the coal can be analyzed. The GLT measurements can then be used with NGS, Litho-Density, and resistivity logs to determine the mineral content, which corresponds to the ash content.

Mineral content, fixed carbon content, and volatile matter are determined by means of the Elemental Log Analysis (ELAN) program. After this program has been run, coal rank can be estimated. With further adjustment of mineral content, using a component based on ash content, data from the bulk density and neutron porosity logs and carbon and oxygen content, the coal macerals can be identified and maceral content can be estimated.

The impressive achievements in evaluation of coal parameters, maceral content, and coal rank from wireline logs have not been matched yet in applications of petroleum geochemistry. However, this article describes two simple approaches to estimation of source rock maturation by wireline logs.

One method depends on direct correlation of vitrinite reflectance with sonic transit time (Dt, in msecs/ft or msecs/m). The second method is based on differential pressure as an indirect guide to maturation of source rocks. In this method, differential pressure is estimated from plots of Dt in shales by well established methods and the equivalent depth technique, described by many authors, among them Hottman and Johnson,⁵ Wichmann,⁶ and Fertl.⁷ Fertl⁷ has thoroughly discussed the advantages, pitfalls, and constraints in use of wireline logs to estimate formation pressures.

Vitrinite reflectance

As a guide to source rock maturation, vitrinite reflectance has been used. Vitrinite reflectance is one of the best documented and most widely used parameters of source rock maturation and coalification.⁸

The methods of preparation of vitrinite for reflectance analysis and investigation of vitrinite reflectance^8-11 are well established. Mean vitrinite reflectance in oil (Rmo%) in both argillaceous and carbonaceous shales of North Sea wells has been measured. The argillaceous shales are of Tertiary and Mesozoic age and the carbonaceous shales are from the Upper Carboniferous (Pennsylvanian). Although the vitrinite reflectance provides an excellent guide to the degree of source rock maturation, additional evidence of the type of organic matter (kerogen) is necessary to determine what type of hydrocarbons might be generated at a given measure of vitrinite reflectance.

At shallow depths, less than about 6,000 ft, in continuously subsiding basins, the relationship of the vitrinite reflectance to other physical factors may be compromised by bacteriological effects on the vitrinization process, where vitrinite reflectance (Rmo) is less than about 0.5%.

Sonic log correlation

Several types of log have been used in plots to determine the position and magnitude of abnormal pressures in well sections. These include electric logs, density logs, neutron logs, and sonic (acoustic) logs,^{6 7} but the preferred log has been the sonic (acoustic) log. For this reason, the sonic log has been favored in this study for correlation against vitrinite reflectance of argillaceous and carbonaceous shales from the North Sea. The argillaceous and carbonaceous shales differ in composition, age, and degree of compaction. Most argillaceous shale samples are from overpressured sections of the northern North Sea, while the majority of carbonaceous shale samples are from compacted sections in the southern North Sea. The differences are reflected in the curves of correlation of vitrinite reflectance against Dt, in msecs/ft (microseconds/ft), for each group of shales (Fig. 1 [60,581 bytes], Fig. 2 [62,623 bytes]). For the Paleozic carbonaceous shales (Fig. 1), Dt shale ranges from 65 to 90 msecs/ft. The value of 65 msecs/ft is probably the matrix transit time for carbonaceous shale. Vitrinite reflectance (Rmo%) ranges from 0.33 to 1.41%. In carbonaceous shales, the "oil maturation window" extends from about Rmo 0.6 to 1.3%.⁸ The correlation coefficient, r, is -0.948 for the line of Equation 1. The correlation curve for argillaceous shales (Fig. 2) differs from that for the carbonaceous shales. The values of Dt shale range from 72 to 140 msecs/ft, but it is not certain that the matrix transit time for argillaceous shale has been reached. The range of vitrinite reflectance (Rmo%) in the argillaceous shales is from 0.33 to 1.54%. The range of the "oil maturation window" may differ slightly from that of carbonaceous shales, depending on the kerogen type, so that the lower limit may extend to about Rmo 0.5%.⁸ The value of r, -0.956, is also very high, for the line of Equation 2. Despite excellent correlations of vitrinite reflectance to Dt for carbonaceous shales and argillaceous shales of the North Sea, these correlations have been derived empirically. Thus, they may not be as applicable globally with the same precision. As the values of Dt shale relative to values of Rmo% may differ greatly for different shale compositions, the vagaries of shale composition, such as carbonate or clay content, may call for local adjustments, basin by basin or within a basin. Nevertheless, high correlation coefficients may be repeated in local calibrations. Further calibration should lead to separate correlation curves for shales with calcareous, argillaceous, and carbonaceous end members, that might be applicable across a wide range of geology in time and space.

Differential pressure

Retardation of source rock maturation in overpressured sequences had been recognized about 20 years ago.¹² However, the process of retardation was described only recently.¹³ It was shown that maximum differential pressure imposed on a rock has a marked effect on retardation, through its influence on porosity reduction, according to Equation 3. Differential pressure is defined relative to lithostatic pressure and pore pressure, expressed in pounds per square inch, in Equation 4. The correlation coefficient, r, between differential pressures, of 84.5 to 380.⁷ bars (1 bar = 14.5 psi), and vitrinite reflectance, of Rmo 0.31 to 1.54%, (Fig. 3 [49,471 bytes]) is 0.978 for the line of Equation 5. To estimate differential pressure, a plot of log Dt shale vs. depth is prepared for a well section, as described by Fertl.⁷ From this plot, a compaction curve is derived that corresponds to the compaction at normal hydrostatic pressure. The departures of Dt shale from this curve can be used to estimate differential pressures by the equivalent depth method.⁷ Using the resultant estimates of differential pressure, porosity at a sample point (fz) is calculated according to Equation 3. For simplicity, the lithostatic pressure gradient is taken as 1 psi/ft. In reality, the lithostatic pressure gradient is less than 1 psi/ft at depths less than about 6,000 ft in continuously subsiding basins. However, more precise measurements of lithostatic pressure can be made with a density log.

The differential pressure of Equation 4 in a normally pressured sequence can be calculated from Equation 6. In an overpressured sequence, Pd, is the same as that at equivalent depth, ze, in the normally pressured sequence. The equivalent depth is the depth in a normally pressured sequence at which differential pressure is the same as that at a given depth in the overpressured sequence. It is at the base of a normally pressured sequence immediately above an overpressured sequence, with gradual build up of overpressure. If seal is sound, differential pressure may remain constant through the overpressured interval. However, the differential pressure will gradually increase, to approach that of a normally pressured sequence, if the seal is imperfect.

The differential pressure can be estimated using either the FPS or metric units, but the calculation of thermal properties is discussed in terms of metric and SI units. From the differential pressure and thermal conductivity of a rock at standard temperature (293° K.) and a given porosity, the thermal conductivity at a depth, z, and temperature, Tz, at the sample point, can be calculated from Equation 7.

The value of Tz is interpolated from temperature control from formation test temperatures or from temperatures estimated from log bottomhole temperatures by established methods^14-16 based on Homer type plots. These temperatures may be in degrees Fahrenheit or Celsius, but they must be in degrees Kelvin in Equation 7.

Heat flow (q) through a source rock system of an interval at depth z (z-z₁) can be expressed in two ways.¹³ Firstly, q is determined from Equation 8, where heat transfer is by conduction and flow of heat is vertically upwards. Secondly, heat flow over thick intervals, as in a well or thick formation, can be derived from Equation 9.^17-19

An important geothermal property for geochemical purposes is the cumulative heatflow, Q13. This is the heat transfer from To, taken as 0° K., to Tz, at given depth, z. It is a measure of cumulative heat flow in a pressure-temperature system at depth, z. The value of Q is determined from Equation 10. This equation is important for source rock maturation, as it remains constant for given values of differential pressure and vitrinite reflectance in a given rock. As Q can be taken as a measure of the heat added to a pressure-temperature system of rock at depth, z, and constant absolute temperature, T (°K.), it could be expressed as DQ. Now DQ/T is a basic measure of change in entropy, where T is the constant absolute temperature at the point in a pressure-temperature system to which heat is transferred; DQ is the quantity of heat added or removed; and DS is the change in entropy.²⁰

Cumulative heat flow, Q, also reflects the heat content of unit volume of source rock for unit time in a thermodynamic system. It corresponds to enthalpy (H) for a given system at specific conditions. For a specific enthalpy, H, vitrinite reflectance will be constant due to the internal chemistry of the vitrinite. As enthalpy, H, is effectively cumulative heat flow, Q, it may be comparable to the free energy of the system, U, which is related to the free energy of a substance. Further, the enthalpy at 298° K. defines the standard heat of formation of a compound at standard conditions of temperature and pressure, 298° K. and 1 atm (14.7 psi or 0.1013 MPa). Thus a value of Q defines the physical conditions at which a specific chemical reaction may take place in a source rock system. The chemical reaction in this study concerns change in vitrinite composition at physical conditions that can also be defined in terms of the temperature and differential pressure.

Implications

High orders of correlation have been demonstrated for vitrinite reflectance relative to sonic transit times (Dt) and to log-derived differential pressures (Pd). However, these correlations relate to specific lithologies from a single basin, so it may still be too early to apply the correlations of Table 1 [186,472 bytes] globally. Nevertheless the values of the methods have been demonstrated, but more local calibrations should be attempted, with special attention to types of lithology. Thus coverage of correlation and the statistical expression of source rock parameters relative to wireline logs would be strengthened.

The value of these methods is that they provide "quick look" methods of estimating source rock maturation from wireline logs in wells that have not been examined previously for geochemistry. Thus, added "infill" data can be derived for geochemical mapping. However, more data on type of organic matter would be needed to predict the type of hydrocarbon that might have been generated from source rock in specific conditions of temperature and differential pressure. For exploration, the most useful application of these methods could be the simple identification of the "immature," "mature," and "'overmature" source rocks in wells with sonic logs but no geochemical data.

An important corollary of these wireline log methods of estimating source rock maturation is the possibility of extending the methods to seismic data. The use of seismic data to estimate pore pressure has a long history and mixed success.^{7 21 22}

Since these early papers appeared, improved resolution of seismic data and refinement of velocity modeling have enhanced the possibility for relating seismic data to source rock maturation more precisely. Further, use of sonic logs and density logs to generate synthetic seismograms has been based on the close relationship of data from sonic and density logs to seismic data. These data are interrelated on theoretical bases.

Seismic modeling of source rock maturation is not expected to yield precise estimates of source rock maturation. However, the ability to determine whether potential source rocks are "immature," "mature," and "overmature" at an early stage in exploration could improve early appraisal of acreage potential.

References

1. Stocks, A.E. and Lawrence, S.R., Identification of source rocks from wireline logs, in Hurst, A., Lovell, M.A. and Morton, A.C., eds., Geological Applications of Wireline Logs, Geol. Soc., Spec. Pub. 48, 1993, pp. 241-242.
2. Reeves, D.R., In-situ analysis of coal by borehole logging techniques., Trans. Can. Inst. Mines, LXXIV, 1971, pp. 61-69.
3. Lavers, B.A. and Smits, L.J.M., Recent developments in coal petrophysics, Trans. 4th European Symposium, SPWLA London, Paper G, 1976, pp. 1-23.
4. Ayoub, J., Colson, L., Hinkel, J., Johnston, D., and Levine, J., Learning to produce coalbed methane. Oilfield Review, Vol. 3, No. 1, 1991, pp. 27-40.
5. Hottman, C.E., and Johnson, R.K., Estimation of formation pressures from log-derived shale properties. J. Petrol. Technol., Vol. 17, 1965, pp. 717-723.
6. Wichmann, P.A., A review of the use of logs to determine abnormal pressures, Trans. 3rd European Symposium, SPWLA London, Paper S, 1974, pp. 1-16.
7. Fertl, W.H., Abnormal formation pressures, Elsevier, Amsterdam, 1976.
8. Robert, P., Organic metamorphism and geothermal history, Reidel, Doordrecht, 1988.
9. Murchison, R. G., Some recent advances in coal petrology, C. R. 6eme Congr. International de Strat. Geol. Carbonifere, Vol. I, 1969, pp. 351-367.
10. Cooper, B.S., Estimation of the maximum temperatures attained in sedimentary rocks, in Hobson, G.D., ed., Developments in petroleum geology, Applied Science Publishers, London, 1977, pp. 127-146.
11. Bostick, N.H., Microscopic measurement of the level of catagenesis of solid organic matter in sedimentary rocks to aid exploration for petroleum and to detennine burial temperaturesa review. SEPM Spec. Pub. 26, 1979, pp. 17-43.
12. McTavish, R.A., Pressure retardation of vitrinite diagenesis, offshore northwest Europe, Nature, 271, 1978, pp. 648-650.
13. McTavish, R.A., The role of overpressure in retardation of maturation of organic matter, Jour. Petrol. Geol., Vol. 21, No. 2, 1998, in press.
14. Timko, D.J., and Fertl, W.H., Implications of formation pressure and temperatures in the search and drilling for hydrocarbons, 4th. Can. Well Logging Symposium, Paper E, 1972, pp. 1-10.
15. Dowdle, W.L. and Cobb, W.M., Static formation temperature from well logsan empirical method. J. Petrol. Technol., Vol. 27, 1975, pp. 1,326-30.
16. Fertl, W.H., and Wichmann, P.A., How to determine static BHT from well log data, World Oil, 1977, pp. 105-106.
17. Evans, T.R., Thermal properties of North Sea rocks, Log Analyst, Vol. 18, 1977, pp. 3-12.
18. Oxburgh, E.R., and Andrews-Speed, C. P., Temperature, thermal gradients, and heat flow in the Southwestern North Sea, in Illing, L.V., and Hobson, G.D., Petroleum geology of the continental shelf of northwest Europe, Heyden and Son, London, 1981, pp. 141-151.
19. Brigaud, F., Chapman, D.S., and Le Douaran, S., Estimating thermal conductivity in sedimentary basins using lithologic data and geophysical well logs, AAPG Bull., Vol. 74, 1990, pp. 1,459-77.
20. Spalding, D.B. and Cole, E.H., Engineering Thermodynamics (3rd Edition), Edward Arnold and ELBS, London, 1982.
21. Pennebaker, E.S., An engineering interpretation of seismic data, SPE Paper 2165, AIME 43rd Ann. Fall Meeting, Houston, 1968.
22. Reynolds, E.B., Predicting overpressured zones with seismic data. World Oil, Vol. 171, October 1970, pp. 78-82.

The Author

Rob McTavish has been a consultant in petroleum exploration and production geology since 1978. Previously he worked with West Australian Petroleum Pty. Ltd. and Conoco in various geological positions.

He holds MSc and PhD degrees in geology from the University of Western Australia.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.