Use resistivity as indicator of source rock maturity

John A. Morel
Foxpark Oil & Gas Consulting
Denver

The resistivity of various shale source rocks has been observed to increase with depth (Bakken, Barnett, Mowry, Niobrara, Woodford, etc.). This relationship can be explained by the retention of generated hydrocarbons in micropores. The generalized process requires: 1) a volume increase during conversion of kerogen to fluid hydrocarbons; 2) a rigid framework that provides a fixed volume of available pore space, and 3) micropores with micropermeability that retain hydrocarbon globules through capillary forces. The resistivity change is then a result of decreased water saturation.

The Mowry shale in the Powder River basin, Wyoming, is presented as a quantitative example for increasing resistivity as a function of progressive source rock maturity. The model is based on density decreases that occur during generation of fluid hydrocarbons from solids. Assuming conservation of mass, significant volume increases are predicted. Resistivity-depth data from over 300 wells along with 97 vitrinite reflectance data points were gathered to demonstrate the actual trends and verify the model. Observed values support the calculated model which can be generalized to many microporous, well lithified source rocks.

All methods used to back-calculate resistivity require volume percentages of porosity and hydrocarbon saturation.1 However, the percent of organic material reported in source rock analyses is a weight percent. The weight percent of organic material can be converted to volume percent if the rock matrix density, kerogen density, and pore volume are available (see table [136,107 bytes], this page ).

Estimates of rock matrix density for the Mowry shale are 2.66 to 2.71 gm/cc. This example uses 2.68 gm/cc. Reported kerogen densities range from 1.10 gm/cc for poorly solidified organics to 1.50 gm/cc for coals.2 This example uses 1.30 gm/cc. Observed Mowry porosity values are generally between 6.0% and 8.0%, all of which is micro- porosity. This example uses 7.0%. Reported values of organic material content range from 1.5% to 3.5%.3 This example uses 2.5%.

These choices put the rock framework matrix density at approximately twice the organic material density. These densities are used for the conversion of weight percentages to volume percentages. In this case the volume percentage of organic material is nearly twice its weight percentage. In many cases the volume of organic material calculates to be almost as large as the porosity.

The table on p. 72 outlines the procedure for converting weight percentage to volume percentage and contains the specific values modeled in this example.

Kerogen is transformed into hydrocarbon fluids through a wide array of chemical reactions. However, the resultant fluids have densities between 0.40 gm/cc and 0.90 gm/cc at normal formation pressures.4 This example uses 0.60 gm/cc approximating 30° gravity crude. Again, relative densities are used to calculate the volume of generated fluid from a specific volume of kerogen. As seen in the table, the density of the fluid hydrocarbon is roughly half the density of kerogen and therefore a constant mass doubles in volume.

During the generation process the percent of kerogen converted to fluid hydrocarbons increases. It starts at 0% prior to generation and continues to the 85% to 95% range before becoming burned out.5 6 This study modeled conversion percentages up to 80% in 10% increments.

As the hydrocarbons are generated they accumulate in micropores adjacent to the kerogen. They become trapped due to pore throat sizes in the 0.01 to 1.0 micron range.7 As calculated by Berg7 and shown by mercury injection profiles,8 the immiscible fluid entry (or exit) pressures are in excess of the fracture gradient.9 10 In the case of a compacted, lithified shale, the pores form a rigid framework. As the hydrocarbons accumulate in these micro-pores, hydrocarbon saturation increases, water is displaced from the pores by the trapped fluids, and the resultant water saturation decreases.

Water saturation is calculated as the amount of remaining pore water over the adjusted pore volume. Fig. 1 [72,134 bytes] shows that the water saturation drops to 38% at 80% conversion.

Archie's equation for lithified sandstone was used to back calculate the estimated resistivities. Shaley sand calculations are inappropriate because they attempt to focus on effective pore spaces where none exist. Fig. 1 also shows the range of calculated resistivities increasing from 8 ohm-m at 0% converted (100% Sw) to 58 ohm-m at 80% conversion (38% Sw).

This is the anticipated resistitivity response to progressive maturation of a shale source rock with no expelled hydrocarbons.

Well data

Data were gathered from more than 300 wells to develop the resistivity versus depth relationship. In general, five wide traverses were examined from east to west across the basin. Supplementary wells were included in the 8,000 to 12,000 ft range to improve statistical significance of the slope change.

There are 55 vitrinite reflectance values that were obtained for the Mowry in the Powder River basin. There were also 42 Rock Eval analyses.11 12 13 The Rock Eval data were calibrated to vitrinite reflectance values where possible and linearly interpolated.9 14 The resulting values were added to the graph of vitrinite reflectance and shown as diamonds and triangles.

Observations

The graph of Mowry resistivity versus depth for the Powder River basin does not increase uniformly ( Fig. 2 [75,926 bytes]). Rather, it has a pronounced increase in slope around 9,500 ft.

The maturity graph of vitrinite reflectance versus depth was drawn from a variety of sources reporting both vitrinite reflectance and converted Rock Eval data (Fig. 3 [81,848 bytes]). It also shows an increase in slope around 9,000 ft.

As described by the model, resistivity and source rock maturity are related.

Analysis

The vitrinite reflectance and resistivity data were then cross-referenced by depth and displayed ( Fig. 4 [82,661 bytes]). The plot contains quite a bit of scatter, but the trend is clear. The width of the ellipses approximates the range of resistivities and the height approximates the range of vitrinite reflectances. It indicates that resistivity begins to increase with the onset of oil generation, that 10 ohm-m is well within the oil window, and that values over 20 ohm-m are in the gas window.

The maximum observed resistivity of 58 ohm-m correlates to a calculated hydrocarbon saturation of 62%, which implies very low expulsion efficiency.

Conclusion

The data summarized from the Powder River basin Mowry formation support the model. The generation and build-up of interstitial hydrocarbons is reflected in increasing resistivity.

These calculations have broad implications not only for the Mowry, but for any compacted and well lithified source rock that presents a low porosity, rigid framework such as the Bakken, Barnett, Woodford, Niobrara, Chainman, Mancos, Cane Creek, and other source rocks.

An issue related to this analysis is that various primary migration mechanisms have been proposed to overcome pore throat restrictions. If these transport mechanisms result in significant leakage, no significant hydrocarbon saturation is achieved and the resistivity remains low.

Allowances must also be made for variations in kerogen and fluid hydrocarbon densities at reservoir conditions. Regional and local calibration is essential.

Finally, it has been shown that the Mowry expelled hydrocarbons into adjacent reservoirs. Both the hydrocarbon saturation and resistivity might have been higher without such expulsion.

References

1. Asquith, G.B., and Gibson, C.R., Basic well log analysis for geologists, AAPG, Tulsa, Okla., 1983.
2. Tissot, B.P., and Welte, E.H., Petroleum formation and occurrence, Springer-Verlag, New York, 1984, 699 p.
3. Davis, H.R., Byers, C.W., and Pratt, L.M., Depositional mechanisms and organic matter in Mowry shale (Cretaceous), Wyoming, AAPG Bull., Vol. 73, No. 9, 1989, pp. 1,103-16.
4. Standing, M.B., Volumetric and phase behavior of oil field hydrocarbon systems, SPE of AIME, Dallas, 1977.
5. Tissot, B., Durand, B., Espitalie, J., and Combaz, A., Influence of nature and diagenesis of organic matter in formation of petroleum, AAPG Bull., Vol. 58, No. 3, 1974, pp. 499-506.
6. Cooles, G.P., MacKenzie, A.S., and Quigley, T.M., Calculation of petroleum masses generated and expelled from source rocks, Organic Geochemistry, Vol. 10, 1986, pp. 235-245.
7. Berg, R.R., Capillary pressure in stratigraphic traps, AAPG Bull., Vol. 59, No. 6, 1975, pp. 939-956.
8. Wardlaw, N.C., Pore geometry of carbonate rocks as revealed by pore casts and capillary pressure, AAPG Bull., Vol. 60, 1978, pp. 245-257.
9. Waples, D., Organic geochemistry for exploration geologists, Burgess Publishing, Minneapolis, Minn., 1981.
10. Durand, B., Understanding of HC migration in sedimentary basins, Organic Geochemistry, Vol. 13, No. 3, 1988, pp. 445-459.
11. Burtner, R.L., and Warner, M.A., Hydrocarbon generation in Lower Cretaceous Mowry and Skull Creek shales of the northern Rocky Mountain area, in RMAG Guidebook, Meissner, F.F., ed., 1984.
12. Surdam, R.C., Zun Sheng Jiao, and Martinsen, R.S., in P. Ortoleva, ed., Basin compartments and seals, AAPG Memoir 61, 1995.
13. MacGowan, D.B., Zun Sheng Jiao, and Miknis, F.P., in P. Ortoleva, ed., Basin compartments and seals, AAPG Memoir 61, 1995.
14. Tissot, B.P., Pelet, R., and Ungerer, Ph., Thermal history of sedimentary basins, maturation indices, and kinetics of oil and gas generation, AAPG Bull., Vol. 71, No. 12, 1987, pp. 1,445-66.

The Author