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Oil Saturation in Shales: Applications in Seal Evaluation

By
R. A. Noble
R. A. Noble
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;
J. G. Kaldi
J. G. Kaldi
Atlantic Richfield Indonesia Inc. Jakarta, Indonesia
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;
C. D. Atkinson
C. D. Atkinson
ARCO British Ltd. Guildford, Surrey, United Kingdom
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Published:
January 01, 1997

Abstract

A procedure has been developed to quantify oil saturation in the pore system of shales. The technique uses geochemical and rock property measurements of core samples (solvent extract yield, porosity, densities, and kerogen sorption capacities). The method takes into account the fact that many shales contain indigenous organic matter (kerogen) and that free hydrocarbons extracted from the shale may originate either from the sorbed fraction of the kerogen/mineral matrix or from residual hydrocarbons within the intergranular pore system. A study of the Eagleford Formation from east Texas shows that mineral surfaces of the shale most likely remain water wet and that residual oil saturation (S0) of the intergranular pore system attains the highest values during the intense zone of oil generation (calculated So = 15 to 70%). The saturation values are examined as a function of burial depth and organic richness to establish typical trends for shales undergoing normal maturation. Relationships between pore saturations and Rock-Eval S1/TOC (total organic carbon) ratio are established so that the concepts can be applied in cases where only Rock-Eval data are available. Samples with S1/TOC ratios >120 mgHC/gC may contain some nonindigenous hydrocarbons, and those with values >200 mgHC/gC almost certainly do. These values were used to evaluate the residual oil contents and seal performance of various fine-grained rock facies. A case study from the Talang Akar Formation, Indonesia, shows that seal rocks with high entry pressures (from mercury injection capillary pressure [MICP] analysis) have low hydrocarbon contents in the range expected for in-situ generation. However, shales with the lowest entry pressures have very high hydrocarbon (HC) contents, indicating impregnation of the pore system with oil from an underlying accumulation. In such samples, the seal rock has most probably attained equilibrium with the maximum oil column height it was capable of supporting. The method complements existing mercury injection capillary pressure (MICP) measurements of seal capacity, and provides a rapid means for detecting seal failure or poor-quality reservoir “waste zones.”

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Contents

AAPG Memoir

Seals, Traps, and the Petroleum System

R.C. Surdam
R.C. Surdam
Institute for Energy Research University of Wyoming Laramie, Wyoming
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American Association of Petroleum Geologists
Volume
67
ISBN electronic:
9781629810775
Publication date:
January 01, 1997

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