Chapter from:
AAPG Memoir 67: Seals, Traps, and the Petroleum System, Edited
by R. C. Surdam, p. 13-29
(Publication Subject: Oil Methodology, Concepts)
AAPG Memoir 67: Seals, Traps, and the Petroleum System. Chapter 2: Oil Saturation in Shales: Applications in Seal Evaluation, by R.A. Noble, J.G. Kaldi, and C.D. Atkinson
Copyright © 1997 by The American Association of Petroleum Geologists. All rights
reserved.
Chapter 2
Oil Saturation in Shales: Applications in Seal
Evaluation
by
R.A. Noble
J.G. Kaldi
Atlantic Richfield Indonesia Inc. Jakarta, Indonesia
C.D. Atkinson
ARCO British Ltd.Guildford, Surrey, United Kingdom
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 (So) 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
