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Chapter from:
AAPG Memoir 70: Abnormal Pressures in Hydrocarbon Environments
Edited by B.E. Law, G.F. Ulmishek, and V.I. Slavin
Copyright © 1998 by The American Association of Petroleum Geologists. All rights reserved.
Memoir 70, Chapter 3: Overpressure Models for Clastic Rocks, Their Relation to Hydrocarbon, by Jean Burrus, Pages 35 - 63

Jean Burrus¹
IFP, Rueil Malmaison, France
¹Present Affiliation: Beicip-Franlab, Rueil Malmaison, France

Abstract

The purpose of this paper is to review advances made in our understanding of the origin of overpressures in clastic rocks and examine the relationship between overpressuring and hydrocarbon expulsion. This study uses numerical simulations to examine overpressure models in clastic rocks. It is based on a review of previous regional overpressure modeling studies in rapidly subsiding basins (the Mahakam Delta, Indonesia, and the Gulf Coast, U.S.A.), and in slowly subsiding basins (the Williston Basin, U.S.A.-Canada and the Paris Basin, France). We show that compaction models based on effective stress-porosity relations satisfactorily explain overpressures in rapidly subsiding basins. Overpressures appear primarily controlled by the vertical permeability of the shaly facies where they are observed. Vertical permeabilities required to model overpressures in the Gulf Coast and Mahakam basins differ little, they are around 1-10 nanodarcies. Geological evidence and models suggest other causes of overpressure such as aquathermal pressuring or clay diagenesis to be generally small compared with compaction disequilibrium. Hydrocarbon (HC) generation can be a minor additional cause of overpressures in rich, mature source rocks. Shale permeabilities calibrated against observed overpressures appear consistent with direct measurements. Specific surface areas of mineral grains and relationships between effective stress/permeability implied by model calibrations agree with independent experimental determination. The main weakness of mechanical compaction models is that they overestimate the porosity of thick overpressured shales. Unlike in previous studies, we suggest that this mismatch is not caused by fluid generation inside overpressured shales. Instead, we infer that it is a consequence of an inappropriate definition of effective stress. If effective stress is defined as S - aP, instead of S - P, then with a around 0.65-0.85, porosity reversals predicted in overpressured shales are much reduced, and better in agreement with observations. Alpha (a) is known in poro-elasticity as the Biot coefficient. We show that the non-linear distribution of horizontal stress often observed in overpressured shale sequences confirms values of the Biot coefficient in the range indicate above.