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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 - αP, 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.

In slowly subsiding basins, there is no compaction disequilibrium. Pressures are regionally controlled by the surface topography. The persistence of high overpressures in thin (few meters thick), mature source rocks in the HC window implies uncommon conditions : a very rich source interval (total organic carbon content, TOC, >10%), a very low permeability (100-1,000 times smaller than for the Mahakam Delta or Gulf Coast shales), and, possibly, a very low porosity (2-3%). The examples examined suggest that permeability of shales in Paleozoic-Mesozoic, slowly subsiding basins are significantly more variable than in Cenozoic rapidly subsiding basins. More complex tectonic and diagenetic histories could explain this greater variability. Our study suggests that, at least at the regional scale considered, diagenetic processes do not need to be invoked in young rapidly subsiding basins. This does not exclude the possibility that locally permeabilities can be decreased if cementation takes place, resulting in an increase of overpressures. It is probable that more mature basins with intermediate sedimentation rates and ages, have mixed chemical and mechanical compaction mechanisms.

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