Abnormally High Fluid Pressure: Survey of Some Basic Principles: GEOLOGIC NOTES

Published hypotheses of the causes of abnormally high fluid pressure have not explored explicitly the relation between the present effective stress (σp) and the maximum effective stress (σm) to which a sediment has been exposed during its history. In basins where sediments are at their maximum burial depth, the present effective stress can be used to evaluate quantitatively different hypotheses of abnormal fluid pressure. The underlying assumption of this approach to hypothesis testing is that shale porosity is principally a function of maximum effective stress. “Nonequilibrium compaction” as a cause of abnormally high fluid pressure requires that σp = σm and predicts porosities that are higher than would be obtained if another cause, such as “aquathermal pressuring” or “clay transformation” (which require that σp < σm) were the predominant mechanism producing the same abnormally high fluid pressure. Observed porosities in Gulf Coast high pressure shale formations commonly are too low to be solely the result of nonequilibrium compaction. In two field examples, shale porosities predicted with the nonequilibrium compaction model are about 20 porosity units higher than porosities determined from γ – γ density logs and cores. In one example, a combined mechanism of nonequilibrium compaction and clay transformation is one possible, and internally consistent. Interpretation of the fluid pressure and porosity data. In the other example, the fluid pressure and pordsity data are consistent with clay transformation as the mechanism for the generation Of the abnormally high fluid pressure, but are not consistent with the nonequilibrium compaction model.