AAPG Bulletin, v. 88, no. 2 (February 2004), pp. 193–211
ABSTRACT
Techniques for detection, evaluation, and prediction of pore pressures
in low-permeability rocks and equations for fluid-pressure
computations in most integrated basin-modeling software are based
on relationships between porosity and effective stress in shales.
However, recent data show that overpressured shales in the North
Sea do not exhibit higher porosities than the normally pressured
shales of the same formation at similar depths.
To further evaluate the existence of porosity vs. effective stress
relationships in shales, fluid-flow simulations and porosity modeling
in a typical high-pressure and high-temperature well in the North
Sea were undertaken. The parameters in the permeability and porosity
equations were adjusted until a satisfactory fit was achieved
between the observed and modeled porosity and fluid pressure at
present. However, the modeled porosity and pore pressure vs. depth
history of the sediments deviated significantly from known porosity
and pore pressure vs. depth relationships that have been observed in
North Sea shales and elsewhere today.
Because the results from basin modeling based on porositystress
relationships were unacceptable, irrespective of parameter
choices, and the well data from the North Sea show no signs of
elevated porosities in the overpressured shales, it is inferred that
effective stress-driven compaction alone has not generated the hard
overpressures observed in deeply buried North Sea shales. These
conclusions are suggested to be generally applicable to shales with
low porosities and hard overpressures worldwide, both because of
the physics involved and because similar results can be extracted
from published modeling in the Niger Delta.
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