| Abstract | Shale porosity distributions within Cretaceous and Tertiary rocks of the Alberta and Saskatchewan subsurface have been determined by the use of sonic and formation density logs, and the examination of
cores and surface rock samples. At shallow depths, shale porosity appears to be related exponentially to depth. Porosity at depth in Cretaceous shales, especially in the western part of the area studied, tends to be greater than the porosity-depth
trend established at shallower depths would suggest, and is associated with anomalously high fluid pressure conditions. Fluid pressure gradients in shales can be determined by the porosity distribution, as derived from sonic logs, of incompletely
compacted shales. Differing permeabilities in shales may be estimated through use of the fluid pressure gradient and Darcy's law. Calculated shale permeabilities and porosity values can then be integrated to establish a subsurface interrelationship.
This method of analysis, applied to Cretaceous shales in the subsurface of Alberta and Saskatchewan, reveals that the permeability increases less with increase in porosity than the amount given by Archie's relation, which is based on sandstone and
carbonate rocks. This calculated porosity-permeability relationship for shales has been verified in numerous other studies by laboratory measured porosity and permeability data. Anomalously high-pressures in the deep subsurface can be explained by
fluid expulsion mechanisms related to compaction of shales. The volume of fluids which should be expelled from shales in unit time to reach compaction equilibrium may be determined for several different rates of sedimentation, based on the shale
porosity data in western Canada. For each rate of sedimentation or subsidence there is a minimum permeability for reaching compaction equilibrium, which may be calculated according to Darcy's law. Comparison of this calculated minimum permeability
with actual shale permeabilities, determined by laboratory measurements, suggests that, at relatively shallow depths, shale usually should be permeable enough to permit the attainment of compaction equilibrium and to maintain normal hydrostatic
pressure. At depth, however, actual permeabilities are less than the calculated minimum necessary for compaction equilibrium, so that abnormal pressures may occur; the incidence of such abnormal pressures should increase with increases in the rate of
sedimentation and in the total thickness of the sequence. Shale porosity distribution in incompletely compacted shale zones also may be affected by the permeability and the extent of adjacent sandstone or carbonate rock bodies. A sharp decrease of
pcrosity in shales close to such rock bodies would suggest that relatively large volumes of fluids have been expelled from the shales into the adjacent sandstones or carbonates. If this expelled fluid volume is large, the possibility of hydrocarbon
accumulation in such sandstone or carbonate rocks is considered to be favorable. To illustrate such a study, Cretaceous shales associated with hydrocarbon reservoirs in the subsurface of northwestern Alberta and northeastern British Columbia has been
examined. Most Mesozoic oil and gas pools in this area are concentrated where a large volume of fluids is considered to have been expelled downward from the overlying shales. To obtain laboratory data on compaction and fluid expulsion relationships,
a number of experiments were conducted on several kinds of clays. The results yielded porosity distributions similar to those of Cretaceous shales in the subsurface of western Canada. |