Compaction and fluid migration in cretaceous shales of western Canada
Authors: Magara K 
Published: February 2016

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.