Shale Rock Properties, Keys for Successful Dynamic
Modeling
of Hydrocarbon Migration
Okui, Akihiko 1
(1)Technical Evaluation Department,
Idemitsu Oil and Gas Co., Ltd., Tokyo, Japan.
In nature, slowest process controls the rate of whole process. In case of hydrocarbon migration, permeability for fine-grained rocks such as shale is much less than course-grained rock such as sandstone. Therefore, the permeability for shale should be main controlling factor on hydrocarbon migration in basins. Since hydrocarbon migration occurs as multi-phase fluid flow, relative permeability as well as capillary pressure is also important to evaluate and model the dynamic nature of hydrocarbon migration.
Static migration modeling
applying ray-trace and invasion
percolation ignores time effect and generally give optimistic result than
natural system. In natural system, the time required for the migration through
shale is long, and therefore the timing to reach traps should be delayed. In
addition, some of hydrocarbons should be lost during its migration. Leakage
through cap rock (seal) is generally evaluated by the balance between capillary
pressure for cap rock and buoyancy of migrating hydrocarbon. However, this is
also an evaluation on specific static condition, and can not be applicable to
dynamic system such as continuous hydrocarbon charge, overpressured reservoir
and so on.
It was found that absolute permeability, relative permeability and
capillary pressure have close relationships, since they are all controlled by
pore-throat size distribution of rocks. Among them, capillary pressure is
easiest to measure by mercury injection test, and therefore capillary pressure
curve is useful way to characterize the nature of multi-phase flow through shales.
Capillary pressures at certain saturation of non-wetting phase (ex. 5%)
collected from shales over the world have wide range, but it was found that the
plotting against porosity enables to group them by shale type (actually
mineralogy). This is because especially chemical compaction affects the
pore-throat size distribution of shales. Characterization of shales by above
way and application of the results to multi-dimensional basin modeling
enables
to model existing hydrocarbon accumulations and long distance migration in a
Southeast Asian basin.
AAPG Search and Discovery Article #90135©2011 AAPG International Conference and Exhibition, Milan, Italy, 23-26 October 2011.