Production of gas out of low permeability shale packages is very recent in the Western Canadian Sedimentary Basin (WCSB). The process of gas release and production from shale gas sediments is not well understood. Because of adsorptive capacity of certain shale constituents, including organic carbon content, coalbed methane models are sometimes being applied to model and simulate tight shale gas production behaviour. Alternatively, conventional Darcy flow models are sometimes applied to tight shale gas. However, neither of these approaches takes into account the differences in transport mechanisms in shale due to additional nanopore networks. Hence, the application of existing models for shale results in erroneous evaluation and predictions. Our analysis shows that a combination of a nanopore network connected to a micrometre pore network controls the gas flow in shale. Mathematical modelling of gas flow in nanopores is difficult since the standard assumption of no-slip boundary conditions in the Navier-Stokes equation breaks down at the nanometre scale, while the computational times of applicable molecular-dynamics (MD) codes become exorbitant. We found that the gas flow in nanopores of the shale can be modeled with a diffusive transport regime with a constant diffusion coefficient and negligible viscous effects. The obtained diffusion coefficient is consistent with the Knudsen diffusivity which supports the slip boundary condition at the nanopore surfaces. This model can be used for shale gas evaluation and production optimization.
Shale gas is a type of reservoir classified under the Unconventional Gas heading. These ‘difficult to produce’ reservoirs will play an increasingly important role in Canadian gas production because they are showing the potential to offset declining conventional gas production.
Quite simply, shale gas is natural gas produced from shale sequences. Gas shales are predominantly lithified clays with organic material and detrital minerals present in varying amounts. Organic matter is an integral constituent of a productive shale gas reservoir. In addition, these fine-grained rocks are microporous, causing low permeabilities.
While shale gas production has had a long history in the United States, dating back about 80 years, it is still at the very early stages of commercial production in Canada. Very little public data exists on shale gas production, yet industry interest is on the rise. A variety of estimates indicate that between 550 and 860 trillion cubic feet of gas-in-place could exist in potential shale gas formations in Western Canada(1,2).
But shales can be difficult to evaluate using conventional laboratory techniques. Much of this has to do with resident clays that can have bound water either as part of their matrix or loosely bound in the interlayers in amounts of 75 to 80%. Another challenge can be the accurate measurement of in situ permeabilities, which are on the nanoscale. Core samples have often been subjected to coring induced or stress release fractures, resulting in greatly overstated permeability measurements.
While some shales in Western Canada are, at this early stage, showing the proper geochemical and reservoir properties to support gas production, new techniques need to be developed to more accurately understand shale properties and their productive potential.