Alberta Research Council

About: Alberta Research Council is a based out in . It is known for research contribution in the topics: Coal & Oil sands. The organization has 1251 authors who have published 1336 publications receiving 40758 citations.

Nanoscale Gas Flow in Shale Gas Sediments

Abstract: 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 modelled 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.

Gas-water-rock interactions in Frio Formation following CO2 injection: Implications for the storage of greenhouse gases in sedimentary basins

Abstract: To investigate the potential for the geologic storage of CO2 in saline sedimentary aquifers, 1600 t of CO2 were injected at 1500 m depth into a 24-m-thick sandstone section of the Frio Formation, a regional brine and oil reservoir in the U.S. Gulf Coast. Fluid samples obtained from the injection and observation wells before CO2 injection showed a Na-CaCl‐type brine with 93,000 mg/L total dissolved solids (TDS) at near saturation with CH4 at reservoir conditions. Following CO2 breakthrough, samples showed sharp drops in pH (6.5‐5.7), pronounced increases in alkalinity (100‐3000 mg/L as HCO3) and Fe (30‐1100 mg/L), and significant shifts in the isotopic compositions of H2O, dissolved inorganic carbon (DIC), and CH4. Geochemical modeling indicates that brine pH would have dropped lower but for the buffering by dissolution of carbonate and iron oxyhydroxides. This rapid dissolution of carbonate and other minerals could ultimately create pathways in the rock seals or well cements for CO2 and brine leakage. Dissolution of minerals, especially iron oxyhydroxides, could mobilize toxic trace metals and, where residual oil or suitable organics are present, the injected CO2 could also mobilize toxic organic compounds. Environmental impacts could be major if large brine volumes with mobilized toxic metals and organics migrated into potable groundwater. The d 18 O values for brine and CO2 samples indicate that supercritical CO2 comprises ;50% of pore-fluid volume ;6 mo after the end of injection. Postinjection sampling, coupled with geochemical modeling, indicates that the brine gradually will return to its preinjection composition.