We analyze the Biot system solved with a fixed-stress split, Enriched Galerkin (EG) discretization for the flow equation, and Galerkin for the mechanics equation. Residual-based a posteriori error estimates are established with both lower and upper bounds. These theoretical results are confirmed by numerical experiments performed with Mandel's problem. The efficiency of these a posteriori error estimators to guide dynamic mesh refinement is demonstrated with a prototype unconventional reservoir model containing a fracture network. We further propose a novel stopping criterion for the fixed-stress iterations using the error indicators to balance the fixed-stress split error with the discretization errors. The new stopping criterion does not require hyperparameter tuning and demonstrates efficiency and accuracy in numerical experiments.

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CO2 capture and sequestration in subsurface reserves are expensive processes. Therefore flue gas can be directly injected into the oil and gas reservoirs to eliminate the cost of CO2 separation from power plant emissions and simultaneously enhance hydrocarbon production that may offset the cost of gas compression. However, gas injection in subsurface resources is often subject to poor volumetric sweep efficiency caused by low viscosity and low density of the injection fluid and formation heterogeneity. This paper aims to study gas mobility control techniques of water alternating gas (WAG) and foam in Cranfield via field-scale simulations. A coupled compositional flow and geomechanics simulator, IPARS, is used to accurately simulate the underlying physical processes. A hysteretic relative permeability model enables modeling local capillary trapping. Foam mobility control technique is examined to investigate the eminent level of CO2 capillary trapping by an implicit texture foam model. The coupled flow-geomechanics model can detect the effect of the plausible interaction of geomechanics and fluid flow on CO2 plume extension by analyzing the critical pressure that could induce hydraulic fracturing. Field-scale simulations indicate that during WAG and foam processes, the oil recovery increased 1.35 times and 1.6 times; and CO2 storage increased by 13.6% and 38.7% of total gas injection during the injection period compared to continuous gas flooding, respectively. During SAG process, coupling geomechanics will significantly increase the predicted gas storage volume, as a result of reservoir pore volume increase. Furthermore, analysis of the pressure margin for inducing hydraulic fracturing ensured the safety of SAG operation.

Tight oil resources have become increasingly important as massive hydraulic fracturing techniques breakthrough. Water flooding is generally applied to tight oil reservoirs; however, the oil recovery achieved by water flooding is quite low. A CO 2 miscible flooding process is regarded as a primary enhanced oil recovery (EOR) technique for conventional oil reservoirs as CO 2 can extract oil even at a high water cut. Furthermore, many CO 2 field trials in low permeability reservoirs have been recorded as successful. As CO 2 utilization efficiency drops when formation permeability goes down, CO 2 injection in a miscible condition for tight oil exploitation may not be as profitable as that in conventional oil reservoirs.In tight formations, there exist small pore throats, even at nanoscale. As the confined space in nanopores may shift a phase envelop and lower CO 2 minimum miscible pressure (MMP), operating a well in a near-miscible region where pressure is slightly less than MMP as measured in the lab may result in a good chance of miscibility for some parts of a tight oil reservoir.In this paper, equations of state (EOS) calculations are conducted in order to see the effects of confinement on a CO 2 injection process in tight oil reservoirs. On the basis of Cardium reservoir properties, numerical reservoir simulations are run to investigate the effects of confinement caused by a small pore throat size in 50 nm and 10nm on the CO 2 injection process. Comparisons of CO 2 near-miscible and miscible processes are made with various pore throat sizes. Results show that confinement effects in tight formations help to lower the bubble point pressure and boost an oil rate during CO 2 injection. However, CO 2 EOR efficiency goes down as formation pressure approaches MMP as mearsured in the lab. It is not necessary for CO 2 injection to operate in an above MMP condition in tight formations, where a nanopore size is present. In this way, the volume of CO 2 injected can be reduced. For tight oil reservoirs with a small pore throat size, a CO 2 near-miscible process is more suitable than miscible flooding.