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.
|Published - 2018
|SPE Improved Oil Recovery Conference 2018 - Tulsa, United States
Duration: 14 Apr 2018 → 18 Apr 2018
|SPE Improved Oil Recovery Conference 2018
|14/04/18 → 18/04/18
Bibliographical noteFunding Information:
This work was supported by DOE grant FG02-04ER25617, NSF grant 1546553, and the Center for Frontiers of Subsurface Energy Security, an Energy Frontier Research Center funded by the U.S. Department of Energy, Office of Science, Office of Basic Energy Sciences under Award Number DE-SC0001114. The authors are thankful to Dr. John Killough from Texas A&M and Dr. Gurpreet Singh from the Center for Subsurface Modeling at The University of Texas at Austin for thoughtful discussions on hydrocarbon and flue gas phase behavoir, and to Dr. David DiCarlo for insightful discussions on foam properties. The authors acknowledge the Texas Advanced Computing Center (TACC) at The University of Texas at Austin for providing HPC resources that have contributed to the research results reported within this paper.
© 2018, Society of Petroleum Engineers.