Coupled reservoir flow and geomechanics has numerous important applications in the oil & gas industry, such as land subsidence, hydraulic fracturing, fault reaction and hydrocarbon recovery etc. High fidelity numerical schemes and multiphysics models must be coupled in order to simulate these processes and their interactions accurately and efficiently. Specifically, in the applications of CO2 sequestration, the effect of geomechanics on carbon storage estimation is not negligible. However, coupled flow-geomechanics simulations are very computationally expensive and most of the computational time is usually spent for geomechanics calculations. This paper investigates a three-way coupling algorithm that uses an error indicator to determine when displacement must be updated and whether fixed-stress iterative coupling technique is required. Numerical experiments with coupled nonlinear single-phase flow and linear poromechanics shows that the three-way coupling algorithm can speed up 4 times comparing to fixed-stress iterative coupling algorithm. Extensions to coupled compositional flow with poromechanics also shows a speed-up for 5 times for continuous CO2 sequestration applications and 2 times for surfactant-alternating-gas applications (SAG). The substantial speed up makes the three-way coupling algorithm of flow and geomechanics feasible in the large-scale optimizations. Based on the three-way coupling of compositional flow and geomechanics, we experimented two black box optimization algorithms, covariance-matrix adaptation evolution strategy (CMA-ES) and genetic algorithm (GA), for the optimization of well controls during SAG process to maximize CO2 storage volume. CMA-ES outperforms GA in that it is more robust, and it achieves higher objective function value in less simulation runs. The optimized SAG process achieves 27.55% more CO2 storage volume and reduces water and surfactant consumption by 54.84%.
Lu, Xueying (The University of Texas at Austin) | Lotfollahi, Mohammad (The University of Texas at Austin) | Ganis, Benjamin (The University of Texas at Austin) | Min, Baehyun (Ewha Womans University) | Wheeler, Mary F. (The University of Texas at Austin)
CO2 capture and sequestration in subsurface reserves are expensive processes. 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 and characterize key operational parameters to the success of the process. A coupled compositional flow and geomechanics simulator, IPARS, is used to accurately simulate the underlying physical processes, with a field scale numerical model, over the desired time-span. We map flow patterns to identify risks of leakage due to interactions of viscous, gravitational, and capillary forces. 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 WAG and foam injection process are optimized for the number of cycles, length of the cycles using the genetic algorithm (GA) in the UT optimization toolbox. The coupled flow-mechanics model can detect the effect of the plausible interaction of geomechanics and fluid flow on CO2 plume extension. Field-scale simulations indicate that during WAG and foam processes, the oil recovery increased significantly and CO2 storage increased by 30% and 49% of during the injection spam compared to continuous gas flooding, respectively. Optimized foam process saved 25% water and surfactant consumption comparing to base case foam processes while achieving approximately the same oil recovery.
In the petroleum industry, accurately estimating wellbore heat loss in thermal recovery processes remains a critical problem. One difficulty lies in simulating heat transfer and fluid dynamics within wellbore annuli. A literature survey shows that the state-of-the-art thermal wellbore simulators use empirical correlations to calculate the heat loss through wellbore annuli. As more sophisticated wells have been drilled, there is a growing need for a more detailed wellbore annulus heat transfer model. In this study, a 2D transient mathematical model is proposed for the conjugate natural convection and radiation within wellbore annuli. The governing equations consist of a continuity equation, a vorticity transfer equation, an energy transport equation and a radiative transfer equation (RTE). A finite volume approach with a second-order upwinding scheme is implemented for discretization. Newton-Raphson iterations are deployed for linearization. The algorithm is validated by consistence in simulation results compared with benchmark numerical solutions with the Rayleigh number up to 107. Parameters such as an aspect ratio, a radius ratio and a conduction-to-radiation coefficient are examined. A case study on vacuum insulated tubing heat transfer using Marlin Well A-6 data demonstrates the merits of the developed program by the consistence of simulation results compared with field measurements.
Zhang, Kai (University of Calgary) | Seetahal, Steve (The University of Trinidad and Tobago) | Alexander, David (The University of Trinidad and Tobago) | Lv, Jiateng (University of Calgary) | Hu, Yi (University of Calgary) | Lu, Xueying (University of Calgary) | Zhang, Dingbang (University of Calgary) | Wu, Keliu (University of Calgary) | Chen, Zhangxin (University of Calgary)
For Cardium tight sandstone reservoir and Monteny liquid rich shale reservoir, horizontal well with multi-stage hydraulic fracturing is applied to develop the oil underground. However, Primary recovery of tight oil reservoirs is still low even with horizontal wells and massive hydraulic fracturing. A CO2 flooding process is regarded as a promising technique for improving tight oil recovery. However, the gas-oil relative permeability during CO2 injection is not fully understood because the nanoscale pore confinement in tight oil reservoirs alters phase behavior of the reservoir fluid.
In this paper, the effect of confinement on gas and oil phase behavior is investigated. Afterwards, the gas-oil interfacial tension and solubility parameter are analyzed, resulting in an alteration in relative permeability during CO2 injection without and with hysteresis. Results show that the relative permeability of oil and gas can be further increased by the confinement effect during CO2 flooding as the interfacial tension of gas-oil can be further decreased in a nanoscale pore. Furthermore, miscibility is enhanced by the confinement effect as the solubility parameters difference between oil and gas decreases. It is consistent with the reduction in gas-oil interfacial tension. In addition, the gas phase trapping caused by hysteresis effect is weakened by the confinement effect, resulting in a lower critical gas saturation and a better oil production during CO2 injection.