Hysteresis effects of three-phase relative permeabilities on black-oil reservoir simulation under WAG injection protocols

Abstract

We study the impact of explicitly including hysteresis effects (HEs) for relative permeabilities in numerical simulations of enhanced oil recovery approaches grounded on the application of Water Alternate Gas (WAG) injection protocols. Our work explores the significance of hysteresis exhibited by the relative permeability of the non-wetting and/or intermediate wetting phases on the results of reservoir simulations performed within a black-oil modeling approach. We consider four diverse strategies that can be employed to model relative permeabilities of fluid phases under WAG scenarios implemented in a water-wet system following primary waterflooding. The effects of all these modeling strategies are assessed in terms of field oil efficiency (FOE) and gas oil ratio (FGOR) evaluated at the total production lifetime of the reservoir, as compared against a base case where only waterflooding is applied to promote oil recovery. Two of these strategies are implemented and used in typical commercial black-oil reservoir simulators and either neglect hysteresis or consider it only for the gas phase. We then examine a procedure where only hysteresis for relative permeability of the oil phase is considered. Finally, we explicitly consider hysteresis of both non-and intermediate-wetting phases. Our results generally show that including HEs yields an increased FOE and a decreased FGOR. This is consistent with the observation that when injection well controls are set at an optimum value, a non-negligible portion of the domain is associated with saturation paths corresponding to three-phase flow conditions, where saturation history can play a significant role. As compared against a base case where waterflooding is considered as the sole strategy for oil recovery, including hysteresis on three-phase relative permeabilities in the numerical simulations of WAG promotes an increased net present value. We also analyze the impact on reservoir simulation responses of the main WAG injection parameters, i.e., (i) injection rate of gas and water, and duration of (ii) WAG cycles, and (iii) primary waterflooding.

Sensitivity-based Parameter Calibration of Single- and Dual-continuum Coreflooding Simulation Models

“…We remark that we perform GSA before calibration of the simulation models on the basis of experimental observations. As such, GSA is keyed to (i) improving our understanding of the importance of each model parameter on target model outputs, and hence (ii) identifying quantities which might be of limited influence in the context of a subsequent model calibration (e.g., Dell'Oca et al 2017;Valdez et al 2021;Ranaee et al 2019;2021).…”

“…In this context, decision making about the proper enhanced oil recovery strategy is typically grounded on results and interpretations of laboratory-scale coreflooding experiments. Thus, insights stemming from an appropriate integration of state-of-the-art coreflooding experiments and stochastic inverse modeling approaches yield critical information to enhance our ability to constrain predictions of multiphase flows taking place across natural geomaterials in the presence of multiple sources of uncertainty (Ranaee et al 2019;Valdez et al 2020;Berg et al 2021a, b;Kuo and Benson 2021). Water alternating gas (WAG) injection is a major enhanced oil recovery technology.…”

Implementation of Three-Phase Black-Oil Reservoir Models Assisted by Micro-Scale Analyses

“…Sensitivity of the reservoir simulation responses to the variation of system input quantities are evaluated within a Global Sensitivity Analysis (GSA) framework (see e.g., amongst others, Saltelli et al, 2008;Dell'Oca et al, 2017;Bianchi Janetti et al, 2019 and references therein). Selected reservoir responses include time evolutions of the (i) field average pressure, FPR, (ii) water-cut, FWCT, (iii) gas oil ratio, FGOR, (iv) oil recovery, FOR, and (v) net-present-value, NPV (see also Ranaee et al, 2019).…”