Influence of pore structure and fluid properties on the dynamics of foamy oil production: an experimental and numerical analysis

Abstract

Cyclic Solvent Injection (CSI) stands out as one of the leading solvent-based post-CHOPS Enhanced Heavy Oil Recovery (EHOR) methods, celebrated for its energy efficiency, improved oil quality, and environmental benefits. Given the escalating concern over greenhouse gas emissions, exploring the use of CO2 in EHOR methods is crucial for mitigating the greenhouse effect. Studies have demonstrated that mixing CO2 with other solvents can enhance CSI performance by leveraging foamy oil flow as the primary driving force. Our state-of-the-art microfluidic systems, developed in-house, offer precise visualizations of the process, and enable controlled simulation of reservoir properties throughout experimental series. In this study, experiments were conducted on both porous and non-porous media to examine the influence of additives, solvent type, and pressure reduction rate on foamy oil production. Utilizing heavy oil from Canada, we conducted fundamental tests, including composition analysis, Constant Composition Expansion (CCE), and Differential Liberation (DL) tests, to characterize the oil and its gas-saturated live oil state. The solvents employed were CO2 and CH4, with CH4 chosen for its cost-effectiveness despite its lower performance compared to C3H8. However, a mix of CO2 and CH4, with added surfactants, yielded improved bubble generation and stability. The project focused on three primary input parameters: solvent type, surfactant concentration, and pressure reduction rate, with their ranges informed by prior research. Minitab software guided the experimental design, suggesting 15 tests on a bulk microfluidic model to observe the dynamics of live and foamy oil under varying pressures. The results of 15 tests highlighted two individual tests ii with superior stability and the lowest energy usage. In addition, optimal input parameters for reducing the oil in place and increasing production rate were identified using Minitab for further application. These optimal conditions were then tested on three different porous microfluidic models to assess the impact of porosity on foamy oil expansion, with porosities set at 31%, 35%, and 40%. The 31% porosity model exhibited the highest stability and expansion, indicating that lower porosity restricts bubble movement, hindering their coalescence and growth. Micro-analyses on bubble dynamics and movement were performed, followed by non-equilibrium reaction studies using CMOST to determine the impact of each parameter on oil production. Initial tuning for solvent type, surfactant concentration, and pressure reduction rate was conducted in CMOST, with subsequent adjustments for porosity and relative permeability. Numerical analysis of bulk phase expansion and three-porosity model results from experimental tests were utilized to derive tuning coefficients. A key novelty of this study is the derivation of non-equilibrium equations that incorporate variables such as pressure reduction rate, porosity, solvent type, and surfactant concentration in the foamy oil process. Finally, the optimized parameters for maximizing heavy oil expansion were implemented in a cylindrical sand pack model. Both simulation and experimental results from the sand pack test indicated that oil production became negligible at lower pressures during the pressure depletion test. The optimal oil production, achieving the highest benefit, was found to reach 37% of the initial oil in place using the pressure depletion technique.