Estimating Relative Permeabilities Through Experimental and Numerical Approaches for a Steam-Flue Gas Hybrid Process

Abstract

Abstract A relative permeability study was undertaken to evaluate the impact on fluid movement and fluid saturations during a steam-flue gas hybrid process to improve oil recovery and energy efficiency. Two-phase water/oil and gas/liquid relative permeability curves were obtained for modeling the recovery of a Colombian heavy oil reservoir with steam-flue gas hybrid processes at the laboratory and eventually field scale. Apparatus setup, experimental and numerical modeling procedures and results are presented. A customized experimental setup was designed and successfully operated to conduct coreflood tests at reservoir pressure and temperatures up to 280°C. Relative permeabilities were determined using the unsteady state method, where fluids are injected in a specified sequence. Two series of isothermal core-flooding experiments were conducted with the injection of oil, water, steam, and in one sequence, flue gas at different temperatures. One series was performed while increasing temperatures from 40°C to 260°C and another while increasing to 270°C and then decreasing to 40°C. The experiments were history matched to derive water/oil and gas/liquid relative permeability curves. Experimental results, including core temperatures, injection and production pressures and fluids, along with estimated residual core saturations from material balances after each core flood, are presented. The core flood experiments were numerically modeled while honoring core properties, fluid injection volume history, production pressures, and core temperatures. Parameters from relative permeability correlations were obtained after successfully history matching the cumulative production of oil, water, and gas (where applicable) of each core flood sequence and temperature. A single set of relative permeability curves for each system, water/oil, steam/liquid, and flue gas/liquid, could adequately model most of the core flooding experiments performed at different temperatures, especially those conducted while the core temperature was increased. Although hysteresis due to saturation history was not observed, temperature history exhibited a hysteretic effect. Higher residual oil saturations to waterfloods at 240°C and 40°C were obtained in tests performed under decreasing temperatures from 270°C compared to the ones obtained while increasing temperatures from 40°C. The two series of coreflood experiments yielded similar residual oil saturations to steamflood. Water/oil and steam/liquid relative permeability curves were consistent for those tests performed while increasing temperature. This study presents a representative methodology to obtain water/oil relative permeability curves for heavy oil and, more importantly, for steam/liquid and flue gas/liquid systems. These curves are key for the reliable modeling of heavy oil recovery with hybrid steam-flue gas processes, which in turn, allow for energy efficiency estimations and identification of opportunities to reduce the carbon footprint of thermal methods that rely on steam, via partial sequestration of flue gas into the porous media.