Effect of CO2-Water Injection Ratio on the Co-Optimization of Oil Recovery and CO2 Storage in a Swag Displacement Process

Abstract

Carbon dioxide (CO2) injection has been studied and applied as an important Enhanced Oil Recovery (EOR) method. However, a low volumetric sweep efficiency has always been a technical issue for continuous CO2 flooding because of high mobility and low density of CO2 in comparison with those of other reservoir fluids. The low volumetric sweep leaves large volumes of bypassed oil in the reservoir which in turn leaves limited pore space available for CO2 storage. Therefore, several mobility control methods have been trialed in laboratory and field pilot tests to improve the sweep efficiency. One mobility control method is CO2 simultaneous water-and-gas (CO2-SWAG) injection. The injected water displaces the oil which is bypassed by the CO2 to enhance oil recovery. Recent laboratory studies have found that fraction of CO2 injected (FGI) in a CO2-SWAG process can affect CO2 relative permeability function [1], [2]. An optimized FGI reduces the CO2 relative permeability, hence increasing the amount of CO2 retained in the pore space. Although the previous studies have highlighted strong dependency of CO2 relative permeability on FGI, the number of experiments performed were limited to find the optimum value of FGI. In this study we performed laboratory experiments to find optimum FGI to maximize oil recovery and CO2 storage during CO2-SWAG displacement in a Bentheimer sandstone. A 28cm long Bentheimer core sample was used for the study. Before the SWAG injection, the core is at irreducible water saturation. The oil phase is composed of 65% Hexane (C6) and 35% Decane (C10). Experiments are run at 1700psia and 700C which represents near-miscible conditions. Pure Supercritical CO2 and distilled water are injected simultaneously into the core at a fixed FGI. A total of 8 experiments were performed at FGI of 0.0, 0.25, 0.50, 0.75, 0.80, 0.997 and 1.0. FGI of 0.0 and 1.0 represents water injection and continuous CO2 injection, respectively while a FGI of 0.997 represents CO2water saturated CO2 at the experimental conditions. The produced fluids are collected in glass vials and are subsequently analyzed using the Gas Chromatography to quantify the produced water and hydrocarbons. A gas flowmeter is used to measure the mass rate of gas. The volume of the produced liquid and differential pressure across the core are continuously recorded during the experiment. A compositional commercial reservoir simulator is used to determine the FGI dependent relative permeability functions. Pressure drop across the core, oil recovery and the mass of CO2 stored are used as the matching parameters. The results indicate that 0.80 is the optimum FGI for the given experimental conditions. A remarkable reduction in CO2 relative permeability was observed for FGI 0.75 compared with continuous CO2 injection (FGI=1).