Mitigating Oil Bypassed in Fractured Cores During CO2 Flooding Using WAG and Polymer Gel Injections

Abstract

Abstract Fractured reservoirs have always been considered as poor candidates for enhanced oil recovery. The fractures provide a pathway for injected fluids to channel through directly from injection to production wells. The interaction between these fractures and the reservoir rock matrix often determines the degree of bypassing during injection of CO2. The use of CO2 as a displacing agent through these reservoirs aggravates the problems of low sweep efficiency due to its high mobility. The microscopic displacement efficiency of CO2 is very high, but the overall displacement efficiency is often hindered by its high mobility that is largely the results of viscosity and density contrasts between the CO2 phase and the reservoir oil and brine phases. In this study, we performed CO2 injection experiments with different injection rates and utilized X-ray CT to determine the saturation distribution along the core and measure oil bypassed during CO2 process in fractured cores. We improved the CO2 sweep efficiency by controlling the CO2 mobility in the fracture. Water viscosified with a polymer was injected directly into the fracture, to divert CO2 flow into the matrix and delay breakthrough. Although the breakthrough time reduced considerably, water "leak off" into the matrix was very high. To counter this problem, a cross-linked gel was used in the fracture for conformance control. The gel was found to overcome "leak off" problems and effectively divert CO2 flow into the matrix. This experimental results increase the understanding of fluid flow and conformance control methods in fractured reservoirs. Introduction CO2 injection has been widely used for recovering oil from reservoirs due to its easy solubility in crude oil and its ability to "swell" the net volume of oil and thereby reduce oil viscosity by a vaporizing-gas-drive mechanism (Martin and Taber, 1992). The quantity of hydrocarbons that can be recovered from a reservoir is influenced by several characteristics of the reservoir including reservoir rock properties, reservoir pressure and temperature, physical and compositional properties of the fluid and structural relief, to name a few. However, the predominant factor in deciding the success of a CO2 flood is the reservoir heterogeneity. Highly heterogeneous reservoirs with variable lateral and vertical permeability characteristics can cause potential problems during CO2 injection. The injection gas tends to finger ahead into areas with high mobility ratios. This results in the gas forming preferential paths and "bypassing" large volumes of oil. Uleberg and Hoier (2002) suggest that the injection gas tends to flow in the highly permeable fractures, instead of the normally expected displacement path. These fractures are often responsible for early and excessive breakthrough of CO2, thus greatly affecting the economics of the project. In the recent years, there has been an increasing interest in the WAG process, both miscible and immiscible. The continuous CO2 injection process is an important process to identify displacement mechanisms but is not likely to be economic in practice unless significant recycling of gas is employed. Inherent in all gas injection processes is the lack of mobility and gravity control (areal and vertical sweep) necessary to sweep significant portions of the reservoir. Therefore, the replacement of high cost CO2 by a cheaper chase fluid such as water for horizontal displacements appears economically attractive. The WAG process involves alternate injections of small pore volumes (5% or less) of CO2 and water until the desired volume of CO2 has been injected. Since the microscopic displacement oil by gas normally is better than by water, the WAG injection combines the improved displacement efficiency of gas flooding with an improved macroscopic sweep by the injection of water. This has resulted in an improved recovery (compared to pure water injection) for most field cases.