Mobility Control for Gas Injection in Heterogeneous Carbonate Reservoirs: Comparison of Foams versus Polymers

Abstract

Gas injection is a proven enhanced oil recovery method, especially for light oil reservoirs. The primary objective of gas injection is to improve the displacement efficiency and reduce residual oil saturation below the values usually obtained in waterflooding. However, the macroscopic sweep efficiency of gas injection can be suboptimal, mainly due to channelling, viscous fingering and gravity segregation of the injected gas. The macroscopic sweep of gas injection is further reduced for highly heterogeneous reservoirs. In this paper we examine the ability of both foam and polymer to provide mobility control to gas injection in a mixed-wet carbonate reservoir with high permeability contrast, i.e, high permeability zone on top of a low permeability zone. Under waterflood, there is an impediment for water to flow from the high permeable Upper zone to the Lower zone due to e.g., capillary pressure. The paper presents two new emerging technologies for mobility control of gas injection, which results in improving vertical sweep efficiency of oil reservoirs, namely: 1-SIMGAP: Simultaneous injection of miscible gas in the low permeable Lower zone and a polymer solution in the high permeable Upper zone. A lateral pressure gradient is maintained in the Upper zone by the injected polymer, providing Lower zone gas confinement; and2-Foam: Simultaneous injection of surfactant solution in the Upper zone and gas in the Lower zone. As gas migrates to the Upper zone, foam will be created in-situ and reduces both gas and water mobility in the Upper zone. This leads to the containment of the gas in the Lower zone, thus improving vertical sweep of the reservoir. The EOR processes are compared based on recovery factor, possibility of success, robustness to geological heterogeneity and operating conditions and stability at high temperature and salinity conditions. Simulation results show that the two EOR processes have the potential of recovering the oil that is by-passed by waterflood or conventional gas injection schemes. The SIMGAP process (polymer based) leads to higher recovery factor than the foam process. Experimental data supporting simulation work was also conducted as part of this study.

Laboratory Study of CO2 Foam Flooding in High Temperature, High Salinity Carbonate Reservoirs Using Co-injection Technique

“…This is to increase its density to a range of 0.5–0.9 g/cm 3 which reduces the density contrast significantly . The miscibility and viscosity of CO 2 increase significantly in supercritical phase as compared to other gases used in gas injection processes . However, the viscosity contrast between supercritical CO 2 and reservoir fluids still remains high, and therefore, viscous fingering remains a significant problem for CO 2 injection. , …”

“…1 The miscibility and viscosity of CO 2 increase significantly in supercritical phase as compared to other gases used in gas injection processes. 6 However, the viscosity contrast between supercritical CO 2 and reservoir fluids still remains high, and therefore, viscous fingering remains a significant problem for CO 2 injection. 7,8 A noble method to reduce the mobility of injected gas for improved oil recovery was first described by Bond and Holbrook.…”

Effect of Oil Presence on CO2 Foam Based Mobility Control in High Temperature High Salinity Carbonate Reservoirs

“…In this case study, a 3D heterogeneous simulation model with a size of 800 ft width and 160 ft thickness is developed. Figure shows two permeability profiles (perm 1 and perm 2) as a function of depth, where the profile termed perm 1 is used as the reference permeability profile to incorporate heterogeneity into the model . The top 70 ft of the reservoir zone is considered as the high permeability zone (permeability in the range of 50–1000 mD), while the rest of the zone is considered as the low permeability zone (permeability in the range of 5–20 mD).…”

“…Figure 18 shows two permeability profiles (perm 1 and perm 2) as a function of depth, where the profile termed perm 1 is used as the reference permeability profile to incorporate heterogeneity into the model. 46 The top 70 ft of the reservoir zone is considered as the high permeability zone (permeability in the range of 50−1000 mD), while the rest of the zone is considered as the low permeability zone (permeability in the range of 5− 20 mD). The initial pressure and temperature of the reservoir are 4000 psi and 120 °C, and a PVT modeling package is used to characterize a seven component oil model.…”

Tuning Foam Parameters for Mobility Control using CO2 Foam: Field Application to Maximize Oil Recovery from a High Temperature High Salinity Layered Carbonate Reservoir

“…On the basis of the experimental observations, tuned foam model is applied on a field scale to maximize the efficiency of injected gas. The surfactant solution is injected in the high permeability zone and gas in the low permeability zone such that foam is created in situ as the gas migrates to the high permeability zone, thereby leading to the containment of gas in the low permeability zone …”