The Effect of Rock Wettability on Water Blocking During Miscible Displacement
- Eugene C. Lin (Unocal Corp.) | Edward T.S. Huang (Unocal Corp.)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- May 1990
- Document Type
- Journal Paper
- 205 - 212
- 1990. Society of Petroleum Engineers
- 5.3.4 Reduction of Residual Oil Saturation, 5.4.9 Miscible Methods, 1.8 Formation Damage, 5.4.2 Gas Injection Methods, 5.4 Enhanced Recovery, 1.6.9 Coring, Fishing, 5.4.1 Waterflooding, 5.3.2 Multiphase Flow, 5.7.2 Recovery Factors, 4.3.3 Aspaltenes, 5.5.8 History Matching, 5.3.1 Flow in Porous Media, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.2.1 Phase Behavior and PVT Measurements, 5.6.5 Tracers, 5.5.1 Simulator Development
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The influence of rock wettability on water blocking of oil during miscible displacements is investigated through both laboratory coreflood experiments and numerical simulations. For non-water-wet cores, the amount of oil remaining in the cores depends on solvent throughput. A solvent-throughput-dependent water-blocking function is proposed for a numerical model to account for the slow release of oil.
Miscible displacement processes, such as CO2 or enriched-hydrocarbon injection, have been widely used to enhance oil recovery. The major drawback of miscible processes is viscous in-stability. A water-alternating-gas (WAG) injection scheme is often applied to reduce viscous fingering. However, this scheme can cause oil trapping as a result of water-blocking effects, resulting in reduced oil recovery. Numerous laboratory investigations of water-blocking effects from simultaneous water/solvent injection have been reported for water-wet cores. These reports concluded that oil trapping caused by the water-blocking effect is significant, especially at higher water saturations. Similar, but limited, experiments for mixed-wet and oil-wet cores suggest that oil trapping becomes insignificant after large PV's of injection. Salter and Mohanty attributed such low oil trapping to the release of dendritic oil. Recently, Huang and Holm investigated the effect of rock wettability on CO2 flood oil recovery. They created cores of different wettabilities by treating Berea sandstones with different wetting agents. By comparing the difference in the amount of oil remaining in the cores after continuous and after WAG CO2 injection of 1 PV of fluid, they concluded that the amount of oil trapped in the water-wet cores was much higher than that trapped in either the mixed-wet or oil-wet cores. A mixing-parameter miscible flood simulator, such as the one developed by Todd and Longstaff, has been widely used in field immiscible flooding studies. In 1977, Warner used a similar model to investigate oil recovery efficiency resulting from various injection scenarios. He found that WAG injection generally produced more oil than continuous CO2 injection. This result may be misleading because his simulator did not model the water-blocking effect, which can reduce WAG oil recovery significantly. Later, Chase and Todd proposed a water-blocking function based on Raimondi and Torcaso's laboratory data from water-wet cores. This function contains an of parameter that can be adjusted to simulate various degrees of water-blocking effect. However, applicability of this function to both mixed-wet and oil-wet cores has not been verified. The objectives of this study were (1) to investigate the rock wettability effect on water-blocking behavior experimentally, (2) to simulate the coreflood displacements numerically with a mixing-parameter miscible flood simulator, and (3) to validate Chase and Todd's water-blocking function for numerical simulations.
Experiments conducted in this study are extensions of those conducted by Huang and Holm. One major difference was the fluid system used, which in this study consisted of mineral oil, isooctane, and 2% brine instead of Devonian crude. CO2, and brine as in Ref. 7. The mineral oil is first-contact miscible with isooctane, and the mineral-oil/isooctane viscosity ratio of 24 was chosen to represent a typical viscosity ratio of a gas miscible flood process. With this fluid system, miscible coreflood experiments can be conducted at ambient conditions, which greatly improves the experimental material-balance measurements. The duration of miscible coreflood experiments was also extended beyond 2 PV of total fluid injection to provide production data for simulation history matching. Table 1 shows the properties of these fluids.
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