Salinity, Temperature, Oil Composition, and Oil Recovery by Waterflooding
- G.Q. Tang (University of Wyoming) | N.R. Morrow (University of Wyoming)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Engineering
- Publication Date
- November 1997
- Document Type
- Journal Paper
- 269 - 276
- 1997. Society of Petroleum Engineers
- 4.3.3 Aspaltenes, 1.6.9 Coring, Fishing, 5.7.2 Recovery Factors, 5.6.2 Core Analysis, 5.2 Reservoir Fluid Dynamics, 4.3.1 Hydrates, 5.4.1 Waterflooding, 5.3.4 Reduction of Residual Oil Saturation, 5.2.1 Phase Behavior and PVT Measurements, 5.5.2 Core Analysis
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The effect of aging and displacement temperatures and brine and oil composition on wettability and the recovery of crude oil by spontaneous imbibition and waterflooding has been investigated. This study is based on displacement tests in Berea sandstone with three crude oils and three reservoir brines (RB's). Salinity was varied by changing the concentration of total dissolved solids (TDS's) of the synthetic brine in proportion. Salinity of the connate and invading brines can have a major influence on wettability and oil recovery at reservoir temperature. Oil recovery increased over that for the RB with dilution of both the initial (connate) and invading brine or dilution of either. Aging and displacement temperatures were varied independently. For all crude oils, water wetness and oil recovery increased with increase in displacement temperature. Removal of light components from the crude oil resulted in increased water wetness. Addition of alkanes to the crude oil reduced the water wetness, and increased oil recovery. Relationships between waterflood recovery and rate and extent of oil recovery by spontaneous imbibition are summarized.
Reservoir wettability has a direct influence on recovery factors for the displacement of oil by water. Laboratory studies have demonstrated the complexity of crude-oil/brine/rock (COBR) interactions and point to the uncertainty in assessments of wetting behavior in reservoirs. Displacement tests at reservoir conditions are most likely to be valid if results for preserved and restored state cores coincide. Even greater confidence follows if there is consistency between laboratory tests and in-situ measurements of reservoir residual oil saturation (ROS) and between forecasted and actual production.
The expense and time involved in obtaining core-analysis data must always be weighed against their reliability and significance. Laboratory tests designed to duplicate reservoir conditions always include compromises. For example, in laboratory displacements, the connate brine and the injected brine usually have the same composition but are different in practice. Laboratory tests are run at isothermal conditions with very small pressure differences across the core. In the reservoir, the injected water is often colder than the reservoir fluids, as evidenced by thermal fracturing. To match pressure gradients within the reservoir, laboratory displacements are run at close to isobaric conditions, whereas large differences in pressure exist between injection and production wells.
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