Improving Oil Recovery from Carbonate Rocks Using Compositionally Modified Water Injection

There is a potential to improve oil production from carbonate and sandstone reservoirs by modifying the salinity and ionic composition of the injection brine relative to resident brine. This process can increase oil production in both green and mature waterflooded reservoirs in secondary and tertiary modes. While initial studies focused mainly on sandstones, the fact that carbonate formations host a major portion of the world's known oil reserves has motivated researchers to examine the feasibility of low salinity water injection in carbonates.

Numerous experimental studies have focused on effect of low salinity on contact angle, zeta potential, oil recovery in imbibition tests and corefloods. There is very little experience in the field and limited to single well tests to measure the change in oil saturation with high salinity and low salinity brines.

We have conducted spontaneous imbibition and coreflood using reservoir core from oolitic-carbonate reservoir focused on the effects of injection brine salinity and reactive-ion composition on wettability alteration and oil recovery in calcite-rich carbonate reservoir rocks. Reservoir core plugs were first cleaned with solvent, oven-dried, vacuumed, and saturated with 250,000 ppm TDS synthetic formation brine. Initial water saturation was established by flooding the core with reservoir stock tank crude oil, and the aging with the crude oil was performed at reservoir temperature of 92 ºC and elevated pressure for about two weeks to somewhat restore the native reservoir wettability. Samples were then placed in imbibition cells filled with formation brine to monitor oil recovery by formation brine imbibition. The results indicated very little oil was produced from the plugs indicating mixed wettability.

Incremental oil recovery and rate of oil recovery compared to the formation brine imbibition were evaluated by replacing formation brine with various select-ion brines to gain insights into different recovery mechanisms using diluted injection seawater, and selective modification of the concentration of potential determining ions (PDI). Brine compositions tested were 50,000 ppm TDS seawater, 10 times diluted seawater, variable concentrations of PDI as well as brine containing wettability-altering agents such as surfactants. Fluid pH and IFT were also measured for the oil/brine compositions tested here.

Dynamic oil recovery of the most promising brines was also evaluated in corefloods using stacked reservoir core plugs at reservoir conditions. Effluent ion chromatography analysis was used to investigate the mechanisms and determining ions. Pressure drop at several lengths was monitored for a potential change in permeability due to calcite dissolution/fines migration.