Previous studies have shown that waterflood recovery is dependent on the composition of injection brine in clastic reservoirs.
Some researchers have also shown that oil recovery from carbonates is dependent on the ionic composition of the injection water. These studies have however been generated at laboratory conditions which are not representative of the reservoir, and therefore it is uncertain whether these IOR benefits are applicable to actual reservoir waterflood oil recovery.
A reservoir condition coreflood study was therefore performed on core from a North Sea carbonate field (Valhall) to determine whether the recovery benefits seen in reduced condition experiments, were also obtained from full reservoir condition tests, using live crude oil and brine. In these reservoir condition tests, two reservoir core plugs were selected from the same reservoir layer and were similar in reservoir properties so that comparisons could be drawn between the experiments. Samples were prepared to give initial water saturations which were uniformly distributed and volumetrically matched to the height above the oil water contact of the samples in the reservoirs. The initial water saturation composition was based upon the simulated formation brine composition of the field. The plugs were then aged in live crude oil to restore wettability. Imbibition capillary pressure tests were then performed at full reservoir conditions, with live oil and brine, using the semi dynamic method. The first experiment utilised a simulated formation water and the second test utilised a simulated sea water, respectively, as the displacing water.
The resultant data showed that the sea water used in the capillary pressure test modified the wettability of the carbonate system, changing the wettability of the rock to a more water wet state. This was indicated by comparing the saturation change in the spontaneous imbibition phase of the test between simulated formation and sea waters.