Assessment of the Potential of Low-Salinity Water Injection Technology to Increase the Oil Recovery of the Carbonate Reservoir of the Kharyaga Field

Abstract

The development of carbonate reservoirs using peripheral and pattern water flooding typically achieves oil recovery factors ranging from 0.3 to 0.5, which is due to some complicating factors, such as, oil-wet surface of the pore space or the surface with intermediate type of wetting, unfavorable ratio of oil and water viscosities, presence of extensive structure of fractures, and significant variations of permeability down the reservoir section. In a complex geological environment, wells display abrupt fluctuations of water production that is an evidence of formation water being by no means the most efficient displacement agent. In these conditions, low-salinity water flooding can improve oil recovery. This paper reports on SCAL results of oil recovery factor determination and spontaneous imbibition using water with different composition and total solinity for Object 2 of Kharyaga oil field. Also, report contains design of on-site determination of residual oil saturation using Single Well Chemical Tracer test technology for evaluation of EOR efficiency. Laboratory tests showed, that low-salinity Jurassic water flooding with total salinity about 5 g/l could rase recovery factor up to 4% and also give incremental recovery due to effects of spontaneous imbibition for permability lower than 100 mD, which makes the injection of Jurassic water more preferable.