The Optimal Initiation Timing of Surfactant-Polymer Flooding in a Waterflooded Conglomerate Reservoir

Abstract

SummarySurfactant-polymer (SP) flooding has been regarded as an efficient technique for enhanced oil recovery in the development of mature oil fields, especially for those with heterogeneous conglomerate reservoirs. However, people are still unclear about the optimal SP flooding initiation timing (OSPT) that is expected to contribute to the maximum ultimate recovery factor in the case with a limited amount of SP solution injection. Accordingly, this study aims to investigate OSPT through conducting a series of experiments, including nuclear magnetic resonance (NMR) online monitoring, full-diameter coreflooding, and microfluidic study. The fractional-flow curve is used to identify OSPT, of which the effect on the oil recovery is analyzed. OSPT is demonstrated to be dependent on the amount of injected SP solution. An earlier-started SP flooding is favorable for achieving higher oil recovery factors under the premise of sufficiently high SP solution injection [more than 1.5 pore volume (PV)]. With the commonly used 0.65 PV of SP solution in the reservoir scale, OSPT is suggested to be at the moment when a water cut of 80 to 90% is reached. The formation of dense emulsions in the early-started SP flooding affects the performance of the post-waterflooding, which eventually decreases the ultimate oil recoveries because of inadequacy of SP solution. An earlier-started SP flooding contributes to a larger swept volume, but the initial efficiency of the SP flooding is lower than that of the waterflooding when the injection pressure is constant. OSPT is proposed through analyzing the fractional-flow curve in the case of 0.65 PV of SP injection, and the determined OSPT is validated by coreflooding experiments and field data. Moreover, OSPT for the conglomerate reservoir is suggested to be earlier than that for the relatively homogenous sandstone reservoir.