During waterflooding processes, injected water disconnects oil droplets as it flows through pores/throats in the reservoir. These disconnections are a consequence of capillary effects hindering the mobilization of oil through pores/throats of the reservoir. Thus, mobilizing the remaining oil in place by any enhanced oil recovery (EOR) process becomes very challenging.
Chemical flooding has been identified as an effective EOR method, which is usually implemented in tertiary mode, where field development has reached a mature level. At this stage, the efficiency of waterflooding, in terms of mobilizing remaining oil, declines due to capillary trapping. Chemical EOR (CEOR) methods such as polymer-surfactant flooding are used to reduce this trapping and mobilize the remaining oil.
Although most EOR processes have been implemented in tertiary mode, earlier implementation is more desirable, because capillary trapping is less prominent. This study investigates the impact of post-waterflood implementation time of surfactant-polymer flooding on ultimate recovery and net present value (NPV), given this capillary trapping. A series of numerical experiments was conducted to test this effect while accounting for operating expenses associated with both flooding options. Capillary pressure curves for the waterflood case and the chemical flood case were added to incorporate capillary trapping effects. Then the chemical-flood implementation time was varied to evaluate its impact on the ultimate oil recovery. These experiments were performed on two stylized reservoir models PUNQ-S3 and SPE10M reservoir models.
Given our assumptions, the ultimate recovery did not significantly change with varying the CEOR implementation time. There is, however, an optimum implementation time for CEOR at which NPV is maximized. The optimum implementation time becomes sooner as the geologic model is more heterogeneous.