Polymer flooding is widely and successfully used to enhance oil recovery. How to further enhance oil recovery after polymer flooding becomes an important question that needs to be solved to stabilize oil production. Branched-preformed particle gel (B-PPG) is a newly developed chemical agent to enhance the oil recovery from heterogeneous reservoirs. Here, laboratory experiments were performed to investigate the enhanced oil recovery of B-PPG/hydrolyzed polyacrylamide (HPAM) mixed solutions through heterogeneous porous media by the core flood test. The results show that the B-PPG/HPAM mixed solutions have a higher oil recovery than solutions containing HPAM or B-PPG alone because of the synergistic effect between B-PPG and HPAM. B-PPG can adjust flows in different permeability zones by its properties of blocking, deforming, and passing through the throat during flow, which can be proved by the fractional flow behaviors in the parallel-sandpack displacement test. HPAM can not only increase the viscosity of the flooding but also enhance the sustained effect of B-PPG. The resistance factors during the flow of B-PPG/HPAM mixed solutions through heterogeneous porous media were also measured. The B-PPG/HPAM mixed solutions have higher resistance factors and residual factors than the solutions of HPAM or B-PPG alone. The relationships between oil recovery and resistance factor show that B-PPG/HPAM mixed solutions have better abilities to enhance oil recovery because of the synergistic effect. Furthermore, the microscopic displacement behaviors in the heterogeneous microscopic model were investigated. The results are consistent with the core flood test and confirm that B-PPG and HPAM have the synergistic effect on further-enhanced oil recovery after polymer flooding.
ABSTRACT The soaking stage is vital for oil production after fracturing in tight reservoirs. However, the roles and contributions of spontaneous imbibition (SI) and forced displacement imbibition (FDI) during this stage are poorly understood. This study gave an in‐depth insight on the imbibition characteristics during the soaking stage under non‐zero initial water saturation conditions by static soaking and dynamic waterflooding of the core. The results indicate that the fluid absorbed by SI in the core is short‐ranged. After SI, there is still a substantial amount of remain oil (30.7%) that can be displaced by subsequent FDI. SI considerably drives oil recovery in small pores (10–100 nm), whereas FDI is more effective in large pores (500–1000 nm). Controlling the rate of fracturing water flowing into the matrix from the fracture can enhance the combined effect of SI and FDI. For reservoirs with high initial water saturation, enhancing FDI effect during the soaking stage is favorable for oil production.
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