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The conglomerate reservoir of the Xinjiang-552 oilfield is characterized by high heterogeneity and complex pore structure. After several years of water injection development, the formation pressure in the reservoir is low and the production per well is poor. The reservoir is difficult to regulate and control and does not meet the conditions for the implementation of the polymer flooding operations. In this paper, the numerical simulation method is applied to optimize the injection-production parameters, including the injection-production ratio, pressure recovery rate, reasonable production rate, and polymer injection timing of the polymer flooding in the X-552 reservoir. The objective of the research is to determine the optimal injection-production parameters and to provide sufficient injection-production capacity for polymer flooding. The front-water flooding technology is applied to ensure the successful progress of polymer flooding in the reservoir. The results show that when the reservoir formation pressure coefficient is 1.0 (the formation pressure is 16.4 MPa), the polymer flooding recovery is reasonably high, the front-water flooding injection time is 5 years, the injection-production ratio is 1.05, and the average annual pressure recovery rate is 0.52 MPa. As shown by the predicted results, the production profile and recovery degree are greatly improved, the development effect is satisfactory, and the goal of the frontal water flooding is achieved. The proposed method can be applied to provide guidance for front-water flooding in conglomerate-type reservoirs. [ABSTRACT FROM AUTHOR]

The spontaneous imbibition of fracturing fluid in the shale matrix is one of the main reasons for the low hydraulic fracturing flowback rate. The distribution characteristics of fracturing fluid in the shale spontaneous imbibition process are studied by the low field nuclear magnetic resonance (NMR) method. An improved pseudo-potential lattice Boltzmann model is proposed to simulate the spontaneous imbibition behavior in a three-dimensional porous shale structure. The results show that the viscosity, sample length, and permeability of the imbibition solution have an important influence on the imbibition characteristics of the samples. In the imbibition process based on the SC-LBM model, due to the capillary force effect, the imbibition liquid preferentially enters the larger pores of the wetting phase and then gradually distributes in the adjacent pores. [ABSTRACT FROM AUTHOR]

Surfactant/polymer (SP) floods have significant potentials to recover remaining oil after water flooding. Their efficiency can be maximized by fully utilizing synergistic effect of polymer and surfactant. Various components adsorbed on the rock matrix due to chromatographic separation can significantly weaken the synergistic effect. Due to scale and dimensional problems, it is hard to investigate chromatographic separation among various components using one-dimensional natural cores. This study compared the adsorption difference between artificial and natural cores and developed a three-dimensional artificial core model of a 1/4 5-spot configuration to simulate oil recovery in multilayered reservoirs with high, middle and low permeability for each layer. Sampling wells were established to monitor pressures, and effluent fluids were acquired to measure interfacial tension (IFT) and viscosity. Then, distances of synergy of polymer and surfactant in three layers were evaluated. Meanwhile, electrodes were set in the model to measure oil saturation variation with resistance changes at different locations. Through comparison with IFT values, the contribution of improved swept volume and oil displacement efficiency to oil recovery during SP flooding could be known. Results showed that injected 0.65 PV of SP could improve oil recovery by 21.56% when water cut reached 95% after water flooding. The retention ratio of polymer viscosity was kept 55.3% at the outlet, but IFT was only 2 mN/m within the 3/10 injector-producer spacing during SP injection. Although subsequent water flooding could result in surfactant desorption and the IFT became 10−2 mN/m within the 3/10 injector-producer spacing, the IFT turned to 2 mN/m at the half of the model. The enhanced displacement efficiency by reducing IFT only worked within three-tenth location of the model in the high permeability layer, while the enlarged swept volume contributed much in the other areas. [ABSTRACT FROM AUTHOR]