Polymer flooding plays an important role in enhanced oil recovery (EOR), particularly in China, where partially hydrolyzed polyacrylamide (HPAM) and hydrophobically associating water-soluble polymers (HAWP) are used in onshore and offshore reservoirs, respectively. Many researchers have highlighted the elasticity of HPAM, which can be used to improve the sweep efficiency, i.e., the ratio of the area swept by an injected fluid to the oil area. On the other hand, fewer studies exist on the elasticity of HAWP. In this study, we investigate the flow of HAWP and Xanthan solutions with identical viscosities in core experiments in terms of elasticity; results reveal that the HAWP can produce shear thickening in the core. The constitutive equation for the HAWP can be obtained using the simulation results matched with the experimental data. On the basis of these experiments, we established a two-phase flow model of a polymer and oil, including the continuity, momentum, constitutive, and phase equations. The volume-of-fluid (VOF) method was used to track the interface between the two phases. A complex pore model was established based on the glass-etched model used in the experiment. We used the OpenFOAM platform to solve the mathematical model. The saturation, pressure, and stress tensor distributions were obtained. The results show that the displacement efficiency increased as the elasticity of the polymer increased; accordingly, the elasticity can enlarge the sweep area and decrease the residual oil saturation. As the elasticity increases, the stresses (the first normal stress, second normal stress, and shear stress) increase. Finally, the results obtained in this study can be used as a guideline in polymer design, screening, and optimization in the polymer flooding oilfields.

The polymer flooding process has already been applied to the medium permeability type II reservoirs of the Daqing Oilfield (China) to enhance oil recovery. However, this process faces a number of challenges, such as the flooding efficiency, high injection pressure, formation blockage and damage, unbalanced absorption ratio, and economical justification. In this study, single-phase and two-phase flow experiments are performed to investigate polymer injection adaptability with natural cores of type II reservoirs. The enhanced oil recovery (EOR) effects of the polymer are studied by physical simulation experiments, and the results of application in an actual field are also presented. The results indicate that the flow characteristics and injection capability are dominated by the reservoir permeability in polymer flooding. Moreover, the adsorption of polymer molecules and the injection pressure gradient, which reflect formation damage, are affected more significantly by the concentration than by the molecular weight in type II reservoirs. Using the matching relationship, the injection-production process is stable, and additional oil recoveries of 10%–15% can be obtained in heterogeneous type II reservoirs with a high water saturation. This work is significant in that it further accelerates the application of polymer flooding EOR in medium permeability heterogeneous oilfields with high water saturation.

Focusing on problems of rapid production decline and poor development effect after volume fracturing of the shale oil reservoir, a production method of SC-HNP (surfactant slug assisting CO2 huff and puff) was proposed. Taking CQ block (CQ, the reservoir block name) as an example, laboratory experiments were carried out using typical oil samples and core samples, and a numerical simulation model of SC-HNP was established based on the experimental results. The production performance and oil recovery mechanism were analyzed, and the oil production by SC-HNP of a typical well was predicted. The results showed that (1) the oil recovery degree of the surfactant imbibition experiment is 34.5%, showing good imbibition oil recovery effect. CO2 has good swelling effect and viscosity reduction ability to the oil. (2) SC-HNP combines the effects of the surfactant and CO2, and it has the best replenishing formation energy ability and the highest oil production level. Its improved recovery degree is about 2.4% (one cycle), showing the best development effect. (3) Compared with SF-HNP (surfactant huff and puff), SC-HNP can improve the oil displacement effect in the far-well fractured area, and compared with CO2-HNP (CO2 huff and puff), SC-HNP can improve the oil displacement effect in the near-well fractured area. (4) Using SC-HNP, it is predicted that the oil recovery degree of well CQP-32 (CQP-32, the well name) can be increased by 1.84%, which significantly improves the development effect, and the CO2 storage percent is about 32%.

Numerical well test model of oil-water two-phase flow in fractured and vuggy carbonate reservoir