Polymer degradation is critical for polymer flooding because it can significantly influence the viscosity of a polymer solution, which is a dominant property for polymer enhanced oil recovery (EOR). In this work, physical experiments and numerical simulations were both used to study partially hydrolyzed polyacrylamide (HPAM) degradation and its effect on polymer flooding in heterogeneous reservoirs. First, physical experiments were conducted to determine basic physicochemical properties of the polymer, including viscosity and degradation. Notably, a novel polymer dynamic degradation experiment was recommended in the evaluation process. Then, a new mathematical model was proposed and an in-house three-dimensional (3D) two-phase polymer flooding simulator was designed to examine both polymer static and dynamic degradation. The designed simulator was validated by comparison with the simulation results obtained from commercial software and the results from the polymer flooding experiments. This simulator further investigated and validated polymer degradation and its effect. The results of the physical experiments showed that the viscosity of a polymer solution increases with an increase in polymer concentration, demonstrating their underlying power law relationship. Moreover, the viscosity of a polymer solution with the same polymer concentration decreases with an increase in the shear rate, demonstrating shear thinning. Furthermore, the viscosity of a polymer solution decreased with an increase in time due to polymer degradation, exhibiting an exponential relationship. The first-order dynamic degradation rate constant of 0.0022 day−1 was greater than the first-order static degradation rate constant of 0.0017 day−1. According to the simulation results for the designed simulator, a 7.7% decrease in oil recovery, after a cumulative injection volume of 1.67 pore volume (PV) was observed between the first-order dynamic degradation rate constants of 0 and 0.1 day−1, which indicates that polymer degradation has a detrimental effect on polymer flooding efficiency.

Abstract:In this paper, physical experiments and numerical simulations were applied to systematically investigate the non-Newtonian flow characteristics of heavy oil in porous media. Rheological experiments were carried out to determine the rheology of heavy oil. Threshold pressure gradient (TPG) measurement experiments performed by a new micro-flow method and flow experiments were conducted to study the effect of viscosity, permeability and mobility on the flow characteristics of heavy oil. An in-house developed novel simulator considering the non-Newtonian flow was designed based on the experimental investigations. The results from the physical experiments indicated that heavy oil was a Bingham fluid with non-Newtonian flow characteristics, and its viscosity-temperature relationship conformed to the Arrhenius equation. Its viscosity decreased with an increase in temperature and a decrease in asphaltene content. The TPG measurement experiments was impacted by the flow rate, and its critical flow rate was 0.003 mL/min. The TPG decreased as the viscosity decreased or the permeability increased and had a power-law relationship with mobility. In addition, the critical viscosity had a range of 42-54 mPa·s, above which the TPG existed for a given permeability. The validation of the designed simulator was positive and acceptable when compared to the simulation results run in ECLIPSE V2013.1 and Computer Modelling Group (CMG) V2012 software as well as when compared to the results obtained during physical experiments. The difference between 0.0005 and 0.0750 MPa/m in the TPG showed a decrease of 11.55% in the oil recovery based on the simulation results, which demonstrated the largely adverse impact the TPG had on heavy oil production.

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This paper provides field scale EOR survey in China which is in line with biennial worldwide EOR survey published by Oil& Gas Journal (OGJ). The EOR progress in China is not available due to language difference and other reasons in OGJ EOR survey. From 2018, EOR survey in China will be published biennially. The first part of this survey mainly focuses on basic information. Chemical flooding, unconventional heavy oil, green recovery and natural gas recovery progress in China will be surveyed and discussed in detail in the other four parts elsewhere. The EOR projects including field tests and field applications in China are summarized in the same pattern as OGJ to the largest extent for better readership outside China. Most data is collected from published journal papers and reports. Different from other countries, there are only four major oil companies in China: CNPC, SINOPEC, CNOOC and Yanchang Oil. The 28 branch companies of these four companies are both operator and owners. Oil and gas production from CNOOC is all offshore. CNPC is the largest oil company in China and its oil production in 2016 accounts for 54% oil production in China. EOR survey in China includes chemical flooding (polymer, SP and ASP flooding, gas flooding (CO2, nitrogen and air), thermal production, MEOR, and foam flooding. EOR production in China in 2016 accounts for 18% total oil production, while chemical EOR accounts for 10 %. Up to present, there has been more than 34 ASP flooding projects in China, most in Daqing. The total ASP oil production in 2016 is 407 million tons. More than 30 SP flooding projects have been carried out, with incremental oil recovery factor of 7%-18% OOIP. More than 170 polymer flooding projects have been carried out. Polymer flooding has been used widely in Daqing, Shengli, Xinjiang, Liaohe, He'nan and Bohai. The incremental oil recovery from polymer flooding and ASP flooding is 7%-15% and 18%-30% OOIP respectively. Gas flooding in China is not as successful as chemical EOR. Polymer flooding production in the largest offshore oilfield in CNOOC accounts for 25% total oil production in 2016. While EOR production in China accounts for 15%-18% in recent years, however, the world EOR oil production only accounts for about 3.3% total oil production. EOR is greatly affected by oil price, as indicated from 26 years EOR content change in America. It is the first time that detailed EOR survey in China in line with worldwide EOR survey in OGJ is given. The EOR survey in China provides valuable and helpful information for engineers and researchers in oil and gas industry.

The flow of polymer solution and heavy oil in porous media is critical for polymer flooding in heavy oil reservoirs because it significantly determines the polymer enhanced oil recovery (EOR) and polymer flooding efficiency in heavy oil reservoirs. In this paper, physical experiments and numerical simulations were both applied to investigate the flow of partially hydrolyzed polyacrylamide (HPAM) solution and heavy oil, and their effects on polymer flooding in heavy oil reservoirs. First, physical experiments determined the rheology of the polymer solution and heavy oil and their flow in porous media. Then, a new mathematical model was proposed, and an in-house three-dimensional (3D) two-phase polymer flooding simulator was designed considering the non-Newtonian flow. The designed simulator was validated by comparing its results with those obtained from commercial software and typical polymer flooding experiments. The developed simulator was further applied to investigate the non-Newtonian flow in polymer flooding. The experimental results demonstrated that the flow behavior index of the polymer solution is 0.3655, showing a shear thinning; and heavy oil is a type of Bingham fluid that overcomes a threshold pressure gradient (TPG) to flow in porous media. Furthermore, the validation of the designed simulator was confirmed to possess high accuracy and reliability. According to its simulation results, the decreases of 1.66% and 2.49% in oil recovery are caused by the difference between 0.18 and 1 in the polymer solution flow behavior indexes of the pure polymer flooding (PPF) and typical polymer flooding (TPF), respectively. Moreover, for heavy oil, considering a TPG of 20 times greater than its original value, the oil recoveries of PPF and TPF are reduced by 0.01% and 5.77%, respectively. Furthermore, the combined effect of shear thinning and a threshold pressure gradient results in a greater decrease in oil recovery, with 1.74% and 8.35% for PPF and TPF, respectively. Thus, the non-Newtonian flow has a hugely adverse impact on the performance of polymer flooding in heavy oil reservoirs.

Many studies have shown that heavy oil with high asphaltene content has a yield stress. Coupled with the solid-liquid interaction between porous media and heavy oil, there is a threshold pressure gradient when heavy oil flows in porous media. Meanwhile, some previous research has indicated that the high viscosity of heavy oil is the decisive factor for its threshold pressure gradient. Hence, this concept needs more clarification, especially because its accuracy is questionable. In this research, different oil samples with the same viscosity and also different asphaltene contents heavy oil samples were prepared. The viscosity of the different heavy oil samples was measured. Threshold pressure gradient experiments under different permeabilities and temperatures were also conducted on heavy oils. The results proved that the viscosity was not directly related to threshold pressure gradient of heavy oil. They also suggested that the heavy oil viscosity increased with the increase of asphaltene content. Moreover, the formula of the factors affecting threshold pressure gradient was regressed, and also its applicability was verified. As the temperature and core permeability increase, the threshold pressure gradient was also proven to decrease significantly. Furthermore, it was found that the threshold pressure gradient increased significantly with the increase of asphaltene content. Therefore, the heavy oil threshold pressure gradient could be characterized as a function of temperature, permeability, and asphaltene content. This study provided some theoretical support for the research attempts on the reduction of threshold pressure gradient and also on the effective development of heavy oil reservoirs.

Abstract. In this paper, physical and numerical simulations were applied to investigate the polymer degradation performance and its effect on polymer enhanced oil recovery (EOR) efficiency in homogeneous reservoirs. Physical experiments were conducted to determine basic physicochemical properties of the polymer, including viscosity, rheology, and degradation. A new mathematical model was proposed, and an in-house simulator was designed to further explore polymer degradation. The results of the physical experiments illustrated that polymer could increase polymer solution viscosity significantly, and the relationship between polymer solution viscosity and polymer concentration exhibited a clear power law relationship. However, the viscosity of a polymer solution with the same polymer concentration decreased with an increase in the shear rate, showing shear thinning performance. Moreover, the viscosity decreased with an increase in time, which was caused by polymer degradation. The validation of the designed simulator was improved when compared to the simulation results using ECLIPSE V2013.1 software. The difference between 0 and 0.1 day -1 in the polymer degradation rate showed a decrease of 6% in oil recovery after 2,000 days, according to simulation results, which demonstrated that polymer degradation had an adverse effect on polymer flooding efficiency.

Influenced by water injection, a dominant flow channel is easily formed in the high water cut stage of a conglomerate reservoir, resulting in the inefficient or ineffective circulation of the injected water. With gel flooding as one of the effective development methods to solve the above problems, its parameter optimization determines its final development effect, which still faces great challenges. A new optimization method for gel flooding is proposed in this paper. Firstly, the gel flooding parameters were obtained through physical experiments; then, an experimental model of gel flooding was established according to the target reservoir, and parameter sensitivity analysis was carried out. Next, a history matching of the gel flooding experiment was carried out. Finally, history matching of the target reservoir was also carried out, and a gel flooding scheme was designed and optimized to determine the best parameters. The experimental results showed that the gelation time was 4 h and the gel viscosity was 6332 mPa·s; the breakthrough pressure, resistance factor (RF), and residual resistance factor (RRF) all decreased with the increase in permeability. The gel had a good profile control ability and improved oil recovery by 16.40%. The numerical simulation results illustrated that the porosity of the high permeability layer (HPL) had the greatest impact on the cumulative oil production (COP) of the HPL, and the maximum polymer adsorption value of the HPL had the largest influence on the COP of the low permeability layer (LPL) and the water cut of both layers. Benefiting from parameter sensitivity analysis, history matching of the gel flooding experiment and a conglomerate reservoir in the Xinjiang A Oilfield with less time consumed and good quality was obtained. The optimization results of gel flooding during the high water cut stage in a conglomerate reservoir of the Xinjiang A Oilfield were as follows: the gel injection volume, injection rate, and polymer concentration were 2000 m3, 50 m3/d, and 2500 mg/L, respectively. It was predicted that the water cut would decrease by 6.90% and the oil recovery would increase by 2.44% in two years. This paper not only provides a more scientific and efficient optimization method for gel flooding in conglomerate reservoirs but also has important significance for improving the oil recovery of conglomerate reservoirs.