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.

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.

Summary: Because of complex chemical reactions and multiphase flow physics, the displacement front stability for in-situ combustion (ISC) enhanced oil recovery (EOR) processes are not well understood. In this work, theory and numerical simulation validation are presented to establish an analytical frontal stability criterion for ISC processes.First, the four influencing factors for ISC displacement stability are analyzed: viscous force, heat conduction, matrix permeability changes caused by coke deposition, and gravity. A thorough analysis of the different zones and displacement fronts in a typical ISC process is conducted, and the most unstable front with the strongest tendency for gravity override is identified. Second, analytical solutions for judging the frontal stability and gravity override are established. Third, numerical reservoir simulation is performed to study the frontal stability and gravity override to validate the analytical theory. Carefully selected numerical schemes, as well as spatial and temporal discretization, are used to ensure the accuracy of these simulations.The four major zones and three displacement fronts (combustion front, leading edge of steam plateau, and oil bank leading edge) are identified in a typical 1D ISC process. The most unstable front with the largest pressure gradient contrast is the leading edge of the steam plateau. Gravity override also first takes place here with large fluid density differences across the front. By establishing material and energy balances and solving the wavy perturbation of the steam front, an analytical equation for deciding the ISC flood front stability in a 2D horizontal plane is achieved. Furthermore, the analytical solution for ISC gravity override is established. In numerical simulations, we are able to obtain results with sufficient accuracy to capture unstable ISC displacements and show fingering behavior under different conditions. The matrix permeability reduction caused by coke deposition has minimal impact on frontal stability. The simulation results are successfully validated with the analytical work for conditions in which the ISC process is stable or unstable and also for the degree of ISC gravity override. This demonstrates the predictive capability of the analytical method.In summary, a theoretical framework to analyze whether the displacement front of an ISC process is stable or not has been established. Numerical simulations confirm its predictive capability. This serves as a new reservoir engineering tool to aid the implementation and design of practical ISC projects.

Advancements in horizontal drilling with hydraulic fracturing have enabled commercial oil production from tight oil reservoirs. However, the primary recovery factor remains very low, usually less than 15%. It is a big challenge to supply formation drive energy to sustain production. After hydraulic fracturing, there is often pre-mature water breakthrough or gas channeling when we inject water or gas. Therefore, CO₂ huff-n-puff becomes an attractive option to improve oil recovery in tight oil reservoirs. Based on typical reservoir and fracture properties in Ordos Long-7 tight oil reservoir, a compositional reservoir simulation model with hydraulic fracture network was established to evaluate the performance of CO₂ huff-n-puff enhanced oil recovery (EOR) method. Through numerical simulation, we perform sensitivity study to explore the impacts of operation parameters such as CO₂ injection rate, injection time, soaking time, number of huff-n-puff cycles on EOR performance. Some of these parameters have rarely been investigated for recovery in tight reservoirs, such as in-situ fluid composition, fracture pore volume and hydraulic fracture characterization. Furthermore, correlation analysis is used to evaluate the performance of CO2 huff-n-puff process. In this study, we find that hydraulic fracture morphology and fracture conductivity can have a large impact on the performance of CO₂ huff-n-puff. Due to the existence of natural fractures in tight reservoirs and the stimulated reservoir volume, CO₂ huff-n-puff can not only mobilize the crude oil near the well, but also have certain recovery effects on the remaining oil between the adjacent wells. Simulation results show that the most important parameter is number of cycles, followed by CO₂ injection rate and soaking time. It is found that the optimum injection pressure of CO₂ huff-n-puff process can be set around the minimum miscibility pressure (MMP) for CO₂ and the crude. We set the soaking time period to be 30 days, injection rate to be 150 ton/day, number of cycles to be 4 for optimized oil recovery. The incremental oil recovery factor after one cycle is 1.59%, and the output-to-input ratio is 1:1.75. The findings in this work have the potential to advance our understandings of the role of CO₂ EOR in developing unconventional oil reservoirs, which will benefit both the energy industry and the environment with the potential benefit of CO₂ geological sequestration.

In-situ combustion simulation from laboratory to field scale has always been challenging, due to difficulties in deciding the reaction model and Arrhenius kinetics parameters, together with erroneous results observed in simulations when using large-sized grid blocks. We present a workflow of successful simulation of heavy oil in-situ combustion process from laboratory to field scale. We choose the ongoing PetroChina Liaohe D block in-situ combustion project as a case of study. First, we conduct kinetic cell (ramped temperature oxidation) experiments, establish a suitable kinetic reaction model, and perform corresponding history match to obtain Arrhenius kinetics parameters. Second, combustion tube experiments are conducted and history matched to further determine other simulation parameters and to determine the fuel amount per unit reservoir volume. Third, we upscale the Arrhenius kinetics to the upscaled reaction model for field-scale simulations. The upscaled reaction model shows consistent results with different grid sizes. Finally, field-scale simulation forecast is conducted for the D block in-situ combustion process using computationally affordable grid sizes. In conclusion, this work demonstrates the practical workflow for predictive simulation of in-situ combustion from laboratory to field scale for a major project in China.

We present the workflow for numerical reservoir simulation of supercritical multi-source and multi-component steam injection for offshore heavy oil development. We have developed unique techniques in a commercial reservoir simulator to implement the thermal properties of supercritical multi-source and multi-component steam, the pyrolysis chemical reactions, the temperature-dependent relative permeability, and the process of partially dissolving the sandstone rock to enhance the matrix permeability in a commercial reservoir simulator. Simulations are conducted on the type pattern reservoir model, which represents one of the heavy oil fields in CNOOC’s Bohai Bay oil field. Simulation input parameters are calibrated based on laboratory experiments conducted for supercritical multi-source and multi-component steam injection. Simulation results have shown clear improvements in injecting supercritical multi-source and multi-component steam in offshore heavy oil reservoirs compared to the normal steam injection process using subcritical steam. This serves as a workflow for implementing a numerical simulation of the novel supercritical multi-source and multi-component steam injection recovery process.