Search

Reservoir heterogeneity, water-oil mobility ratio, cementation degree, and strong injection and production significantly influence long-term waterflooding and polymer flooding processes in oil reservoir development, leading to the formation of low-resistance dominant seepage channels in the lower part of thick oil layers without internal laminations. Understanding the spatial distribution and evolution of dominant seepage channels in oil reservoirs during waterflooding and polymer flooding is crucial for improving reservoir development and recovery rates. It uses a streamlined numerical simulation method to quantitatively show the spatial and temporal distribution of dominant seepage channels in the oil reservoir. A model and chart were created to demonstrate the relationship between permeability and throat radius, capturing changes in reservoir permeabilities over time. The study developed a comprehensive mathematical model to identify dominant seepage channels, considering parameters such as inter-well flow ratio, injection efficiency, permeability change value, and water saturation. Research findings indicate a 14.8 % increase in reservoir permeability after polymer flooding, with slight changes in porosity and a 20.3 % decrease in clay content. The established mathematical model and identification criteria were used to comprehensively quantitatively evaluate flow channels, describing the distribution characteristics and evolution process of dominant seepage channels in the experimental area over four periods: pre-polymer flooding, low water-saturation period during polymer flooding, post-polymer injection, and subsequent 10 years of water flooding. Both polymer flooding and subsequent water flooding have significantly altered the distribution pattern of predominant fluid pathways: 254 well layers now demonstrate robust predominant fluid pathways (19 %); another 272 well layers feature moderately predominant fluid pathways (22 %); while an additional 440 well layers display weaker predominant fluid pathways (approximately 35 %). There has been a noticeable increase in both weak and moderate predominant fluid pathways, which are now more widespread in the area. However, localized occurrences of strong predominant fluid pathways persist with no significant change in their distribution characteristics. Analysis at four different time points shows a clear trend of increasing intensity as we move from polymer to subsequent water flooding in this decade. Additionally, examination along an axis from upper left to lower right reveals a linear progression that indicates clear connections among different categories of dominant seepage channel. The verification results show a strong correlation between the calculated dominant seepage channel distribution and actual water-injection profile test results, indicating that the method effectively identifies dominant seepage channels in oil reservoirs after polymer flooding and has the potential to enhance oil recovery further. [ABSTRACT FROM AUTHOR]

Understanding polymer retention is a critical aspect in the field of chemical-enhanced oil recovery (cEOR). This article presents a comprehensive review of polymer retention in reservoir rocks, focusing on the underlying mechanisms, measurement techniques, and the factors influencing this phenomenon. Three main (proposed) mechanisms that contribute to polymer retention are discussed in detail. Polymer adsorption, hydrodynamic retention, and mechanical entrapment are identified as key factors affecting the overall retention of polymers during flow through porous media. Also, herein, we explore the details of these mechanisms, explaining how polymer characteristics and rock surface properties influence the degree of retention. Furthermore, we analyze the influencing factors that affect polymer retention. The rock surface properties, such as surface charge and wettability, play a vital role in determining the interaction between polymers and rocks. The interplay of these factors provides valuable insights into understanding and controlling polymer retention in cEOR applications. This review paper put in a nutshell a comprehensive understanding of the mechanisms, measurement techniques, and influencing factors involved. [ABSTRACT FROM AUTHOR]

To solve the problems of shear degradation and injection difficulties in conventional polymer flooding, the capsule polymer flooding for enhanced oil recovery (EOR) was proposed. The flow and oil displacement mechanisms of this technique were analyzed using multi-scale flow experiments and simulation technology. It is found that the capsule polymer flooding has the advantages of easy injection, shear resistance, controllable release in reservoir, and low adsorption retention, and it is highly capable of long-distance migration to enable viscosity increase in deep reservoirs. The higher degree of viscosity increase by capsule polymer, the stronger the ability to suppress viscous fingering, resulting in a more uniform polymer front and a larger swept range. The release performance of capsule polymer is mainly sensitive to temperature. Higher temperatures result in faster viscosity increase by capsule polymer solution. The salinity has little impact on the rate of viscosity increase. The capsule polymer flooding is suitable for high-water-cut reservoirs for which conventional polymer flooding techniques are less effective, offshore reservoirs by polymer flooding in largely spaced wells, and medium to low permeability reservoirs where conventional polymers cannot be injected efficiently. Capsule polymer flooding should be customized specifically, with the capsule particle size and release time to be determined depending on target reservoir conditions to achieve the best displacement effect. [ABSTRACT FROM AUTHOR]

A novel hydrophobic association copolymer (PAMA) was synthesized by incorporating acrylamide (AM), 2-acrylamide-2-methylpropanesulfonic acid (AMPS), cationic monomer (MEDDA), and methyl methacrylate (MMA). The properties of MMA copolymers with varying contents were analyzed using infrared spectroscopy, nuclear magnetic resonance spectroscopy, and scanning electron microscopy. Optimal overall performance of the solution was achieved when the MMA content reached 1.4 % w/w. Compared to pure PAAM (without MMA), the PAMA-1.4 % polymer exhibited superior viscoelasticity, temperature resistance, and shear resistance. This enhancement in PAMA performance can be attributed to the significant inhibition of intermolecular water film formation within the polymer matrix by MMA, effectively improving and regulating solution solubility while strengthening molecular chain interactions and enhancing the structural network strength of PAMA polymers. Additionally, the inclusion of MMA transformed rock surfaces from non-wetting to wetting conditions, thereby greatly improving oil displacement efficiency. In displacement experiments, PAMA-1.4 % performed better in terms of enhanced oil recovery, the recovery rate of 0.1 % w/w PAMA-2.4 % solution is only 7.78 %, while the recovery rate of 0.1 % w/w PAMA-1.4 % solution is 13.06 %. [ABSTRACT FROM AUTHOR]

Copyright of Special Oil & Gas Reservoirs is the property of Special Oil & Gas Reservoirs Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Reservoir heterogeneity, water-oil mobility ratio, cementation degree, and strong injection and production significantly influence long-term waterflooding and polymer flooding processes in oil reservoir development, leading to the formation of low-resistance dominant seepage channels in the lower part of thick oil layers without internal laminations. Understanding the spatial distribution and evolution of dominant seepage channels in oil reservoirs during waterflooding and polymer flooding is crucial for improving reservoir development and recovery rates. It uses a streamlined numerical simulation method to quantitatively show the spatial and temporal distribution of dominant seepage channels in the oil reservoir. A model and chart were created to demonstrate the relationship between permeability and throat radius, capturing changes in reservoir permeabilities over time. The study developed a comprehensive mathematical model to identify dominant seepage channels, considering parameters such as inter-well flow ratio, injection efficiency, permeability change value, and water saturation. Research findings indicate a 14.8 % increase in reservoir permeability after polymer flooding, with slight changes in porosity and a 20.3 % decrease in clay content. The established mathematical model and identification criteria were used to comprehensively quantitatively evaluate flow channels, describing the distribution characteristics and evolution process of dominant seepage channels in the experimental area over four periods: pre-polymer flooding, low water-saturation period during polymer flooding, post-polymer injection, and subsequent 10 years of water flooding. Both polymer flooding and subsequent water flooding have significantly altered the distribution pattern of predominant fluid pathways: 254 well layers now demonstrate robust predominant fluid pathways (19 %); another 272 well layers feature moderately predominant fluid pathways (22 %); while an additional 440 well layers display weaker predominant fluid pathways (approximately 35 %). There has been a noticeable increase in both weak and moderate predominant fluid pathways, which are now more widespread in the area. However, localized occurrences of strong predominant fluid pathways persist with no significant change in their distribution characteristics. Analysis at four different time points shows a clear trend of increasing intensity as we move from polymer to subsequent water flooding in this decade. Additionally, examination along an axis from upper left to lower right reveals a linear progression that indicates clear connections among different categories of dominant seepage channel. The verification results show a strong correlation between the calculated dominant seepage channel distribution and actual water-injection profile test results, indicating that the method effectively identifies dominant seepage channels in oil reservoirs after polymer flooding and has the potential to enhance oil recovery further.

To solve the problems of shear degradation and injection difficulties in conventional polymer flooding, the capsule polymer flooding for enhanced oil recovery (EOR) was proposed. The flow and oil displacement mechanisms of this technique were analyzed using multi-scale flow experiments and simulation technology. It is found that the capsule polymer flooding has the advantages of easy injection, shear resistance, controllable release in reservoir, and low adsorption retention, and it is highly capable of long-distance migration to enable viscosity increase in deep reservoirs. The higher degree of viscosity increase by capsule polymer, the stronger the ability to suppress viscous fingering, resulting in a more uniform polymer front and a larger swept range. The release performance of capsule polymer is mainly sensitive to temperature. Higher temperatures result in faster viscosity increase by capsule polymer solution. The salinity has little impact on the rate of viscosity increase. The capsule polymer flooding is suitable for high-water-cut reservoirs for which conventional polymer flooding techniques are less effective, offshore reservoirs by polymer flooding in largely spaced wells, and medium to low permeability reservoirs where conventional polymers cannot be injected efficiently. Capsule polymer flooding should be customized specifically, with the capsule particle size and release time to be determined depending on target reservoir conditions to achieve the best displacement effect.

AbstractUnderstanding mechanical degradation is crucial for successful polymer flooding. In this study, the effects of stretching velocity, pore-throat ratio, polymer concentration, and migration distance on the mechanical degradation of HPAM were studied using a pore-throat model. Additionally, the contribution of tensile degradation at the entry point of the pore-throat model to the overall mechanical degradation was assessed through extrapolation. The experimental results indicate that tensile degradation at the entry point is the primary cause of the mechanical degradation, and its contribution is positively related to the flow rate. The mechanical degradation correlates positively with the stretching velocity (0.41 ∼ 6362s−1), pore-throat ratio (6 ∼ 60), and polymer concentration (500 ∼ 2200mg/L). Moreover, higher flow rate amplify the effects of changes in polymer concentration and pore-throat ratio on mechanical degradation. As the migration distance increases, the mechanical degradation initially increases and then stabilizes in the pore-throat model, whereas in the sand-packed model, the mechanical degradation continues to increase with increasing migration distance. This study enhances our understanding of polymer mechanical degradation and offers insights for developing strategies to reduce mechanical degradation and improve polymer-enhanced oil recovery. [ABSTRACT FROM AUTHOR]

Due to the poor salt resistance of polyaerylamide polymers, the technology of polymer flooding for enhanced oil recovery in high calcium and magnesium reservoirs is limited. By introducing the suspended microcrystalline polymer system, it becomes beneficial for the injection of water containing the high- concentration calcium and magnesium ions. The self-developed tackifier turns the calcium and magnesium ions into microcrystals, and associates the microcrystals with polymer molecules to form a local network. The structure of the three-dimensional macromolecules has the properties of anti-calcium and magnesium, thickening, and the increased viscosity of the polymer solution. The optimum concentration of dispersant and crystallization agent in suspended microcrystalline polymer system is 0.2% and 0.3%, respectively. The polymer is preferably hydrophobic associative polyaerylamide polymer. [ABSTRACT FROM AUTHOR]

Copyright of Special Oil & Gas Reservoirs is the property of Special Oil & Gas Reservoirs Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

In this research, it was attempted to describe in vitro the efficiency of a natural polymer synthesized from sugarcane waste by bacteria for application in enhanced crude oil recovery. Necessary experiments were carried out with the main targets of extraction and description of the polymer and its effectiveness in enhanced oil recovery. It is shown that in the polymer concentrations of 1, 2, 5, and 8 wt%, the viscosity is equal to 26.08, 76.51, 100.94, and 168.36 mPa s. A shear‐thinning flow behavior is observed at initial shear rates. The sandstone wettability alteration is observed through the contact angles at concentrations of 1, 2, 5, and 8 wt% that are 85.93°, 72.19°, 76.51°, and 71.09°, respectively. Based on salinity compatibility, the polymer work up to a salinity of 90 000 ppm and based on viscosity tests, up to a salinity of 120 000 ppm. Regarding the performance of the polymer solution against temperature, it shows an acceptable performance in increasing the viscosity at the highest temperature of 75 °C. The water cut reaches its minimum of 8%, and then increases. By injecting 3.3 Pore volum (PV), the oil recovery reaches 81.4%. In a polymeric slug injection program, the oil recovery factor reaches 74.8%.Similarly, the water cut starts to decrease after the injection of polymer, and finally, after the injection of 0.9 PV including 0.5 PV of the polymer solution and 0.4 PV of water, reaches its minimum during the experiment, i.e., 22%. [ABSTRACT FROM AUTHOR]

Polymer flooding is a prominent enhanced oil recovery process that is widely recognized for its cost-effectiveness and substantial success in increasing oil production. In this study, the Buckley–Leverett mathematical model for polymer flooding was used to generate more than 163,000 samples that reflect different reservoir conditions using seven input parameters. We introduced artificial noise into the dataset to simulate real-world conditions and mitigate overfitting. Seven classic machine learning models and two neural networks were trained on this dataset to predict the oil recovery factor based on the input parameters. Among these, polynomial regression performed best with a coefficient of determination ( R 2 ) of 0.909, and the dense neural network and cascade-forward neural network achieved R 2 scores of 0.908 and 0.906, respectively. Our analysis included permutation feature importance and metrics analysis, where key features across all models were identified, and the model's performance was evaluated on a range of metrics. Compared with similar studies, this research uses a significantly larger and more realistic synthetic dataset that explores a broader spectrum of machine learning models. Thus, when applied to a real dataset, our methodology can aid in decision-making by identifying key parameters that enhance oil production and predicting the oil recovery factor given specific parameter values. [ABSTRACT FROM AUTHOR]

Polymer flooding is an effective development technology to enhance oil recovery, and it has been widely used all over the world. However, after long-term polymer flooding, a large number of oilfields have experienced a sharp decline in reservoir development efficiency. High water cut wells, serious dispersion of residual oil distribution and complex reservoir conditions all bring great challenges to enhance oil recovery. In this study, the method of enhancing oil recovery after polymer flooding was studied by taking the S Oilfield as an example. A surfactant–polymer system suitable for high-permeability heterogeneous oilfields was developed, comprising biogenic surfactants and polymers. Microscopic displacement experiments were conducted using cast thin sections from the S Oilfield, and nuclear magnetic resonance was employed for core displacement experiments. Numerical simulation experiments were also conducted on the S Oilfield. The results show that the enhanced oil recovery mechanism of the surfactant–polymer system is to adjust the flow direction, expand the swept volume, emulsify crude oil and reduce interfacial tension. Surfactant–polymer flooding proves to be effective in improving recovery efficiency, significantly reducing the time of flooding and further enhancing the strong swept area. The nuclear magnetic resonance results indicate a high amplitude of passive utilization of residual oil during the surfactant–polymer flooding stage, highlighting the enormous potential for an increased recovery ratio. Surfactant–polymer flooding emerges as a more suitable technique to enhance oil recovery in the post polymer-flooding stage in high-permeability heterogeneous oilfields. [ABSTRACT FROM AUTHOR]

In order to effectively adjust reservoir heterogeneity and further exploit the remaining oil, a new type of low-viscosity gel was prepared by adding a regulating agent, retarder, and reinforcing agent on the basis of a polymer + Cr3+ crosslinking system. The new gel has the advantages of low initial viscosity, a slow gel formation rate, and high strength after gel formation. The effectiveness of the gel was verified through three-layer core displacement experiments, and the injection scheme was optimized by changing the slug combination of the polymer and the gel. The results showed that the gel can effectively block the high-permeability layer and adjust reservoir heterogeneity. An injection of 0.1 pore volume (PV) low-initial-viscosity gel can improve oil recovery by 5.10%. By changing the slug combination of the gel and polymer, oil recovery was further increased by 3.12% when using an injection of 0.07 PV low-initial-viscosity gel +0.2 PV high-concentration polymer +0.05 PV low-initial-viscosity gel +0.5 PV high-concentration polymer. [ABSTRACT FROM AUTHOR]

Copyright of Oilfield Chemistry is the property of Sichuan University, Oilfield Chemistry Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Polymer flooding has proved an effective technique to improve development efficiency in heterogeneous reservoirs. Previously, operators usually employed continuous injection of large polymer slugs. However, problems existed including premature injection profile reversal during development, ineffective circulation of polymer solution in low-permeability zones, and excessive polymer consumption in the late development stage. The paper proposed a combination method, named as polymer-alternating-water (PAW), to solve the issues of traditional polymer flooding. The characteristic of this method is injecting water slugs between polymer slugs during the polymer flooding process. At present, research on the PAW technique is limited, with the operational parameters, oil recovery mechanisms, and applicability under various reservoir conditions remaining unclear. In this work, a numerical polymer flooding model is developed using the commercial CMG-STARS reservoir simulation module to investigate the oil displacement performance of PAW. Numerical simulations are performed to determine the optimal parameters for maximizing oil recovery factor. The results indicated compared with continuous polymer flooding, PAW shows multiple peaks in daily oil production rate, with a significantly decreased decline rate, resulting in a 1.47% increase in recovery factor. Under different reservoir conditions including mean permeability, heterogeneity, and crude oil viscosity, PAW can achieve further improvements on the basis of continuous polymer flooding. Polymer adsorption and injection concentration significantly impact the recovery factor, requiring further optimization for field applications. In this study, better polymer flooding performance was achieved when the number of alternating cycles of PAW was 2, and the injected alternating water slug volume was 50%. This study contributes to a deeper understanding of the key mechanisms and parameters in PAW enhanced oil recovery process, thereby providing guidance for the further optimization and field application of this technique. [ABSTRACT FROM AUTHOR]

As oil reserves are depleted during the development of an oil deposit in an elastic-water-pressure mode, the water cut of the fluid gradually increases, reducing the efficiency of waterflooding and maintaining reservoir pressure by the system of injection wells. The rheological characteristics of the saturating fluid and the structure of the reservoir affect the likelihood of premature watering of production wells. To increase oil production and level the displacement front, various polymer systems, both synthetic and biological, are used to promote additional oil production from previously untapped reservoir zones. There are technologies for both constant injection of a working agent with a polymer, and a slug of a polymer solution of a certain concentration with subsequent injection of water. The purpose of this work is to assess the effect of injection of xanthan solution on the oil displacement efficiency with subsequent injection of formation water. An experimental (laboratory) study was carried out on alternating injection of xanthan and formation water solutions to increase filtration resistance in flooded filtration channels. Inhomogeneous terrigenous core samples with different fracturing and filtration-capacitive properties were selected as a physical model for carrying out the experiments. The main results of the laboratory study are the dependence of the oil recovery factor and water cut on the injected volume of formation water. It is noted that the key factor in reducing the displacement efficiency after injection of a polymer slug is the loss of polymer molecules both after adsorption on the rock and during further filtration of formation water through diffusion. As a result of the experimental study, it was revealed that changing the filtration rate can have a beneficial effect on the involvement of oilsaturated rock in the displacement process due to the sealing of watered areas when the injection pressure changes.

Abstract Polymer flooding has proved an effective technique to improve development efficiency in heterogeneous reservoirs. Previously, operators usually employed continuous injection of large polymer slugs. However, problems existed including premature injection profile reversal during development, ineffective circulation of polymer solution in low-permeability zones, and excessive polymer consumption in the late development stage. The paper proposed a combination method, named as polymer-alternating-water (PAW), to solve the issues of traditional polymer flooding. The characteristic of this method is injecting water slugs between polymer slugs during the polymer flooding process. At present, research on the PAW technique is limited, with the operational parameters, oil recovery mechanisms, and applicability under various reservoir conditions remaining unclear. In this work, a numerical polymer flooding model is developed using the commercial CMG-STARS reservoir simulation module to investigate the oil displacement performance of PAW. Numerical simulations are performed to determine the optimal parameters for maximizing oil recovery factor. The results indicated compared with continuous polymer flooding, PAW shows multiple peaks in daily oil production rate, with a significantly decreased decline rate, resulting in a 1.47% increase in recovery factor. Under different reservoir conditions including mean permeability, heterogeneity, and crude oil viscosity, PAW can achieve further improvements on the basis of continuous polymer flooding. Polymer adsorption and injection concentration significantly impact the recovery factor, requiring further optimization for field applications. In this study, better polymer flooding performance was achieved when the number of alternating cycles of PAW was 2, and the injected alternating water slug volume was 50%. This study contributes to a deeper understanding of the key mechanisms and parameters in PAW enhanced oil recovery process, thereby providing guidance for the further optimization and field application of this technique.

Abstract A novel quaternary copolymer of AA/AM/AOS/C16‐DMAAC was synthesized with acrylic acid (AA), acrylamide (AM), sodium α‐alkenyl‐sulfonate (AOS), and dimethyl‐hexadecyl‐allyl‐ammonium chloride (C16‐DMAAC), using ammonium persulfate and sodium bisulfate (NH4)2S2O8‐NaHSO3) as initiators. The structure of AA/AM/AOS/C16‐DMAAC was characterized using Fourier transform infrared spectroscopy and nuclear magnetic resonance hydrogen spectroscopy. It can be found that the thickening capacity, shearing resistance, temperature‐resistance, salt‐resistance, and emulsification properties of AA/AM/AOS/C16‐DMAAC were superior to those of most widely and cost‐effective partially hydrolyzed polyacrylamide (HPAM) solution at the same concentration. Specifically, the viscosity retention rate of AA/AM/AOS/C16‐DMAAC (3000 mg/L) solution was 86%, which was better than that of HPAM solution (52%) after 30 s of mechanical shearing at 28000 r/min. In addition, the enhanced oil recovery of AA/AM/AOS/C16‐DMAAC solution was 16% at 65 °C, which was about 1.5 times higher than that of HPAM solution (11%). Significantly, successful synthesis of zwitterionic quaternary copolymer emphasizes the importance of a systematic approach to designing appropriate copolymers for enhanced oil recovery. Highlights A novel zwitterionic quaternary copolymer of AA/AM/AOS/C16‐DMAAC was successfully synthesized. The performance on thickening capacity, shearing resistance, temperature‐resistance, salt‐resistance, and emulsification properties of AA/AM/AOS/C16‐DMAAC was superior to that of the most widely used partially hydrolyzed polyacrylamide (HPAM). The enhanced oil recovery of AA/AM/AOS/C16‐DMAAC (16%) was about 1.5 times higher than that of HPAM (11%).

Due to the deterioration of the structure of oil reserves, the demand for enhanced oil recovery technologies is increasing every year. These technologies are usually classified into the following: Chemical, gas, thermal and combined enhance oil recovery methods. Among the chemical methods, polymer flooding stands out. It has been actively studied since the middle of the last century and currently numbers hundreds of completed projects around the world. Despite the relatively long study period and the number of publications dedicated to polymer flooding, there is still a range of aspects requiring research and development as well as field testing. One of the crucial issues at the preparation stage of a polymer flooding project is necessity to select oilfield or pilot area to achieve the best possible technological and economic efficiency results. This article provides analysis of the key factors influencing effectiveness of polymer flooding implementation. The paper reflects historical evolution, i.e. expansion of the technology applicability limits. Their current values have been verified, based on the analysis of the experience of implementing the technology in extreme conditions. Applicability criteria has been established as well for the polymer flooding development. The paper includes development of a uniquely designed integrated methodology for screening, assessment and ranking of promising objects for the technology implementation. The methodology is designed on the basis of a background review of completed projects, as well as on the expertise of the specialists involved in the development and scientific support of chemical enhanced oil recovery projects implementation. The purpose of the methodology is to create a basic universal tool for an express assessment of the prospects for using polymer flooding in different fields, which a wide range of specialists in the oil and gas industry could apply. [ABSTRACT FROM AUTHOR]

A novel quaternary copolymer of AA/AM/AOS/C16‐DMAAC was synthesized with acrylic acid (AA), acrylamide (AM), sodium α‐alkenyl‐sulfonate (AOS), and dimethyl‐hexadecyl‐allyl‐ammonium chloride (C16‐DMAAC), using ammonium persulfate and sodium bisulfate (NH4)2S2O8‐NaHSO3) as initiators. The structure of AA/AM/AOS/C16‐DMAAC was characterized using Fourier transform infrared spectroscopy and nuclear magnetic resonance hydrogen spectroscopy. It can be found that the thickening capacity, shearing resistance, temperature‐resistance, salt‐resistance, and emulsification properties of AA/AM/AOS/C16‐DMAAC were superior to those of most widely and cost‐effective partially hydrolyzed polyacrylamide (HPAM) solution at the same concentration. Specifically, the viscosity retention rate of AA/AM/AOS/C16‐DMAAC (3000 mg/L) solution was 86%, which was better than that of HPAM solution (52%) after 30 s of mechanical shearing at 28000 r/min. In addition, the enhanced oil recovery of AA/AM/AOS/C16‐DMAAC solution was 16% at 65 °C, which was about 1.5 times higher than that of HPAM solution (11%). Significantly, successful synthesis of zwitterionic quaternary copolymer emphasizes the importance of a systematic approach to designing appropriate copolymers for enhanced oil recovery. Highlights: A novel zwitterionic quaternary copolymer of AA/AM/AOS/C16‐DMAAC was successfully synthesized.The performance on thickening capacity, shearing resistance, temperature‐resistance, salt‐resistance, and emulsification properties of AA/AM/AOS/C16‐DMAAC was superior to that of the most widely used partially hydrolyzed polyacrylamide (HPAM).The enhanced oil recovery of AA/AM/AOS/C16‐DMAAC (16%) was about 1.5 times higher than that of HPAM (11%). [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Because of their small particle size, excellent stability, high temperature tolerance, and salt tolerance, polymer nanoparticles are attracting a lot of attention in low-permeability reservoirs. In this study, SiO2, acrylamide (AM), and 2-acrylamido-2-methylpropanesulfonic acid (AMPS) were used to synthesize novel copolymer-grafted nano-silica particles (HPGN). HPGN's overall performance in low-permeability reservoirs was evaluated. The results demonstrate that the viscosity of a 2000 mg/L HPGN solution at 50 °C is 75.8 mPa·s, with high stability under high temperature, high salt, and shear conditions. More notably, the displacement experiment proved that under the condition of 18450 mg/L, a 2000 mg/L HPGN solution enhanced the recovery rate by 21.89%. This research indicates that HPGN has great applicability potential in low-permeability reservoirs with high temperatures and salinities. [ABSTRACT FROM AUTHOR]

The Saffman‐Taylor instability of polymeric fluids flooding through saturated heterogeneous porous media is studied numerically. The displacement of a Newtonian fluid by a viscoelastic liquid is examined using a Hartley transformation and a fourth‐order Adams‐Bashforth technique. The flow is assumed to be miscible, and the Carreau‐Yasuda equation is used to model the shear‐thinning viscometric functions. The effects of different rheological properties and domain parameters on flow instability are studied in detail. It is found that a channeling regime is possible as the main difference between displacements through homogeneous and heterogeneous media. [ABSTRACT FROM AUTHOR]

In polymer flooding, the residual polymer in the produced fluid can increase the stability of crude oil emulsion, thereby negatively affecting the demulsification process. Therefore, a polymer that has no effect on the stability of crude oil emulsion is required. Herein, a polymerizable monomer with a demulsification function (MD) was synthesized and then copolymerized with acrylamide, acrylic acid, and 2‐acrylamide‐2‐methylpropane sulfonic acid to prepare a novel copolymer (self‐demulsifying polymer, PDM). The dissolution time, solution viscosity, shear resistance, static adsorption on quartz sand, and the effect on the crude oil emulsion stability of PDM were compared with those of regular polyacrylamide (PAM). Experimental results showed that owing to the steric hindrance effect of MD, the molecular weight of PDM was lower than that of PAM. Both polymers exhibited satisfactory solubility, solution viscosity, shear resistance, and static adsorption, which can meet the requirements of polymer for use in oil displacement. However, in contrast to PAM, PDM had no negative effect on the crude oil emulsion stability. This study provides a new solution to the problem of increased crude oil emulsion stability in polymer flooding. [ABSTRACT FROM AUTHOR]

Polyacrylamide (PAM) is one of the most critical materials in polymer flooding technology. However, the reservoir environment with high temperature, high pressure and high salinity will degrade PAM, which will reduce its viscosity and affect the recovery rate. In addition, previous studies lacked in-depth research on the PAM degradation mechanism and viscosity stabilization strategies. Therefore, the degradation mechanism of PAM solution in polymer flooding technology (including mechanical degradation, thermal degradation, free radical degradation, and biodegradation) and corresponding anti-degradation measures was introduced in this study, which provides a general strategy for effectively maintaining the viscosity of PAM solution. The conclusion shows that in order to maintain the viscosity of PAM solution, introducing functional monomer to modify PAM is the most essential and effective strategy. The combination of chemicals resistant to free radical degradation can further reduce viscosity loss and enhance oil recovery. The results of this study provide a comprehensive and systematic viscosity stabilization strategy that is important for PAM to reduce viscosity losses and enhance oil recovery in polymer flooding applications. In addition, modified PAM with low cost and resistance to free radical degradation should be developed in the future to meet the trend of future oil and gas resource development. [ABSTRACT FROM AUTHOR]

Polymer flooding in fractured wells has been extensively applied in oilfields to enhance oil recovery. In contrast to water, polymer solution exhibits non-Newtonian and nonlinear behavior such as effects of shear thinning and shear thickening, polymer convection, diffusion, adsorption retention, inaccessible pore volume and reduced effective permeability. Meanwhile, the flux density and fracture conductivity along the hydraulic fracture are generally non-uniform due to the effects of pressure distribution, formation damage, and proppant breakage. In this paper, we present an oil-water two-phase flow model that captures these complex non-Newtonian and nonlinear behavior, and non-uniform fracture characteristics in fractured polymer flooding. The hydraulic fracture is firstly divided into two parts: high-conductivity fracture near the wellbore and low-conductivity fracture in the far-wellbore section. A hybrid grid system, including perpendicular bisection (PEBI) and Cartesian grid, is applied to discrete the partial differential flow equations, and the local grid refinement method is applied in the near-wellbore region to accurately calculate the pressure distribution and shear rate of polymer solution. The combination of polymer behavior characterizations and numerical flow simulations are applied, resulting in the calculation for the distribution of water saturation, polymer concentration and reservoir pressure. Compared with the polymer flooding well with uniform fracture conductivity, this non-uniform fracture conductivity model exhibits the larger pressure difference, and the shorter bilinear flow period due to the decrease of fracture flow ability in the far-wellbore section. The field case of the fall-off test demonstrates that the proposed method characterizes fracture characteristics more accurately, and yields fracture half-lengths that better match engineering reality, enabling a quantitative segmented characterization of the near-wellbore section with high fracture conductivity and the far-wellbore section with low fracture conductivity. The novelty of this paper is the analysis of pressure performances caused by the fracture dynamics and polymer rheology, as well as an analysis method that derives formation and fracture parameters based on the pressure and its derivative curves. [ABSTRACT FROM AUTHOR]

Polymer flooding, one of the main methods for improving crude oil recovery using chemical flooding technology in China, is widely used for actual oil displacement. Partially hydrolyzed polyacrylamide (HPAM) is a commonly used linear polymer in polymer flooding, but it exhibits poor temperature and salt resistance due to its molecular structure. Therefore, branched polymers have been studied. This article provides a review of the specific synthetic methods and current practical applications in the petrochemical field of dendritic polymers and hyperbranched macromolecules. The advantages and disadvantages of each synthetic method for branched polymers are also elaborated. Finally, the application prospects of branched polymers are discussed. The feasibility of branched polymers in large quantities should be further verified through additional field tests, which should address concerns such as synthesis costs and reaction efficiency. [ABSTRACT FROM AUTHOR]

Steady-shear rheometry equipped with the perfect circular geometry has been used for decades to characterize the viscous characteristics of EOR polymer systems. Recently (Azad in SPE J, 2023), they have been successfully used to characterize the shear thickening characteristics of higher Mw (molecular weight)-higher elastic polymer systems. However, circular geometry fails to thicken the low Mw-lesser elastic polymer systems that exhibited thickening in consolidated porous media. Despite the fact that the different geometries could impose a different deformation, no effort was made to study the effect of non-circular geometry on their rheological behavior. This paper addresses this gap. The results indicate that non-circular geometry not only thickens the higher Mw-elastic systems strongly, but also the lower Mw-lesser elastic systems. Compared with concentric cylinder (CC) geometry, non-circular geometry better predicts the nonlinear viscoelastic properties of polymer systems especially those characterized by low Mw-low salinity-high concentration in porous media. However, CC appears to characterize the Newtonian behavior well and thereby suggests that the combination of both geometries could improve the selection criteria for viscoelastic polymer EOR applications. [ABSTRACT FROM AUTHOR]

Polymer flooding is an effective development technology to enhance oil recovery, and it has been widely used all over the world. However, after long-term polymer flooding, a large number of oilfields have experienced a sharp decline in reservoir development efficiency. High water cut wells, serious dispersion of residual oil distribution and complex reservoir conditions all bring great challenges to enhance oil recovery. In this study, the method of enhancing oil recovery after polymer flooding was studied by taking the S Oilfield as an example. A surfactant–polymer system suitable for high-permeability heterogeneous oilfields was developed, comprising biogenic surfactants and polymers. Microscopic displacement experiments were conducted using cast thin sections from the S Oilfield, and nuclear magnetic resonance was employed for core displacement experiments. Numerical simulation experiments were also conducted on the S Oilfield. The results show that the enhanced oil recovery mechanism of the surfactant–polymer system is to adjust the flow direction, expand the swept volume, emulsify crude oil and reduce interfacial tension. Surfactant–polymer flooding proves to be effective in improving recovery efficiency, significantly reducing the time of flooding and further enhancing the strong swept area. The nuclear magnetic resonance results indicate a high amplitude of passive utilization of residual oil during the surfactant–polymer flooding stage, highlighting the enormous potential for an increased recovery ratio. Surfactant–polymer flooding emerges as a more suitable technique to enhance oil recovery in the post polymer-flooding stage in high-permeability heterogeneous oilfields.

Polymer flooding is a prominent enhanced oil recovery process that is widely recognized for its cost-effectiveness and substantial success in increasing oil production. In this study, the Buckley–Leverett mathematical model for polymer flooding was used to generate more than 163,000 samples that reflect different reservoir conditions using seven input parameters. We introduced artificial noise into the dataset to simulate real-world conditions and mitigate overfitting. Seven classic machine learning models and two neural networks were trained on this dataset to predict the oil recovery factor based on the input parameters. Among these, polynomial regression performed best with a coefficient of determination (R2) of 0.909, and the dense neural network and cascade-forward neural network achieved R2 scores of 0.908 and 0.906, respectively. Our analysis included permutation feature importance and metrics analysis, where key features across all models were identified, and the model’s performance was evaluated on a range of metrics. Compared with similar studies, this research uses a significantly larger and more realistic synthetic dataset that explores a broader spectrum of machine learning models. Thus, when applied to a real dataset, our methodology can aid in decision-making by identifying key parameters that enhance oil production and predicting the oil recovery factor given specific parameter values.

After polymer flooding, the heterogeneity between different layers intensifies, forming intricate seepage channels and fluid diversions, which results in decreased circulation efficiency and lower recovery rates, leaving a significant amount of residual oil trapped within the reservoir. Understanding the characteristics of residual oil occurrence is crucial for enhancing oil recovery post-polymer flooding. This study focused on sandstone reservoirs with varying permeability in the Saertu block of the Daqing oilfield. Using cryosectioning and laser scanning confocal microscopy, the occurrence characteristics of the residual oil in these sandstone reservoirs post-polymer flooding were investigated. Additionally, micro-CT and scanning electron microscopy were employed to analyze the impact of the pore structure on the distribution characteristics of the residual oil. The results indicate that laser scanning confocal images reveal that post-polymer flooding, the residual oil in high- and low-permeability sandstone reservoirs predominantly exists in a bound state (average > 47%), mostly as particle-adsorbed oil. In contrast, the residual oil in medium-permeability reservoirs is primarily in a free state (average > 49%), mostly as intergranular-adsorbed oil. In high-permeability sandstone reservoirs, heavy oil components are mainly in a particle-adsorbed form; in medium-permeability sandstone reservoirs, residual oil predominantly consists of heavy components, with most light components occurring in a clustered form; in low-permeability sandstone reservoirs, clustered residual oil exists in a balanced coexistence of light and heavy components, while the heavy components primarily exist in a particle-adsorbed form. Post-polymer flooding, the large pore–throat structure in high-permeability sandstone reservoirs results in effective displacement and less free residual oil; medium-permeability sandstone reservoirs, with medium–large pores and throats, have preferential channels and fine particles blocking the throats, leading to some unswept pores and more free residual oil; low-permeability sandstone reservoirs, with small pores and throats, exhibit weak displacement forces and poor mobility, resulting in more bound residual oil. The distribution and content of clay particles and clay minerals, along with the complex microscopic pore structure, are the main factors causing the differences in the residual oil occurrence states in sandstones with varying permeability.

This work presents the proposal design for the completion of a polymer flooding injector well with waterflood flow regulator valves (FRV) in a Colombian field, based on experimental evaluations at the laboratory, intending to reduce the mechanical degradation suffered by the polymer solution at the time of injection, which allows to maintain the design parameters of the improved recovery project and reach the expected recovery factor. An analysis of the parameters and variables that influence the mechanical degradation of the polymer solution during the injection process (polymer solution concentration and the diameters of the FRV) was carried out using one laboratory methodology based on the recommended practices for the evaluation of polymers used in enhanced oil recovery operations API RP63. This work focuses on the following highlights: Evaluation of a waterflood flow regulator valve through experimental tests for polymer flooding and the designing of an initial well completion strategy to minimize mechanical degradation. The proposed valve and diameter resulted in a reduction of only 15 percentage points in the mechanical degradation of the polymeric solution when compared to a commercial water valve. [ABSTRACT FROM AUTHOR]

The amphiphilic polymer has excellent performance and is expected to replace traditional polymer oil-displacing agent in China. In this study, the iso-viscosity method evaluates the oil displacement performance of the betaine-type amphiphilic polymers with different content of hydrophobic groups in high salinity reservoirs. Rheometer, emulsion stability analyzer, laser particle size analyzer, and visualization of microscopic displacement are used to explore their oil displacement mechanism. The results show that the content of hydrophobic groups, and the recovery ratio of polymer flooding shows a positive correlation. The difference in the displacement performance reflects the difference in the viscoelasticity of the displacement system and the ability to emulsify crude oil. The synergistic effect of the two aspects further improves the oil washing efficiency. This study provides a reference for the practical application of the amphiphilic polymer, providing a theoretical basis to select polymer flooding agents in high salinity reservoirs. [ABSTRACT FROM AUTHOR]

There have been some studies conducted about the single factor viscoelasticity of polymer solution or wettability effect on the micro-flow mechanism of polymer flooding. In this paper, the flow mechanism of polymer solution in dual heterogeneous reservoir considering the wettability and gravity was studied. The influences of wettability and rock particle shape on flow characteristics were studied based on the characteristics of saturation and pressure distribution. Compared with the simulation results of polymer flooding in three different rock particle shapes porous media, the oil displacement efficiency of the circular particle model is the highest at 91.57%, which is 3.34% and 11.48% higher than that in the hexagonal and diamond models, respectively. The influence of wettability was studied by the circular particle model. The oil displacement efficiency under water-wet conditions was higher than that under oil-wet conditions. The displacement process considering gravity was affected by the crossflow caused by gravity and viscous force, and the micro-oil displacement efficiency was 9.87% lower than that of non-gravity. Considering the wettability, vertical crossflow will be formed. The oil displacement efficiency under water-wet conditions was 3.9% higher than in oil-wet conditions. The research results can not only expand and enrich the micro-flow mechanism of viscoelastic polymer solution, but also provide reference and guidance for polymer flooding scheme design. [ABSTRACT FROM AUTHOR]

Increasing the efficiency of hydrocarbon field development is an important issue. One of the methods for increasing oil recovery is the injection of aqueous solutions of polymers. Although this method has been known and used for quite some time, further systematic research is needed to further improve its effectiveness. In this work, systematic computational studies of the features of oil displacement by aqueous polymer solutions from a naturally fractured structure were carried out. Direct numerical modeling of a two-phase immiscible flow in the process of displacing oil from a natural fracture structure using solutions of anionic polymers based on polyacrylamide was carried out. Aqueous solutions of three different polymers were considered, the concentrations of which varied from 0 to 0.1%, and the molecular weights were from 10 to 20 mln c.u. The rheological properties of polymers and their wetting characteristics have been previously studied in laboratory experiments. A distinctive feature of the polymers considered was the non-Newtonian nature of their aqueous solutions even at low concentrations. To take these processes into account, the computational technique has been extended to the case of non-Newtonian rheology for immiscible two-phase flow in one of the media. During numerical simulations, the effect of the concentration of polymers, their molecular weight, and charging density on the flow regimes in a fractured reservoir have been investigated systematically at various crude oil viscosities. It has been shown that the use of a 0.1% aqueous solution of polyacrymalide can increase the oil-recovery factor by 1.8 times. It has been established that, with an increase in the molecular weight and surface charge density of the polymer, the efficiency of its use for enhancing oil recovery increases. With an increase in the viscosity of the displaced oil, the effect of using the injection of the considered polymers also increases. The data obtained in this work can be used to further improve polymer-flooding technologies for oil fields. [ABSTRACT FROM AUTHOR]

Copyright of Revista ION is the property of Universidad Industrial de Santander and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)