Search Results (88)

Polymer flooding is a widely used enhanced oil recovery (EOR) method for improving energy efficiency and reducing the carbon footprint of oil production. Optimizing polymer concentration is critical for maximizing recovery while minimizing economic and environmental costs. Here, we present a systematic experimental study which shows that even very low concentrations of polymers yield relatively high recovery rates at adverse mobility ratios (230 cP oil). A series of core flood experiments were conducted on Bentheimer sandstone rock, with polymer concentrations ranging from 40 ppm (1.35 cP) to 600 ppm (10.0 cP). Beyond a mobility ratio threshold, increasing polymer concentration did not significantly enhance recovery. This plateau in performance was attributed to the persistence of viscous fingering and oil crossflow into pre-established water channels. The study suggests that low concentrations of polymer may mobilize oil at high mobility ratios by making use of the pre-established water channels as transport paths for the oil and that the rheology of the polymer enhances this effect. These findings enable reductions in the polymer concentration in fields with adverse mobility ratios, leading to substantial reductions in chemical usage, energy consumption, and environmental impact of the extraction process. Full article

As an enhanced oil recovery (EOR) technique, alkali/surfactant/polymer (ASP) flooding effectively mitigates production decline in mature oilfields through chemical flooding mechanisms. The breakthrough of ASP chemical agents poses challenges to the green and efficient separation of oilfield produced water. In this paper, sedimentation separation of produced water was simulated using the Eulerian method and the RNG k–ε model. In addition, the filtration process was simulated using a discrete phase model (DPM) and a porous media model. The distribution characteristics of oil/suspended solids obtained through simulation, along with the water quality parameters at each treatment node, were systematically extracted, and the influence of operating conditions on treatment capacity was analyzed. Simulations reveal that elevated treatment loads and produced water polymer concentrations synergistically impair ASP flooding produced water treatment efficiency. Fluctuations of operating conditions generate oil/suspended solids content in output water ranges spanning 13–78 mg/L and 19–92 mg/L, respectively. The interpolation method is adopted to determine the critical water quality parameters of each treatment node, ensuring that the treated produced water meets the treatment standards. The operating limits of the ASP flooding produced water treatment process are established. Full article

Polymer flooding is one of the critical methods for enhancing oil recovery (EOR) in domestic and international oilfields. Since the large-scale implementation of industrial polymer flooding in Daqing Oilfield in 1996, the overall recovery rate has increased by over 10%. With the advancement of chemical flooding technologies, conventional polymer flooding can no longer meet the practical demands of oilfield development. This study focuses on functional polymers, such as salt-resistant polymers and polymeric surfactants, tailored for Class II and III reservoirs in Daqing Oilfield. A series of experiments, including emulsification experiments, hydrodynamic characteristic size-reservoir compatibility comparison experiments, polymer retention experiments in porous media, and core flooding experiments, were conducted to investigate the differences between functional polymers and conventional polymers in terms of intrinsic properties and application performance. Comparative analyses of molecular chemical structures and micro-aggregation morphologies between functional polymers (branched polymers and polymeric surfactants) and conventional polymers revealed structural composition disparities and distinct viscosity-enhancing properties. From the perspective of aqueous solution viscosity enhancement mechanisms, functional polymers exhibit a three-stage viscosity-enhancing mechanism: bulk viscosity, associative viscosity, and emulsion-induced viscosity enhancement. The hydrodynamic characteristic sizes of polymers were analyzed to evaluate their compatibility with reservoir pore structures, and the seepage resistance mechanisms of both polymeric surfactants and salt-resistant polymers were identified. Core flooding experiments conclusively demonstrated the superior practical performance of functional polymers over conventional polymers. The application of functional polymers in polymer flooding can effectively enhance oil recovery. Full article

The scaling up of carbon capture, utilization, and storage (CCUS) deployment is constrained by multiple factors, including technological immaturity, high capital expenditures, and extended investment return periods. The existing research on CCUS investment decisions predominantly centers on coal-fired power plants, with the utilization pathways placing a primary emphasis on storage or enhanced oil recovery (EOR). There is limited research available regarding the chemical utilization of carbon dioxide (CO₂). This study develops an options-based analytical model, employing geometric Brownian motion to characterize carbon and oil price uncertainties while incorporating the learning curve effect in carbon capture infrastructure costs. Additionally, revenues from chemical utilization and EOR are integrated into the return model. A case study is conducted on a process producing 100,000 tons of methanol annually via CO₂ hydrogenation. Based on numerical simulations, we determine the optimal investment conditions for the “CO₂-to-methanol + EOR” collaborative scheme. Parameter sensitivity analyses further evaluate how key variables—carbon pricing, oil market dynamics, targeted subsidies, and the cost of renewable electricity—influence investment timing and feasibility. The results reveal that the following: (1) Carbon pricing plays a pivotal role in influencing investment decisions related to CCUS. A stable and sufficiently high carbon price improves the economic feasibility of CCUS projects. When the initial carbon price reaches 125 CNY/t or higher, refining–chemical integrated plants are incentivized to make immediate investments. (2) Increases in oil prices also encourage CCUS investment decisions by refining–chemical integrated plants, but the effect is weaker than that of carbon prices. The model reveals that when oil prices exceed USD 134 per barrel, the investment trigger is activated, leading to earlier project implementation. (3) EOR subsidy and the initial equipment investment subsidy can promote investment and bring forward the expected exercise time of the option. Immediate investment conditions will be triggered when EOR subsidy reaches CNY 75 per barrel or more, or the subsidy coefficient reaches 0.2 or higher. (4) The levelized cost of electricity (LCOE) from photovoltaic sources is identified as a key determinant of hydrogen production economics. A sustained decline in LCOE—from CNY 0.30/kWh to 0.22/kWh, and further to 0.12/kWh or below—significantly advances the optimal investment window. When LCOE reaches CNY 0.12/kWh, the project achieves economic viability, enabling investment potentially as early as 2025. This study provides guidance and reference cases for CCUS investment decisions integrating EOR and chemical utilization in China’s refining–chemical integrated plants. Full article

The development of eco-friendly surfactants is pivotal for enhanced oil recovery (EOR). In this study, a novel lignin-derived zwitterionic surfactant (DMS) was synthesized through a two-step chemical process involving esterification and free radical polymerization, utilizing renewable alkali lignin, maleic anhydride, dimethylamino propyl methacrylamide (DMAPMA), and sulfobetaine methacrylate (SBMA) as precursors. Comprehensive characterization via ¹H NMR, FTIR, and XPS validated the successful integration of amphiphilic functionalities. Hydrophilic–lipophilic balance (HLB) analysis showed a strong tendency to form stable oil-in-water (O/W) emulsions. The experimental results showed a remarkable 91.6% viscosity reduction in Xinjiang heavy crude oil emulsions at an optimum dosage of 1000 mg/L. Notably, DMS retained an 84.8% viscosity reduction efficiency under hypersaline conditions (total dissolved solids, TDS = 200,460 mg/L), demonstrating exceptional salt tolerance. Mechanistic insights derived from zeta potential measurements and molecular dynamics simulations revealed dual functionalities: interfacial modification by DMS-induced O/W phase inversion and electrostatic repulsion (zeta potential: −30.89 mV) stabilized the emulsion while disrupting π–π interactions between asphaltenes and resins, thereby mitigating macromolecular aggregation in the oil phase. As a green, bio-based viscosity suppressor, DMS exhibits significant potential for heavy oil recovery in high-salinity reservoirs, addressing the persistent challenge of salinity-induced inefficacy in conventional chemical solutions and offering a sustainable pathway for enhanced oil recovery. Full article

This study is dedicated to fundamental research on evaluating the effectiveness of enhanced oil recovery (EOR) methods for high-viscosity oil reservoirs. This paper presents the results of filtration experiments assessing the application of thermal, chemical, and gas-based EOR techniques to reservoir cores of high-viscosity oil, using the East Moldabek field in Kazakhstan as a case study. Experimental studies were conducted on the Cretaceous horizons M-II and M-III as well as the Jurassic horizon J-IV. The obtained production data from the East Moldabek wells indicated the low efficiency of conventional recovery methods. The objective of this study was to identify the most effective EOR method in terms of displacement efficiency. The investigated recovery techniques included base case conventional waterflooding (displacement using formation water), thermal EOR (hot-water flooding), chemical EOR (polymer flooding and ASP flooding), and gas EOR (nitrogen and CO₂ flooding). The filtration experiments were conducted at different times using various filtration systems. The results indicated that the most effective EOR methods for the highly viscous oil in the East Moldabek field were the chemical and thermal EOR techniques. The chemical EOR included ASP flooding, polymer flooding, and surfactant solution injection. ASP flooding achieved the highest increase in displacement efficiency, reaching 19%, making it the most effective method among all of the others. Full article

This paper presents a review of modern methods and technologies for extracting high- (HVO) and extra-high-viscous oil (EHVO). Special attention is given to thermal, physico-chemical, and combined enhanced oil recovery (EOR) methods based on the synergistic effect of these approaches. Theoretical aspects of these technologies, their applicability limits, and their practical implementation are considered. The article describes the main complicating factors in the extraction of HVO and EHVO using the reviewed methods, one of which is the high water cut in well production. We analyse the mechanisms of water production in HVO and EHVO fields. The paper highlights the experience of developing HVO and EHVO fields, primarily in Russia, and examines laboratory and field studies, ongoing projects, and future prospects. The authors of this paper have analysed the available literature and have provided further recommendations for studying these technologies. We hope that this work will be useful to all those interested in the challenges of oil production. Full article

As an efficient and economical method to enhance oil recovery (EOR), it is very important to explore the applicability of chemical flooding under harsh reservoir conditions, such as high temperature and high salinity. We designed microscopic visualization oil displacement experiments to comprehensively evaluate the oil displacement performance of the zwitterionic surfactant betaine (BSB), a temperature- and salinity-resistant hydrophobically modified polymer (BHR), and surfactant–polymer (SP) binary systems. Based on macroscopic properties and microscopic oil displacement effects, we confirmed that the BSB/BHR binary solution has the potential to synergistically improve oil displacement efficiency and quantified the reduction in residual oil and oil displacement efficiency within the swept range. The experimental results show that after water flooding, a large amount of residual oil remains in the porous media in the form of clusters, porous structures, and columnar formations. After water flooding, only slight emulsification occurred after the injection of BSB solution, and the residual oil could not be activated. The injection of polymer after water flooding can expand the swept range to a certain extent. However, the distribution of residual oil in the swept range is similar to that of water flooding, and the oil washing efficiency is low. The SP binary flooding process can expand sweep coverage and effectively decompose large oil clusters simultaneously. This enhances the oil washing efficiency within the swept area and can significantly improve oil recovery. Finally, we obtained the microscopic oil displacement mechanism of BSB/BHR binary system to synergistically increase the swept volume and effectively activate the residual oil after water flooding. It is the result of the combined action of low interfacial tension (IFT) and suitable bulk viscosity. These findings provide critical insights for optimizing chemical flooding strategies in high-temperature and high-salinity reservoirs, significantly advancing EOR applications in harsh environments. Full article

This paper summarizes the research progress and applications of oxygen-reduced-air-assisted gravity drainage (OAGD) in enhanced oil recovery (EOR). The fundamental principles and key technologies of OAGD are introduced, along with a review of domestic and international field trials. Factors influencing displacement performance, including low-temperature oxidation reactions, injection rates, and reservoir dip angles, are discussed in detail. The findings reveal that low-temperature oxidation significantly improves the recovery efficiency through the dynamic balance of light hydrocarbon volatilization and fuel deposition, coupled with the synergistic optimization of the reservoir temperature, pressure, and oxygen concentration. Proper control of the injection rate stabilizes the oil–gas interface, expands the swept volume, and delays gas channeling. High-dip reservoirs, benefiting from enhanced gravity segregation, demonstrate superior displacement efficiency. Finally, the paper highlights future directions, including the optimization of injection parameters, deepening studies on reservoir chemical reaction mechanisms, and integrating intelligent gas injection technologies to enhance the effectiveness and economic viability of OAGD in complex reservoirs. Full article

The Bohai oilfield is characterized by severe heterogeneity and high average permeability, leading to a low water flooding recovery efficiency. Polymer flooding only works for a certain heterogeneous reservoir. Therefore, supplementary technologies for further enlarging the swept volume are still necessary. Based on the concept of discontinuous chemical flooding with multi slugs, three chemical systems, which were polymer gel (PG), hydrophobically associating polymer (polymer A), and conventional polymer (polymer B), were selected as the profile control and displacing agents. The optimization design of the discontinuous chemical flooding was investigated by core flooding experiments and displacement equilibrium degree calculation. The gel, polymer A, and polymer B were classified into three levels based on their profile control performance. The degree of displacement equilibrium was defined by considering the sweep conditions and oil displacement efficiency of each layer. The effectiveness of displacement equilibrium degree was validated through a three-core parallel displacement experiment. Additionally, the parallel core displacement experiment optimized the slug size, combination method, and shift timing of chemicals. Finally, a five-core parallel displacement experiment verified the enhanced oil recovery (EOR) performance of discontinuous chemical flooding. The results show that the displacement equilibrium curve exhibited a stepwise change. The efficiency of discontinuous chemical flooding became more significant with the number of layers increasing and heterogeneity intensifying. Under the combination of permeability of 5000/2000/500 mD, the optimal chemical dosage for the chemical discontinuous flooding was a 0.7 pore volume (PV). The optimal combination pattern was the alternation injection in the form of “medium-strong-weak-strong-weak”, achieving a displacement equilibrium degree of 82.3%. The optimal shift timing of chemicals occurred at a water cut of 70%, yielding a displacement equilibrium degree of 87.7%. The five-core parallel displacement experiment demonstrated that discontinuous chemical flooding could get a higher incremental oil recovery of 24.5% compared to continuous chemical flooding, which presented a significantly enhanced oil recovery potential. Full article

This study presents a novel Enhanced Oil Recovery (EOR) method using Smart Black Nanocards (SLNs) to mitigate the environmental impact of conventional thermal recovery, especially under global warming. Unlike prior studies focusing on wettability alteration via adsorption, this research innovatively models ‘oil film detachment’ in a reservoir simulator to achieve wettability alteration. Using the CMG-STARS (2020) simulator, this study highlights SLNs’ superior performance over traditional chemical EOR and spherical nanoparticles by reducing residual oil saturation and shifting wettability toward water-wet conditions. The structural disjoining pressure (SDP) of SLNs reaches 20.99 × 10³ Pa, 16.5 times higher than spherical particles with an 18.5 nm diameter. Supported by the Percus–Yevick (PY) theory, the numerical model achieves high accuracy in production history matching, with oil recovery and water cut fitting within precision error ranges of 0.02 and 0.05, respectively. This research advances chemical EOR technologies and offers an environmentally sustainable, efficient recovery strategy for low-permeability and heavy oil reservoirs, serving as a promising alternative to thermal methods. Full article

Alkali–surfactant–polymer (ASP) flooding is one of the most effective and promising ways to enhance oil recovery (EOR). The synergistic effect between alkali, surfactant, and polymer can respectively promote emulsification performance, reduce interfacial tension, and improve bulk phase viscosity, thus effectively improving flooding efficiency. However, the displacement mechanism of ASP flooding and the contribution of different components to the oil displacement effect still need further discussion. In this study, five groups of chemical slugs were injected into the fracture model after water flooding to characterize the displacement effect of weak alkali, surfactant, polymer, and their binary/ternary combinations on residual oil. Additionally, the dominant mechanism of the ASP flooding system to improve the recovery was studied. The results showed that EOR can be improved through interfacial reaction, low oil/water interfacial tension (IFT), and increased viscosity. In particular, the synergistic effect of ASP includes sweep and oil washing. As for sweep, the swept volume is expanded by the interfacial reaction between the alkali and the acidic components in Daqing crude oil, and the polymer increases the viscosity of the system. As for oil washing, the surfactant generated by the alkali cooperates with surfactants to reduce the IFT to an ultra-low level, which promotes the formation and migration of oil-in-water emulsions and increases the efficiency of oil washing. Overall, ASP can not only activate discontinuous oil ganglia in the pores within the water flooding range, but also emulsify, decompose, and migrate the continuous residual oil in the expanded range outside the water flooding. The EOR of ASP is 38.0% higher than that of water flooding. Therefore, the ASP system is a new ternary composite flooding technology with low cost, technical feasibility, and broad application prospects. Full article

Applying chemical enhanced oil recovery (EOR) to shale and tight formations is expected to accelerate China’s Shale Revolution as it did in conventional reservoirs. However, its screening and modeling are more complex. EOR operations are faced with choices of chemicals including traditional surfactant solutions, surfactant solutions in the form of micro-emulsions (nano-emulsions), and nano-fluids, which have similar effects to surfactant solutions. This study presents a systematic comparative analysis composed of laboratory screening and numerical modeling. It was conducted on three scales: tests of chemical morphology and properties, analysis of micro-oil-displacing performance, and simulation of macro-oil-increasing effect. The results showed that although all surfactant solutions had the effects of reducing interfacial tension, altering wettability, and enhancing imbibition, the nano-emulsion with the lowest hydrodynamic radius is the optimal selection. This is attributed to the fact that the properties of the nano-emulsion match well with the characteristics of these shale and tight reservoirs. The nano-emulsion is capable of integrating into the tight matrix, interacting with the oil and rock, and supplying the energy for oil to flow out. This study provides a comprehensive understanding of the role that surfactant solutions could play in the EOR of unconventional reservoirs. Full article

Alkaline–surfactant–polymer (ASP) flooding by means of which alkali additives, surfactant and polymer are inserted as the same slug is one of the most favourable worldwide focuses of Chemical Enhanced Oil Recovery (cEOR) research and field trials, due to the individual synergy of the three chemical components. To develop efficient oil recovery chemicals, it is essential to fully understand the mechanism behind ASP flooding. Nonetheless, there are hardly any studies reporting a systematic characterization of the ASP process. Thus, the present paper focuses on modelling this process in a laboratory by the use of an anionic surfactant—sodium dodecyl sulphate (SDS) in alkaline–polymer media—which is composed of a commercial water-soluble polymer (Flopaam AN125SH^®, SNF Floerger, Andrézieux-Bouthéon, France) and alkali compounds (NaOH and Na₂CO₃). The samples were characterized using rheometry, dynamic light scattering (DLS), infrared spectroscopy (IR) and measurement of inferfacial tension (IFT) between the samples and rapeseed oil. In accordance with the experimental results, surprisingly lower IFT values were recorded between the alkaline–polymer solutions and rapeseed oil than the samples which contained SDS. Increasing polymer and sodium chloride concentration caused a decrease (from 0.591 mN/m to 0.0486 mN/m) in IFT between the surfactant containing samples and rapeseed oil. The IR measurements confirmed that the surfactant was not detected in the oil phase in the absence of NaOH and Na₂CO₃. The effects of SDS on the viscosity of the mixtures were also investigated, as viscosity is a considerably important parameter in processes using polymers. Full article

The Gasi reservoir in the Qinghai oilfield is a typical high-temperature and high-salinity reservoir, with an average temperature and average salinity of 70.0 °C and 152,144 mg/L, respectively. For over 30 years since 1990, water flooding has been the primary method for enhancing oil recovery. Recently, the Gasi reservoir has turned into a mature oilfield. It possesses a high water cut of 76% and a high total recovery rate of 47%. However, the main developing enhanced oil recovery (EOR) technology for the development of the Gasi reservoir in the next stage is yet to be determined. Surfactant–polymer (SP) flooding, which can reduce the oil–water interfacial tension and increase the viscosity of the water phase, has been widely applied to low-temperature and low-salinity reservoirs across China in the past few decades, but it has rarely been applied to high-temperature and high-salinity reservoirs such as the Gasi reservoir. In this study, the feasibility of SP flooding for high-temperature and high-salinity reservoirs was established. Thanks to the novel surfactant and polymer products, an SP flooding formula with surfactants ZC-2/B2 and polymer BRH-325 was proposed for Gasi. The formula showed a low interfacial tension of 10⁻² mN/m and a high viscosity of 18 MPa·s in simulated reservoir conditions. The oil displacement experiment demonstrated that this formula can enhance the oil recovery rate by 26.95% upon water flooding at 64.64%. This study provides a feasible EOR candidate technology for high-temperature and high-salinity reservoirs, as exemplified by the Qinghai Gasi reservoir. Full article