Search Results (45)

At present, various advanced technologies for field development based on gas-enhanced oil recovery (EOR) methods are widely applied worldwide. These include high-pressure gas injection (hydrocarbon gases, nitrogen, flue gases), water-alternating-gas (WAG) injection, and carbon dioxide (CO₂) flooding. This study presents the results of filtration experiments investigating the application of gas EOR methods using core samples from a heavy oil reservoir. The primary objective of these experiments was to determine the oil displacement factor and analyze changes in interfacial tension upon injection of different gas agents. The following gases were utilized for modeling gas EOR processes: nitrogen (N₂), carbon dioxide (CO₂), and hydrocarbon gases (methane, propane). The core samples used in the study were obtained from the East Moldabek heavy oil field in Kazakhstan. Based on the results of the filtration experiments, carbon dioxide (CO₂) injection was identified as the most effective gas EOR method in terms of increasing the oil displacement factor, achieving an incremental displacement factor of 5.06%. Other gas injection methods demonstrated lower efficiency. Full article

Oil production will remain essential in the coming decades, requiring environmental responsibilities that are aligned with Agenda 2030. Enhanced oil recovery (EOR) increases recovery efficiency with low investment, but environmental protection technologies (EOR and Env), including green EOR (GEOR) and waste treatment (WT), must be integrated. The BRICS association, representing half of global oil production, promotes technology transfer in this context. Worldwide patent data (2004–2023) of EOR and Env technologies at TRL 4–5 in BRICS and non-BRICS countries were compared for nine GEOR (1489 patents) and nine WT (2292 patents) methods. China is the global leader (73%, being 98% of BRICS patents), maintaining dominance even when normalized by GDP. Non-BRICS patents are from the USA (41%), Japan (31%), and the Republic of Korea (14%). BRICS countries surpassed non-BRICS in 2014, with a 5.9% growth rate, −13.2% for non-BRICS, with all methods growing, whereas in non-BRICS, only water flocculation treatment is growing. BRICS technological specialization is expanding more rapidly than that of non-BRICS countries. BRICS countries exhibit higher relative technological advantages and distance in surfactants, polymers, macromolecules, sludge treatment, and multistage water treatment devices. Non-BRICS countries are more competitive in in situ combustion, water alternating gas (WAG), re-pressurization, vacuum techniques, flotation, water–oil separation, sorption, or precipitation, flocculation, and oil-contaminated water. China is the primary BRICS leader and is positioned to define BRICS policies regarding technology transfer and innovation. Technological partnerships between BRICS and non-BRICS countries are strongly recommended to enhance synergy and achieve sustainable and efficient production more rapidly. Full article

This study investigates the combined effects of impurities in CO₂ stream, geochemistry, water salinity, and wettability alteration on oil recovery and CO₂ storage in carbonate reservoirs and optimizes injection strategy to maximize oil recovery and CO₂ storage ratio. Specifically, it compares the performance of pure CO₂ water-alternating gas (WAG), impure CO₂-WAG, pure CO₂ low-salinity water-alternating gas (LSWAG), and impure CO₂-LSWAG injection methods from perspectives of enhanced oil recovery (EOR) and CO₂ sequestration. CO₂-enhanced oil recovery (CO₂-EOR) is an effective way to extract residual oil. CO₂ injection and WAG methods can improve displacement efficiency and sweep efficiency. However, CO₂-EOR has less impact on the carbonate reservoir because of the complex pore structure and oil-wet surface. Low-salinity water injection (LSWI) and CO₂ injection can affect the complex pore structure by geochemical reaction and wettability by a relative permeability curve shift from oil-wet to water-wet. The results from extensive compositional simulations show that CO₂ injection into carbonate reservoirs increases the recovery factor compared with waterflooding, with pure CO₂-WAG injection yielding higher recovery factor than impure CO₂-WAG injection. Impurities in CO₂ gas decrease the efficiency of CO₂-EOR, reducing oil viscosity less and increasing interfacial tension (IFT) compared to pure CO₂ injection, leading to gas channeling and reduced sweep efficiency. This results in lower oil recovery and lower storage efficiency compared to pure CO₂. CO₂-LSWAG results in the highest oil-recovery factor as surface changes. Geochemical reactions during CO₂ injection also increase CO₂ storage capacity and alter trapping mechanisms. This study demonstrates that the use of impure CO₂-LSWAG injection leads to improved oil recovery and CO₂ storage compared to pure CO₂-WAG injection. It reveals that wettability alteration plays a more significant role for oil recovery and geochemical reaction plays crucial role in CO₂ storage than CO₂ purity. According to optimization, the greater the injection of gas and water, the higher the oil recovery, while the less gas and water injected, the higher the storage ratio, leading to improved storage efficiency. This research provides valuable insights into parameters and injection scenarios affecting enhanced oil recovery and CO₂ storage in carbonate reservoirs. Full article

This study evaluates the feasibility of CO₂ Water-Alternating-Gas (WAG) injection for enhanced oil recovery (EOR) in a highly heterogeneous reservoir using cost-effective and efficient tools. The Rule of Thumb method was initially used to screen the reservoir, confirming its suitability for CO₂-WAG injection. A fluid model was constructed by comparing several component lumping methods, selecting the approach with the least deviation from experimental data to ensure accuracy. The minimum miscibility pressure (MMP), a critical parameter for CO₂-EOR, was estimated using three methodologies: 1D simulation based on the slim tube test, semi-empirical analytical correlations, and fluid modeling. These techniques provided complementary insights into the reservoir’s miscibility conditions. The CO₂ Prophet software version 1 was employed to history-match production data and evaluate different development strategies. The Kinder Morgan CO₂ Scoping Model was used to perform production forecasting and assess the economic viability of implementing CO₂-WAG. Quantitative comparisons showed that the CO₂ Prophet version 1 model revealed minimal deviations from the history match results: oil production estimates differed by only 3.5%, and water production estimates differed by −4.11%. Cumulative oil recovery was projected to reach approximately 20.26 MMSTB over a 25-year production period. The results indicate that CO₂-WAG injection could enhance oil recovery significantly compared to water flooding while maintaining economic feasibility. This study demonstrates the practical integration of analytical tools and inexpensive models to evaluate and optimize CO₂-EOR strategies in complex reservoirs. The findings provide a systematic workflow for deploying CO₂-WAG in heterogeneous reservoirs, balancing technical and economic considerations. Full article

CO₂ is the main solvent used in enhanced oil recovery (EOR). However, its low density and viscosity compared to oil cause a decrease in sweep efficiency. Recently, dimethyl ether (DME), which is more efficient than CO₂, has been introduced into the process. DME improves oil recovery by reducing minimum miscible pressure (MMP), interfacial tension (IFT), and oil viscosity. Since DME is an expensive solvent, price reduction and appropriate injection scenarios are needed for economic feasibility. In this study, a compositional model was developed to inject DME with impure CO₂ streams, where the CO₂ was derived from one of these three purification methods: dehydration, double flash, and distillation. It was assumed that such a mixed solvent was injected into a heterogeneous reservoir where gravity override was maximized. As a result, lower oil recovery is achieved for the higher impurity content of the CO₂ stream, lower DME content, and more heterogeneous reservoir. When a high-purity CO₂ stream is used, the change in oil recovery according to DME content and heterogeneity of the reservoir is increased. When the lowest-purity CO₂ stream is used, the net present value (NPV) is the highest. For a homogeneous reservoir, the NPV is highest for all impure CO₂ streams. This optimization indicates a greater impact on revenue from reduced CO₂ purchase cost than on profit loss due to reduced oil recovery by impurities. Additional benefits can be expected when considering solvent reuse and carbon capture and storage (CCS) credits. Full article

The exploitation of Block L within the Tarim Basin oilfield commenced in 1989 and it has transitioned from the natural energy development stage to the current water injection development stage. Despite this, the efficacy of water flooding remains suboptimal, with the low degree of control, uneven utilization of reserves, and subpar mining outcomes. The block still contains substantial remaining oil resources, necessitating continued extraction. Notably, the primary oil produced in this block is condensate oil, which commands a high economic value. To enhance the oil recovery efficiency of the block reservoir, a development plan employing alternating and water-natural gas flooding has been proposed. The objective of this study is to evaluate the feasibility of the proposed alternating displacement scheme involving natural gas and water in this reservoir. The specific steps include PVT fitting, historical matching, residual oil evaluation, and the optimization of gas injection parameters. Results show that for this reservoir the water-natural gas flooding (WAG) is the optimal option. And this article has the application of WAG flooding simulation, simulating 15 years of operation. Compared with the original development scheme of the original well pattern, the recovery of this reservoir is increased by 12.05%, which provided a reference basis for the on-site application of WAG in this reservoir. Full article

This study presents a comparative analysis of CO₂-EOR and water flooding scenarios to optimize oil recovery in a geologically heterogeneous reservoir with a dome structure and partial aquifer support. Using production data from twelve production and three monitoring wells, a dynamic reservoir model was built and successfully history-matched with a 1% deviation from actual field data. Three main recovery methods were evaluated: water flooding, continuous CO₂ injection, and water-alternating-gas (WAG) injection. Water flooding resulted in a four-fold increase from primary recovery, while continuous CO₂ injection provided up to 40% additional oil recovery compared to water flooding. WAG injection further increased recovery by 20% following water flooding. The minimum miscibility pressure (MMP) was determined using a 1D slim-tube simulation to ensure effective CO₂ performance. A sensitivity analysis on CO₂/WAG ratios (1:1, 2:1, 3:1) revealed that continuous CO₂ injection, particularly in high permeability zones, offered the most efficient recovery. An economic evaluation indicated that the optimal development strategy is 15 years of water flooding followed by 15 years of continuous CO₂ injection, resulting in a net present value (NPV) of USD 1 billion. This study highlights the benefits of CO₂-EOR for maximizing oil recovery and suggests further work on hybrid EOR techniques and carbon sequestration in depleted reservoirs. Full article

A recrosslinkable CO₂-resistant branched preformed particle gel (CO₂-BRPPG) was developed for controlling CO₂ injection conformance, particularly in reservoirs with super-permeable channels. Previous work focused on a millimeter-sized CO₂-BRPPG in open fractures, but its performance in high-permeability channels with pore throat networks remained unexplored. This study used a sandpack model to evaluate a micro-sized CO₂-BRPPG under varying conditions of salinity, gel concentration, and pH. At ambient conditions, the equilibrium swelling ratio (ESR) of the gel reached 76 times its original size. This ratio decreased with increasing salinity but remained stable at low pH values, demonstrating the gel’s resilience in acidic environments. Rheological tests revealed shear-thinning behavior, with gel strength improving as salinity increased (the storage modulus rose from 113 Pa in 1% NaCl to 145 Pa in 10% NaCl). Injectivity tests showed that lower gel concentrations reduced the injection pressure, offering flexibility in deep injection treatments. Gels with higher swelling ratios had lower injection pressures due to increased strength and reduced deformability. The gel maintained stable plugging performance during two water-alternating-CO₂ cycles, but a decline was observed in the third cycle. It also demonstrated a high CO₂ breakthrough pressure of 177 psi in high salinity conditions (10% NaCl). The permeability reduction for water and CO₂ was influenced by gel concentration and salinity, with higher salinity increasing the permeability reduction and higher gel concentrations decreasing it. These findings underscore the effectiveness of the CO₂-BRPPG in improving CO₂ sweep efficiency and managing CO₂ sequestration in reservoirs with high permeability. Full article

In carbonate reservoirs, nanoparticles can adhere to rock surfaces, potentially altering the rock wettability and modifying the absolute permeability. In the water-alternating-gas (WAG) process, the introduction of nanoparticles into the water phase, termed nano-water-alternating gas (NWAG), is a promising approach for enhancing oil recovery and CO₂ storage. The NWAG process can alter rock wettability and absolute permeability through the adsorption of nanoparticles on the rock surface. This study investigated the efficiency of the NWAG method, which utilizes nanofluids in CO₂-enhanced oil recovery (EOR) processes to simultaneously recover oil and store CO₂ using 1D core and 3D heterogeneous reservoir models. The simulation results of the 1D core model showed that applying the NWAG method enhanced both oil recovery and CO₂ storage efficiency by increasing to 3%. In a 3D reservoir model, a Dykstra–Parsons coefficient of 0.4 was selected to represent reservoir heterogeneity. Additionally, the capillary trapping of CO₂ during WAG injection was computed using Larsen and Skauge’s three-phase relative permeability hysteresis model. A sensitivity analysis was performed using the NWAG ratio, slug size, injection period, injection cycle, and nanofluid concentration. The results confirmed an increase of 0.8% in oil recovery and 15.2% in CO₂ storage compared with the conventional WAG process. This mechanism suggests that nanofluids can enhance oil recovery and expand CO₂ storage, improving the efficiency of both the oil production rate and CO₂ storage compared to conventional WAG methods. Full article

CO₂-enhanced oil recovery (CO₂-EOR) is a crucial method for CO₂ utilization and sequestration, representing an important zero-carbon or even negative-carbon emission reduction technology. However, the low viscosity of CO₂ and reservoir heterogeneity often result in early gas breakthrough, significantly reducing CO₂ utilization and sequestration efficiency. A water-alternating-gas (WAG) injection is a technique for mitigating gas breakthrough and viscous fingering in CO₂-EOR. However, it encounters challenges related to insufficient mobility control in highly heterogeneous and fractured reservoirs, resulting in gas channeling and low sweep efficiency. Despite the extensive application and research of a WAG injection in oil and gas reservoirs, the most recent comprehensive review dates back to 2018, which focuses on the mechanisms of EOR using conventional WAG. Herein, we give an updated and comprehensive review to incorporate the latest advancements in CO₂-WAG flooding techniques for enhanced sweep efficiency, which includes the theory, applications, fluid displacement mechanisms, and control strategies of a CO₂-WAG injection. It addresses common challenges, operational issues, and remedial measures in WAG projects by covering studies from experiments, simulations, and pore-scale modeling. This review aims to provide guidance and serve as a reference for the application and research advancement of CO₂-EOR techniques in heterogeneous and fractured reservoirs. Full article

This paper presents a comprehensive analysis of water injection management practices for complex and impactful onshore and offshore carbonate reservoirs. It delves into the fundamental aspects of waterflooding design, surveillance techniques, and monitoring methods tailored for the unique challenges posed by carbonate formations. Two case studies from the Permian Basin in Texas and two from Lula Field offshore Brazil and Agbami Field offshore Nigeria are examined considering scientific principles into practice to provide insights into best practices, lessons learned, and strategies to maximize the benefits derived from real noteworthy waterflood operations. The paper underscores the significance of rigorous reservoir characterization, including understanding reservoir architecture, heterogeneities, fracture networks, fluid communication pathways, and rock–fluid interactions. It emphasizes the crucial role of integrated multidisciplinary teams involving geologists, reservoir engineers, production engineers, and field operators in ensuring successful waterflood design, implementation, and optimization. Through the case studies, the paper highlights the importance of designing pattern configurations, well placements, and injection/production strategies to the specific reservoir characteristics, continually optimizing these elements based on surveillance data. It also stresses the necessity of comprehensive data acquisition, advanced analytics, numerical simulations, and frequent model updates for effective reservoir management and decision-making. The paper is impactful in terms of the lessons learned from the actual case studies, and how can these be implemented in actual field projects. Different case studies documented in the paper provide the challenges facing them and how different authors have addressed their problems in unique ways. The paper distills the information and important findings from a variety of case studies and provides succinct information that is of immense value as a reference. Important findings of these case studies are connected using creativity and are innovative as they introduce unique techniques and establish successful ideas to create new value in terms of maximizing oil recovery. Most importantly, this paper explores the application of innovative technologies, such as intelligent completions, 4D seismic monitoring, and water–alternating gas (WAG) injection, which can significantly improve waterflood performance in complex carbonate reservoirs. In summary, the paper provides a thorough understanding of the factors contributing to the success and failure of waterfloods in carbonate reservoirs through case studies based on factually and technically sound operations. It documents guidelines for optimizing waterflood performance and reducing or eliminating the potential for failures, reinforcing positive results in these challenging yet invaluable hydrocarbon resources. Full article

The Lunnan oilfield, nestled within the Tarim Basin, represents a prototypical extra-low-permeability sandstone reservoir, distinguished by high-quality crude oil characterised by a low viscosity, density, and gel content. The effective exploitation of such reservoirs hinges on the implementation of carbon dioxide (CO₂) flooding techniques. This study, focusing on the sandstone reservoirs of Lunnan, delves into the mechanisms of CO₂-assisted oil displacement under diverse operational parameters: injection pressures, CO₂ concentration levels, and variations in crude oil properties. It integrates analyses on the high-pressure, high-temperature behaviour of CO₂, the dynamics of CO₂ injection and expansion, prolonged core flood characteristics, and the governing principles of minimum miscible pressure transitions. The findings reveal a nuanced interplay between variables: CO₂’s density and viscosity initially surge with escalating injection pressures before stabilising, whereas they experience a gradual decline with increasing temperature. Enhanced CO₂ injection correlates with a heightened expansion coefficient, yet the density increment of degassed crude oil remains marginal. Notably, CO₂ viscosity undergoes a substantial reduction under stratigraphic pressures. The sequential application of water alternating gas (WAG) followed by continuous CO₂ flooding attains oil recovery efficiency surpassing 90%, emphasising the superiority of uninterrupted CO₂ injection over processes lacking profiling. The presence of non-miscible hydrocarbon gases in segmented plug drives impedes the oil displacement efficiency, underscoring the importance of CO₂ purity in the displacement medium. Furthermore, a marked trend emerges in crude oil recovery rates as the replacement pressure escalates, exhibiting an initial rapid enhancement succeeded by a gradual rise. Collectively, these insights offer a robust theoretical foundation endorsing the deployment of CO₂ flooding strategies for enhancing oil recovery from sandstone reservoirs, thereby contributing valuable data to the advancement of enhanced oil recovery (EOR) technologies in challenging, low-permeability environments. Full article

The evaluation of water-alternating-gas (WAG) efficiency and profitability is complicated by a large number of reservoir, operating, and economic parameters and constraints. This study aims at understanding the influence of the oil composition on different WAG injections. By employing compositional reservoir modeling and the Monte Carlo method to characterize the diversity of oils occurring in nature, we simulate the microscopic displacement efficiency of CO₂ flooding when it is applied to both light- and heavy-oil reservoirs. We find that the economic performance of WAG in both miscible and immiscible scenarios is mainly characterized by the dimensionless injection rate and the oil density at surface conditions. Neither the bubble point pressure nor the minimum miscibility pressure can be used for the quantification of the optimal WAG parameters. We present our estimates of the best strategies for the miscible and immiscible injections and verify some of our previous results for randomly sampled oils. In particular, we demonstrate that CO₂ flooding is better to apply at higher-dimensionless injection rates. We show that the injection of CO₂ organized at a light-oil reservoir results in a higher profitability of WAG, although this comes at the cost of lower carbon storage efficiency. Full article

For over four decades, carbon dioxide (CO₂) has been instrumental in enhancing oil extraction through advanced recovery techniques. One such method, water alternating gas (WAG) injection, while effective, grapples with limitations like gas channeling and gravity segregation. To tackle the aforementioned issues, this paper proposes an upgrade coupling method named alkaline-surfactant-polymer alternating gas (ASPAG). ASP flooding and CO₂ are injected alternately into the reservoir to enhance the recovery of the WAG process. The uniqueness of this method lies in the fact that polymers could help profile modification, CO₂ would miscible mix with oil, and alkaline surfactant would reduce oil–water interfacial tension (IFT). To analyze the feasibility of ASPAG, a couples model considering both gas flooding and ASP flooding processes is established by using the CMG-STARS (Version 2021) to study the performance of ASPAG and compare the recovery among ASPAG, WAG, and ASP flooding. Our research delved into the ASPAG’s adaptability across reservoirs varying in average permeability, interlayer heterogeneity, formation rhythmicity, and fluid properties. Key findings include that ASPAG surpasses the conventional WAG in sweep and displacement efficiency, elevating oil recovery by 12–17%, and in comparison to ASP, ASPAG bolsters displacement efficiency, leading to a 9–11% increase in oil recovery. The primary flooding mechanism of ASPAG stems from the ASP slug’s ability to diminish the interfacial tension, enhancing the oil and water mobility ratio, which is particularly efficient in medium-high permeability layers. Through sensitivity analysis, ASPAG is best suited for mid-high-permeability reservoirs characterized by low crude oil viscosity and a composite reverse sedimentary rhythm. This study offers invaluable insights into the underlying mechanisms and critical parameters that influence the alkaline-surfactant-polymer alternating gas method’s success for enhanced oil recovery. Furthermore, it unveils an innovative strategy to boost oil recovery in medium-to-high-permeability reservoirs. Full article

This paper focuses on the current application of machine learning (ML) in enhanced oil recovery (EOR) through CO₂ injection, which exhibits promising economic and environmental benefits for climate-change mitigation strategies. Our comprehensive review explores the diverse use cases of ML techniques in CO₂-EOR, including aspects such as minimum miscible pressure (MMP) prediction, well location optimization, oil production and recovery factor prediction, multi-objective optimization, Pressure–Volume–Temperature (PVT) property estimation, Water Alternating Gas (WAG) analysis, and CO₂-foam EOR, from 101 reviewed papers. We catalog relative information, including the input parameters, objectives, data sources, train/test/validate information, results, evaluation, and rating score for each area based on criteria such as data quality, ML-building process, and the analysis of results. We also briefly summarized the benefits and limitations of ML methods in petroleum industry applications. Our detailed and extensive study could serve as an invaluable reference for employing ML techniques in the petroleum industry. Based on the review, we found that ML techniques offer great potential in solving problems in the majority of CO₂-EOR areas involving prediction and regression. With the generation of massive amounts of data in the everyday oil and gas industry, machine learning techniques can provide efficient and reliable preliminary results for the industry. Full article