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Keywords = EOR miscible CO2

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13 pages, 1486 KiB  
Article
Evaluation of Miscible Gas Injection Strategies for Enhanced Oil Recovery in High-Salinity Reservoirs
by Mohamed Metwally and Emmanuel Gyimah
Processes 2025, 13(8), 2429; https://doi.org/10.3390/pr13082429 - 31 Jul 2025
Viewed by 229
Abstract
This study presents a comprehensive evaluation of miscible gas injection (MGI) strategies for enhanced oil recovery (EOR) in high-salinity reservoirs, with a focus on the Raleigh Oil Field. Using a calibrated Equation of State (EOS) model in CMG WinProp™, eight gas injection scenarios [...] Read more.
This study presents a comprehensive evaluation of miscible gas injection (MGI) strategies for enhanced oil recovery (EOR) in high-salinity reservoirs, with a focus on the Raleigh Oil Field. Using a calibrated Equation of State (EOS) model in CMG WinProp™, eight gas injection scenarios were simulated to assess phase behavior, miscibility, and swelling factors. The results indicate that carbon dioxide (CO2) and enriched separator gas offer the most technically and economically viable options, with CO2 demonstrating superior swelling performance and lower miscibility pressure requirements. The findings underscore the potential of CO2-EOR as a sustainable and effective recovery method in pressure-depleted, high-salinity environments. Full article
(This article belongs to the Special Issue Recent Developments in Enhanced Oil Recovery (EOR) Processes)
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15 pages, 3876 KiB  
Article
Research on the Development Mechanism of Air Thermal Miscible Flooding in the High Water Cut Stage of Medium to High Permeability Light Oil Reservoirs
by Daode Hua, Changfeng Xi, Peng Liu, Tong Liu, Fang Zhao, Yuting Wang, Hongbao Du, Heng Gu and Mimi Wu
Energies 2025, 18(11), 2783; https://doi.org/10.3390/en18112783 - 27 May 2025
Viewed by 345
Abstract
Currently, the development of oil reservoirs with high water cut faces numerous challenges, including poor economic efficiency, difficulties in residual oil recovery, and a lack of effective development technologies. In light of these issues, this paper conducts research on gas drive development during [...] Read more.
Currently, the development of oil reservoirs with high water cut faces numerous challenges, including poor economic efficiency, difficulties in residual oil recovery, and a lack of effective development technologies. In light of these issues, this paper conducts research on gas drive development during the high water cut stage in middle–high permeability reservoirs and introduces an innovative technical approach for air thermal miscible flooding. In this study, the Enhanced Oil Recovery (EOR) mechanism and the dynamic characteristics of thermal miscible flooding were investigated through laboratory experiments and numerical simulations. The N2 and CO2 flooding experiments indicate that gas channeling is likely to occur when miscible flooding cannot be achieved, due to the smaller gas–water mobility ratio compared to the gas–oil mobility ratio during the high water cut stage. Consequently, the enhanced recovery efficiency of N2 and CO2 flooding is limited. The experiment on air thermal miscible flooding demonstrates that under conditions of high water content, this method can form a stable high-temperature thermal oxidation front. The high temperature, generated by the thermal oxidation front, promotes the miscibility of flue gas and crude oil, effectively inhibiting gas flow, preventing gas channeling, and significantly enhancing oil recovery. Numerical simulations indicate that the production stage of air hot miscible flooding in reservoirs with middle–high permeability and high water cut can be divided into three phases: pressurization and drainage response, high efficiency and stable production with a low air–oil ratio, and low efficiency production with a high air–oil ratio. These phases can enable efficient development during the high water cut stage in medium to high permeability reservoirs, with the theoretical EOR range expected to exceed 30%. Full article
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23 pages, 3535 KiB  
Article
Geological–Engineering Synergistic Optimization of CO2 Flooding Well Patterns for Sweet Spot Development in Tight Oil Reservoirs
by Enhui Pei, Chao Xu and Chunsheng Wang
Sustainability 2025, 17(11), 4751; https://doi.org/10.3390/su17114751 - 22 May 2025
Cited by 1 | Viewed by 424
Abstract
CO2 flooding technology has been established as a key technique that is both economically viable and environmentally sustainable, achieving enhanced oil recovery (EOR) while advancing CCUS objectives. This study addresses the challenge of optimizing CO2 flooding well patterns in tight oil [...] Read more.
CO2 flooding technology has been established as a key technique that is both economically viable and environmentally sustainable, achieving enhanced oil recovery (EOR) while advancing CCUS objectives. This study addresses the challenge of optimizing CO2 flooding well patterns in tight oil reservoirs through a geological–engineering integrated approach. A semi-analytical model incorporating startup pressure gradients and miscible/immiscible two-phase flow was developed to dynamically adjust injection intensity. An effective driving coefficient model considering reservoir heterogeneity and fracture orientation was proposed to determine well pattern boundaries. Field data from Blocks A and B were used to validate the models, with the results indicating optimal injection intensities of 0.39 t/d/m and 0.63 t/d/m, respectively. Numerical simulations confirmed that inverted five-spot patterns with well spacings of 240 m (Block A) and 260 m (Block B) achieved the highest incremental oil production (3621.6 t/well and 4213.1 t/well) while reducing the gas channeling risk by 35–47%. The proposed methodology provides a robust framework for enhancing recovery efficiency in low-permeability reservoirs under varying geological conditions. Full article
(This article belongs to the Special Issue Sustainable Exploitation and Utilization of Hydrocarbon Resources)
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34 pages, 8695 KiB  
Article
Cost-Effective Strategies for Assessing CO2 Water-Alternating-Gas (WAG) Injection for Enhanced Oil Recovery (EOR) in a Heterogeneous Reservoir
by Abdul-Muaizz Koray, Emmanuel Appiah Kubi, Dung Bui, Jonathan Asante, Irma Primasari, Adewale Amosu, Son Nguyen, Samuel Appiah Acheampong, Anthony Hama, William Ampomah and Angus Eastwood-Anaba
Water 2025, 17(5), 651; https://doi.org/10.3390/w17050651 - 23 Feb 2025
Viewed by 1397
Abstract
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 CO [...] Read more.
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
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24 pages, 7652 KiB  
Article
Economic Optimization of Enhanced Oil Recovery and Carbon Storage Using Mixed Dimethyl Ether-Impure CO2 Solvent in a Heterogeneous Reservoir
by Kwangduk Seo, Bomi Kim, Qingquan Liu and Kun Sang Lee
Energies 2025, 18(3), 718; https://doi.org/10.3390/en18030718 - 4 Feb 2025
Viewed by 861
Abstract
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 [...] Read more.
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
(This article belongs to the Special Issue Oil Recovery and Simulation in Reservoir Engineering)
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28 pages, 11248 KiB  
Article
A Comparison of Water Flooding and CO2-EOR Strategies for the Optimization of Oil Recovery: A Case Study of a Highly Heterogeneous Sandstone Formation
by Dung Bui, Son Nguyen, William Ampomah, Samuel Appiah Acheampong, Anthony Hama, Adewale Amosu, Abdul-Muaizz Koray and Emmanuel Appiah Kubi
Gases 2025, 5(1), 1; https://doi.org/10.3390/gases5010001 - 24 Dec 2024
Cited by 2 | Viewed by 2371
Abstract
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 [...] Read more.
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
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15 pages, 3001 KiB  
Article
Carbon Dioxide Oil Repulsion in the Sandstone Reservoirs of Lunnan Oilfield, Tarim Basin
by Zangyuan Wu, Qihong Feng, Liming Lian, Xiangjuan Meng, Daiyu Zhou, Min Luo and Hanlie Cheng
Energies 2024, 17(14), 3503; https://doi.org/10.3390/en17143503 - 17 Jul 2024
Cited by 3 | Viewed by 1076
Abstract
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 [...] Read more.
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
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16 pages, 5293 KiB  
Article
A Multiphase and Multicomponent Model and Numerical Simulation Technology for CO2 Flooding and Storage
by Qiaoyun Li, Zhengfu Ning, Shuhong Wu, Baohua Wang, Qiang Li and Hua Li
Energies 2024, 17(13), 3222; https://doi.org/10.3390/en17133222 - 30 Jun 2024
Cited by 2 | Viewed by 1293
Abstract
In recent years, CO2 flooding has become an important technical measure for oil and gas field enterprises to further improve oil and gas recovery and achieve the goal of “dual carbon”. It is also one of the concrete application forms of CCUS. [...] Read more.
In recent years, CO2 flooding has become an important technical measure for oil and gas field enterprises to further improve oil and gas recovery and achieve the goal of “dual carbon”. It is also one of the concrete application forms of CCUS. Numerical simulation based on CO2-EOR plays an indispensable role in the study of the mechanism of CO2 flooding and buried percolation, allowing for technical indicators to be selected and EOR/EGR prediction to be improved for reservoir engineers. This paper discusses the numerical simulation techniques related to CO2 flooding and storage, including mathematical models and solving algorithms. A multiphase and multicomponent mathematical model is developed to describe the flow mechanism of hydrocarbon components–CO2–water underground and to simulate the phase diagram of the components. The two-phase P-T flash calculation with SSI (+DEM) and the Newton method is adopted to obtain the gas–liquid phase equilibrium parameters. The extreme value judgment of the TPD function is used to form the phase stability test and miscibility identification model. A tailor-made multistage preconditioner is built to solve the linear equation of the strong-coupled, multiphase, multicomponent reservoir simulation, which includes the variables of pressure, saturation, and composition. The multistage preconditioner improves the computational efficiency significantly. A numerical simulation of CO2 injection in a carbonate reservoir in the Middle East shows that it is effective for researching the recovery factor and storage quantity of CO2 flooding based on the above numerical simulation techniques. Full article
(This article belongs to the Section D: Energy Storage and Application)
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19 pages, 21778 KiB  
Article
Reservoir Simulations of Hydrogen Generation from Natural Gas with CO2 EOR: A Case Study
by Krzysztof Miłek, Wiesław Szott, Jarosław Tyburcy and Alicja Lew
Energies 2024, 17(10), 2321; https://doi.org/10.3390/en17102321 - 11 May 2024
Cited by 2 | Viewed by 1249
Abstract
This paper addresses the problem of hydrogen generation from hydrocarbon gases using Steam Methane Reforming (SMR) with byproduct CO2 injected into and stored in a partially depleted oil reservoir. It focuses on the reservoir aspects of the problem using numerical simulation of [...] Read more.
This paper addresses the problem of hydrogen generation from hydrocarbon gases using Steam Methane Reforming (SMR) with byproduct CO2 injected into and stored in a partially depleted oil reservoir. It focuses on the reservoir aspects of the problem using numerical simulation of the processes. To this aim, a numerical model of a real oil reservoir was constructed and calibrated based on its 30-year production history. An algorithm was developed to quantify the CO2 amount from the SMR process as well as from the produced fluids, and optionally, from external sources. Multiple simulation forecasts were performed for oil and gas production from the reservoir, hydrogen generation, and concomitant injection of the byproduct CO2 back to the same reservoir. EOR from miscible oil displacement was found to occur in the reservoir. Various scenarios of the forecasts confirmed the effectiveness of the adopted strategy for the same source of hydrocarbons and CO2 sink. Detailed simulation results are discussed, and both the advantages and drawbacks of the proposed approach for blue hydrogen generation are concluded. In particular, the question of reservoir fluid balance was emphasized, and its consequences were presented. The presented technology, using CO2 from hydrogen production and other sources to increase oil production, also has a significant impact on the protection of the natural environment via the elimination of CO2 emission to the atmosphere with concomitant production of H2. Full article
(This article belongs to the Section A5: Hydrogen Energy)
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27 pages, 2009 KiB  
Review
A Comprehensive Summary of the Application of Machine Learning Techniques for CO2-Enhanced Oil Recovery Projects
by Xuejia Du, Sameer Salasakar and Ganesh Thakur
Mach. Learn. Knowl. Extr. 2024, 6(2), 917-943; https://doi.org/10.3390/make6020043 - 29 Apr 2024
Cited by 11 | Viewed by 4637
Abstract
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 [...] Read more.
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
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23 pages, 1874 KiB  
Article
Research and Application of Carbon Capture, Utilization, and Storage–Enhanced Oil Recovery Reservoir Screening Criteria and Method for Continental Reservoirs in China
by Jinhong Cao, Ming Gao, Zhaoxia Liu, Hongwei Yu, Wanlu Liu and Hengfei Yin
Energies 2024, 17(5), 1143; https://doi.org/10.3390/en17051143 - 28 Feb 2024
Cited by 5 | Viewed by 1691
Abstract
CCUS-EOR is a crucial technology for reducing carbon emissions and enhancing reservoir recovery. It enables the achievement of dual objectives: improving economic efficiency and protecting the environment. To explore a set of CCUS-EOR reservoir screening criteria suitable for continental reservoirs in China, this [...] Read more.
CCUS-EOR is a crucial technology for reducing carbon emissions and enhancing reservoir recovery. It enables the achievement of dual objectives: improving economic efficiency and protecting the environment. To explore a set of CCUS-EOR reservoir screening criteria suitable for continental reservoirs in China, this study investigated and compared the CCUS-EOR reservoir screening criteria outside and in China, sorted out the main reservoir parameters that affect CO2 flooding, and optimized the indices and scope of CCUS-EOR reservoir screening criteria in China. The weights of parameters with respect to their influences on CCUS-EOR were determined through principal component analysis. The results show that there are 14 key parameters affecting CO2 flooding, which can be categorized into four levels. For the first level, the crude oil-CO2 miscibility index holds the greatest weight of 0.479. It encompasses seven parameters: initial formation pressure, current formation pressure, temperature, depth, C2–C15 molar content, residual oil saturation, and minimum miscibility pressure. The second level consists of the crude oil mobility index, which has a weight of 0.249. This index includes four parameters: porosity, permeability, density, and viscosity. The third level pertains to the index of reservoir tectonic characteristics, with a weight of 0.141. It comprises two parameters: permeability variation coefficient and average effective thickness. Lastly, the fourth level focuses on the index of reservoir property change, with a weight of 0.131, which solely considers the pressure maintenance level. Based on the CCUS-EOR reservoir screening criteria and index weights established in this study, comprehensive scores for CCUS-EOR were calculated for six blocks in China. Among these, five blocks are deemed suitable for CCUS-EOR. Based on the comprehensive scoring results, a planning for field application of CCUS-EOR is proposed. The study provides a rational method to evaluate the CCUS-EOR reservoir screening and field application in continental reservoirs in China. Full article
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23 pages, 12560 KiB  
Article
Feasibility of Advanced CO2 Injection and Well Pattern Adjustment to Improve Oil Recovery and CO2 Storage in Tight-Oil Reservoirs
by Lijun Zhang, Tianwei Sun, Xiaobing Han, Jianchao Shi, Jiusong Zhang, Huiting Tang and Haiyang Yu
Processes 2023, 11(11), 3104; https://doi.org/10.3390/pr11113104 - 29 Oct 2023
Cited by 8 | Viewed by 2895
Abstract
Global tight-oil reserves are abundant, but the depletion development of numerous tight-oil reservoirs remains unsatisfactory. CO2 injection development represents a significant method of reservoir production, potentially facilitating enhanced oil recovery (EOR) alongside CO2 storage. Currently, limited research exists on advanced CO [...] Read more.
Global tight-oil reserves are abundant, but the depletion development of numerous tight-oil reservoirs remains unsatisfactory. CO2 injection development represents a significant method of reservoir production, potentially facilitating enhanced oil recovery (EOR) alongside CO2 storage. Currently, limited research exists on advanced CO2 injection and well pattern adjustment aimed at improving the oil recovery and CO2 storage within tight-oil reservoirs. This paper focuses on the examination of tight oil within the Ordos Basin. Through the employment of slim-tube experiments, long-core displacement experiments, and reservoir numerical simulations, the near-miscible pressure range and minimum miscible pressure (MMP) for the target block were ascertained. The viability of EOR and CO2 sequestration via advanced CO2 injection was elucidated, establishing well pattern adjustment methodologies to ameliorate CO2 storage and enhance oil recovery. Simultaneously, the impacts of the injection volume and bottom-hole pressure on the development of advanced CO2 injection were explored in further detail. The experimental results indicate that the near-miscible pressure range of the CO2–crude oil in the study area is from 15.33 to 18.47 MPa, with an MMP of 18.47 MPa, achievable under reservoir pressure conditions. Compared to continuous CO2 injection, advanced CO2 injection can more effectively facilitate EOR and achieve CO2 sequestration, with the recovery and CO2 sequestration rates increasing by 4.83% and 2.29%, respectively. Through numerical simulation, the optimal injection volume for advanced CO2 injection was determined to be 0.04 PV, and the most favorable bottom-hole flowing pressure was identified as 10 MPa. By transitioning from a square well pattern to either a five-point well pattern or a row well pattern, the CO2 storage ratio significantly improved, and the gas–oil ratio of the production wells also decreased. Well pattern adjustment effectively supplements the formation energy, extends the stable production lives of production wells, and increases both the sweep efficiency and oil recovery. This study provides theoretical support and serves as a reference for CO2 injection development in tight-oil reservoirs. Full article
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14 pages, 5555 KiB  
Article
Study of Supercritical State Characteristics of Miscible CO2 Used in the Flooding Process
by Yu Zhang, Weifeng Lyu, Ke Zhang, Dongbo He, Ao Li, Yaoze Cheng and Jiahao Gao
Energies 2023, 16(18), 6693; https://doi.org/10.3390/en16186693 - 18 Sep 2023
Cited by 7 | Viewed by 1846
Abstract
Carbon dioxide flooding is a strategic replacement technology for greatly enhancing oil recovery in low-permeability oilfields, which includes social benefits resulting from carbon emission reduction and economic benefits owing to the improvement of oil recovery. Therefore, it is of great significance to develop [...] Read more.
Carbon dioxide flooding is a strategic replacement technology for greatly enhancing oil recovery in low-permeability oilfields, which includes social benefits resulting from carbon emission reduction and economic benefits owing to the improvement of oil recovery. Therefore, it is of great significance to develop and apply the technology of CO2 flooding and storage in the petroleum industry. In reservoir conditions, CO2 is usually under a supercritical state, presenting both low viscosity and high diffusivity of a gaseous state and high density of a liquid state. The special phase behavior of CO2 directly affects its extraction capacity, resulting in the change of miscible behavior between CO2 and crude oil. In this paper, the ultra-high-pressure–high-temperature pressure–volume–temperature (PVT) system was used to evaluate the phase characteristics of CO2 during the process of reservoir development. The phase behaviors of the CO2/CH4/N2 crude oil system were compared and analyzed. Moreover, the matching mechanism between supercritical CO2 characteristics and oil–gas system miscibility was investigated and defined. This work deepened the understanding of the phase characteristics of CO2 in the process of miscible flooding, providing both theoretical guidance for the application of CO2 injection on oilfields and the essential scientific basis for the implementation of CCUS-EOR technology. Full article
(This article belongs to the Section H: Geo-Energy)
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28 pages, 6761 KiB  
Article
Prediction of Key Parameters in the Design of CO2 Miscible Injection via the Application of Machine Learning Algorithms
by Mohamed Hamadi, Tayeb El Mehadji, Aimen Laalam, Noureddine Zeraibi, Olusegun Stanley Tomomewo, Habib Ouadi and Abdesselem Dehdouh
Eng 2023, 4(3), 1905-1932; https://doi.org/10.3390/eng4030108 - 7 Jul 2023
Cited by 19 | Viewed by 3826
Abstract
The accurate determination of key parameters, including the CO2-hydrocarbon solubility ratio (Rs), interfacial tension (IFT), and minimum miscibility pressure (MMP), is vital for the success of CO2-enhanced oil recovery (CO2-EOR) projects. This study presents a robust machine [...] Read more.
The accurate determination of key parameters, including the CO2-hydrocarbon solubility ratio (Rs), interfacial tension (IFT), and minimum miscibility pressure (MMP), is vital for the success of CO2-enhanced oil recovery (CO2-EOR) projects. This study presents a robust machine learning framework that leverages deep neural networks (MLP-Adam), support vector regression (SVR-RBF) and extreme gradient boosting (XGBoost) algorithms to obtained accurate predictions of these critical parameters. The models are developed and validated using a comprehensive database compiled from previously published studies. Additionally, an in-depth analysis of various factors influencing the Rs, IFT, and MMP is conducted to enhance our understanding of their impacts. Compared to existing correlations and alternative machine learning models, our proposed framework not only exhibits lower calculation errors but also provides enhanced insights into the relationships among the influencing factors. The performance evaluation of the models using statistical indicators revealed impressive coefficients of determination of unseen data (0.9807 for dead oil solubility, 0.9835 for live oil solubility, 0.9931 for CO2-n-Alkane interfacial tension, and 0.9648 for minimum miscibility pressure). One notable advantage of our models is their ability to predict values while accommodating a wide range of inputs swiftly and accurately beyond the limitations of common correlations. The dataset employed in our study encompasses diverse data, spanning from heptane (C7) to eicosane (C20) in the IFT dataset, and MMP values ranging from 870 psi to 5500 psi, covering the entire application range of CO2-EOR. This innovative and robust approach presents a powerful tool for predicting crucial parameters in CO2-EOR projects, delivering superior accuracy, speed, and data diversity compared to those of the existing methods. Full article
(This article belongs to the Special Issue GeoEnergy Science and Engineering)
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40 pages, 12055 KiB  
Article
Applying Reservoir Simulation and Artificial Intelligence Algorithms to Optimize Fracture Characterization and CO2 Enhanced Oil Recovery in Unconventional Reservoirs: A Case Study in the Wolfcamp Formation
by Xincheng Wan, Lu Jin, Nicholas A. Azzolina, Shane K. Butler, Xue Yu and Jin Zhao
Energies 2022, 15(21), 8266; https://doi.org/10.3390/en15218266 - 4 Nov 2022
Cited by 9 | Viewed by 3196
Abstract
Reservoir simulation for unconventional reservoirs requires proper history matching (HM) to quantify the uncertainties of fracture properties and proper modeling methods to address complex fracture geometry. An integrated method, namely embedded discrete fracture model–artificial intelligence–automatic HM (EDFM–AI–AHM), was used to automatically generate HM [...] Read more.
Reservoir simulation for unconventional reservoirs requires proper history matching (HM) to quantify the uncertainties of fracture properties and proper modeling methods to address complex fracture geometry. An integrated method, namely embedded discrete fracture model–artificial intelligence–automatic HM (EDFM–AI–AHM), was used to automatically generate HM solutions for a multistage hydraulic fracturing well in the Wolfcamp Formation. Thirteen scenarios with different combinations of matrix and fracture parameters as variables or fixed inputs were designed to generate 1300 reservoir simulations via EDFM–AI–AHM, from which 358 HM solutions were retained to reproduce production history and quantify the uncertainties of matrix and hydraulic fracture properties. The best HM solution was used for production forecasting and carbon dioxide (CO2)-enhanced oil recovery (EOR) strategy optimization. The results of the production forecast for primary recovery indicated that the drainage area for oil production was difficult to extend further into the low-permeability reservoir matrix. However, CO2 EOR simulations showed that increasing the gas injection rate during the injection cycle promoted incremental oil production from the reservoir matrix, regardless of minimum miscibility pressure. A gas injection rate of 25 million standard cubic feet per day (MMscfd) resulted in a 14% incremental oil production improvement compared to the baseline scenario with no EOR. This paper demonstrates the utility of coupling reservoir simulation with artificial intelligence algorithms to generate ensembles of simulation cases that provide insights into the relationships between fracture network properties and production. Full article
(This article belongs to the Special Issue CO2 Injection and Storage in Reservoir)
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