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School of Engineering, King's College, University of Aberdeen, Aberdeen AB24 3UE, UK
Department of Civil & Environmental Engineering, University of Alberta, Edmonton, AB, Canada
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Enhanced Oil Recovery Technologies, 3rd Edition

Abstract submission deadline
closed (31 December 2024)
Manuscript submission deadline
closed (31 March 2025)
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Topic Information

Dear Colleagues,

This Topic is a continuation of the previous successful Topic “Enhanced Oil Recovery Technologies, 2nd Volume” at https://www.mdpi.com/topics/EOR. For many years, there has been a clear trend of increasing energy demand. Despite the energy transition, oil and natural gas will remain the main energy sources for the next several dozen years. As the reservoir is depleted during primary recovery, oil recovery becomes increasingly difficult, even though the deposits are not yet completely recovered. Therefore, it is essential to develop innovative methods to increase oil recovery from known reservoirs. Enhanced oil recovery (EOR) has been considered the most promising technology to increase the recovery factor. This Topic has been proposed to international journals to further disseminate the results of basic research, laboratory investigations and field testing or implementation on the following topics:

  • Studies of fluids and interfaces in porous media;
  • Complex interfacial rheology and multiphase flow;
  • Fundamental research on surfactants and polymers;
  • Development of techniques for gas flooding (CO2, N2, foam, etc.);
  • Thermal recovery;
  • Emerging technologies, including smart water and microbial EOR;
  • Hybrid technology;
  • Related technologies, including carbon capture and sequestration (CCS);
  • Artificial intelligence/machine learning/deep learning applications in EOR techniques.

Dr. Jan Vinogradov
Dr. Ali Habibi
Topic Editors

Keywords

  • interfacial behavior
  • multiphase flow
  • wettability alteration
  • oil recovery factor
  • machine learning
  • unconventional resources

Participating Journals

Journal Name Impact Factor CiteScore Launched Year First Decision (median) APC
Applied Sciences
applsci 		2.5 5.3 2011 18.4 Days CHF 2400
Energies
energies 		3.0 6.2 2008 16.8 Days CHF 2600
Geosciences
geosciences 		2.4 5.3 2011 23.5 Days CHF 1800
Polymers
polymers 		4.7 8.0 2009 14.5 Days CHF 2700
Processes
processes 		2.8 5.1 2013 14.9 Days CHF 2400

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Published Papers (18 papers)

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29 pages, 8907 KiB  
Article
Research on Interpretation Method of Oil–Water Two-Phase Production Profile Using Artificial Intelligence Algorithm
by Tao Zheng, Hongwei Song and Ming Li
Processes 2025, 13(3), 886; https://doi.org/10.3390/pr13030886 - 17 Mar 2025
Viewed by 386
Abstract
The oil field enters a low-production liquid and high-water-cut stage, where the oil–water two-phase flow becomes increasingly complex and diverse. Traditional production profile logging interpretation methods often face significant errors and limitations. To improve interpretation accuracy, this study begins by examining the impact [...] Read more.
The oil field enters a low-production liquid and high-water-cut stage, where the oil–water two-phase flow becomes increasingly complex and diverse. Traditional production profile logging interpretation methods often face significant errors and limitations. To improve interpretation accuracy, this study begins by examining the impact of flow rate and water cut on the oil–water two-phase flow pattern (defined as the characteristic distribution and movement of oil and water phases in the flow, which varies depending on flow conditions such as flow rate and water cut) through numerical simulations and surface experimental observations. The flow characteristics of the oil–water two-phase flow are clarified. Next, the data from surface experiments are collected using a multi-component logging tool, and artificial intelligence algorithms are employed to identify flow patterns and provide data support for production profile interpretation. The genetic algorithm–backpropagation (GA-BP) algorithm is used for flow type classification, with the flow pattern recognition accuracy reaching 93.75% when compared to the experimental results. Finally, the surface experimental data and flow patterns are input into the grey wolf and falcon optimization algorithm–radial basis function (GHOA-RBF) algorithm for training and prediction. The results show that the GHOA-RBF algorithm, incorporating flow patterns, exhibits superior prediction accuracy. Specifically, the coefficient of determination (R2) for oil flow is 0.996, and for water flow, it is 0.993, outperforming traditional RBF neural networks and the GHOA-RBF algorithm without flow pattern incorporation. This demonstrates that this study provides new theoretical support for production profile logging interpretation, with significant practical implications. However, limitations include the reliance on experimental data, which may not fully capture all field conditions, and the computational efficiency of the algorithm, which may need optimization for large-scale applications. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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17 pages, 3962 KiB  
Article
Preparation and Performance Evaluation of High-Temperature Polymer Nano-Plugging Agents for Water-Based Drilling Fluids Systems Applicable to Unconventional Reservoirs
by Lei Yao, Xiaohu Quan, Yongjie Zhang, Shengming Huang, Qi Feng and Xin Zhang
Polymers 2025, 17(5), 588; https://doi.org/10.3390/polym17050588 - 23 Feb 2025
Viewed by 611
Abstract
To address the challenges of micro-fracture development in shale formations, frequent wellbore instability, and the limited plugging capability of water-based drilling fluids in unconventional reservoirs, a nano-plugging agent (NPA) was synthesized using emulsion polymerization. The synthesized NPA was characterized through thermogravimetric analysis (TGA) [...] Read more.
To address the challenges of micro-fracture development in shale formations, frequent wellbore instability, and the limited plugging capability of water-based drilling fluids in unconventional reservoirs, a nano-plugging agent (NPA) was synthesized using emulsion polymerization. The synthesized NPA was characterized through thermogravimetric analysis (TGA) and transmission electron microscopy (TEM), revealing excellent high-temperature stability and a spherical or sub-spherical morphology, with particle diameters ranging from approximately 20 to 50 nm. The rheological, filtration, and plugging properties of NPA were systematically evaluated, and its sealing mechanism was analyzed. The results demonstrate that at a test temperature of 180 °C, the optimal NPA concentration in the drilling fluid base slurry is 1.5%, achieving a 60.5% reduction in HTHP (high-temperature high-pressure) sand disc filtration loss. Additionally, the API filtration loss and HTHP filtration loss reduction rates reached 58.1% and 50.3%, respectively, highlighting the remarkable filtration loss reduction and plugging efficiency of NPA under high-temperature conditions. After NPA treatment, the specific surface area and pore volume of shale cuttings decreased to 9.348 m2/g and 0.035 cm3/g, respectively, indicating effective surface plugging. The mechanism analysis suggests that due to its nanoscale size, NPA can penetrate deep into micro-pores and fractures within the shale, achieving deep-layer plugging. Furthermore, NPA forms a physical plugging barrier on the shale surface, effectively suppressing shale hydration and swelling. This study provides valuable insights and guidance for addressing wellbore instability and the insufficient plugging performance of drilling fluids in unconventional reservoir drilling operations. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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15 pages, 9063 KiB  
Article
Study on the Imbibition Law of Laminated Shale Oil Reservoir During Injection and Shut-In Period Based on Phase Field Method
by Kun Yang, Shenglai Yang, Xinyue Liu, Shuai Zhao and Jilun Kang
Processes 2025, 13(2), 481; https://doi.org/10.3390/pr13020481 - 10 Feb 2025
Viewed by 572
Abstract
Laminated shale oil reservoirs feature well-developed microcracks, with significant differences in wettability on either side of these fractures. The complex pore structure of laminated shale oil reservoirs makes capillary imbibition prevalent during both water injection and well shut-in periods. Therefore, based on the [...] Read more.
Laminated shale oil reservoirs feature well-developed microcracks, with significant differences in wettability on either side of these fractures. The complex pore structure of laminated shale oil reservoirs makes capillary imbibition prevalent during both water injection and well shut-in periods. Therefore, based on the phase field method, this study investigates the imbibition behavior and the influencing factors during the injection and shut-in stage. This research shows that the imbibition mode determines the recovery rate: co-current imbibition > co-current imbibition + counter-current imbibition > counter-current imbibition. Co-current imbibition predominantly occurs in the dominant seepage channels, while counter-current imbibition mainly takes place in pore boundary regions. During the water injection stage, a low injection rate is beneficial for synergistic oil recovery through imbibition and displacement. As the injection rate increases, the capillary imbibition effect diminishes. Increased water saturation strengthens the co-current imbibition effect. Compared to injecting for 5 ms, injecting for 10 ms resulted in a 4.53% increase in imbibition recovery during the shut-in stage. The water sweep efficiency increases with the tortuosity of fractures. The wettability differences on either side of the fractures have a certain impact on imbibition. Around the fracture, the recovery in the strongly wetted area is 35% higher than that in the weakly water-wetted area. The wettability difference across fractures causes water to penetrate along the strongly water-wet pores, while only the inlet end and the pores near the fracture in the weakly water-wet zone are affected. Therefore, it is crucial to monitor the injection pressure to maximize the synergistic effects of displacement and imbibition during the development of laminated shale oil reservoirs. Additionally, surfactants should be used judiciously to prevent fingering due to wettability differences. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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17 pages, 3055 KiB  
Article
Rate Transient Analysis for Fractured Wells in Inter-Salt Shale Oil Reservoirs Considering Threshold Pressure Gradient
by Xiao Guo, Ting Huang, Xian Gao, Wenzhi Song, Changpeng Hu and Jingwei Liu
Processes 2024, 12(12), 2833; https://doi.org/10.3390/pr12122833 - 10 Dec 2024
Viewed by 787
Abstract
The low-velocity non-Darcy effect within the shale matrix significantly influences the well production performance of shale reservoirs, primarily caused by the threshold pressure gradient identified by various researchers. Moreover, in inter-salt shale reservoirs, salt minerals dissolve and diffuse when they encounter water-based working [...] Read more.
The low-velocity non-Darcy effect within the shale matrix significantly influences the well production performance of shale reservoirs, primarily caused by the threshold pressure gradient identified by various researchers. Moreover, in inter-salt shale reservoirs, salt minerals dissolve and diffuse when they encounter water-based working fluids, resulting in substantial alterations in pore structure. This paper introduces a transient pressure model for inter-salt shale oil reservoirs that accounts for oil flow from formation to the wellbore, considering all of the aforementioned mechanisms. The partial differential equations of this dual-porosity model, which incorporate salt dissolution and the low-velocity non-Darcy effect in the shale matrix, are derived. An accurate solution is achieved through the application of Laplace transformation and Green’s functions. We derive the analytical solutions for transient pressure and production in real space by employing the Stehfest numerical inversion method and obtain the bi-logarithmic type curves. Six distinct flow regimes are identified, and the impacts of salt dissolution, the threshold pressure gradient, the cross-flow coefficient, and the storativity ratio are discussed. This analysis holds significant importance for evaluating fluid flow and transport in inter-salt shale oil reservoirs. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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16 pages, 5617 KiB  
Article
Evaluation Method of Water Injection Development Effects in Fractured Vuggy Carbonate Reservoirs: Case Study of FI7 Strike-Slip Fault Zone
by Jie Geng, Long Xiao, Ping Yue, Yun Xiao, Hongnan Yang, Simin Qu and Xia Wang
Energies 2024, 17(22), 5611; https://doi.org/10.3390/en17225611 - 9 Nov 2024
Cited by 4 | Viewed by 766
Abstract
As the main method of secondary development, water injection has been widely used in fractured vuggy carbonate reservoirs. By using an evaluation index system combined with an integrated approach to objectively evaluate and support targeted and operational adjustments of water injection development effects [...] Read more.
As the main method of secondary development, water injection has been widely used in fractured vuggy carbonate reservoirs. By using an evaluation index system combined with an integrated approach to objectively evaluate and support targeted and operational adjustments of water injection development effects in fractured vuggy carbonate reservoirs, a comprehensive evaluation method is established in this study. The CRITIC method is used as the main approach, and the analytic hierarchy process, the entropy weight method, and the coefficient of variation method are used as sub-methods. Additionally, the clustering centres are divided using the clustering method to reduce the error caused by the irrational distribution of the relevant evaluation index data. The method is used to evaluate and analyse the effects of water injection development, using the FI7 fault zone of the Halahatang oilfield as an example. The application results show that the evaluation method is feasible and effective for cases with small data volume, fewer computational resources, and less time. This study has a certain reference significance for the evaluation of the effect of water injection development in similar fractured vuggy reservoirs. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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26 pages, 35353 KiB  
Article
New Insights into the Understanding of High-Pressure Air Injection (HPAI): The Role of the Different Chemical Reactions
by Dubert Gutiérrez, Gord Moore, Don Mallory, Matt Ursenbach, Raj Mehta and Andrea Bernal
Geosciences 2024, 14(10), 270; https://doi.org/10.3390/geosciences14100270 - 13 Oct 2024
Viewed by 999
Abstract
High-pressure air injection (HPAI) is an enhanced oil recovery process in which compressed air is injected into deep, light oil reservoirs, with the expectation that the oxygen in the injected air will react with a fraction of the reservoir oil at an elevated [...] Read more.
High-pressure air injection (HPAI) is an enhanced oil recovery process in which compressed air is injected into deep, light oil reservoirs, with the expectation that the oxygen in the injected air will react with a fraction of the reservoir oil at an elevated temperature to produce carbon dioxide. The different chemical reactions taking place can be grouped into oxygen addition, thermal cracking, oxygen-induced cracking, and bond scission reactions. The latter reactions involve the combustion of a flammable vapor as well as the combustion of solid fuel, commonly known as “coke”. Since stable peak temperatures observed during HPAI experiments are typically below 300 °C, it has been suggested that thermal cracking and combustion of solid fuel may not be important reaction mechanisms for the process. The objective of this work is to assess the validity of that hypothesis. Therefore, this study makes use of different oxidation and combustion HPAI experiments, which were performed on two different light oil reservoir samples. Modeling of those tests indicate that thermal cracking is not an important reaction mechanism during HPAI and can potentially be ignored. The work also suggests that the main fuel consumed by the process is a flammable vapor generated by the chemical reactions. This represents a shift from the original in situ combustion paradigm, which is based on the combustion of coke. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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22 pages, 1525 KiB  
Article
Selection of Enhanced Oil Recovery Method on the Basis of Clustering Wells
by Oksana Marinina, Anton Malikov, Yulia Lyubek, Svetlana Pasternak, Ekaterina Reshneva and Natalia Stolbovskaya
Processes 2024, 12(10), 2082; https://doi.org/10.3390/pr12102082 - 25 Sep 2024
Cited by 4 | Viewed by 1158
Abstract
The relevance of the technical and economic evaluation of the application of enhanced oil recovery methods at oil fields at the final stage of development is related to the need to recover the remaining reserves, including hard-to-recover (HTR) reserves, the share of which [...] Read more.
The relevance of the technical and economic evaluation of the application of enhanced oil recovery methods at oil fields at the final stage of development is related to the need to recover the remaining reserves, including hard-to-recover (HTR) reserves, the share of which is growing annually. Currently, there are many effective enhanced oil recovery (EOR) methods for different process conditions, but their application has different effects based on the combination of methods, techniques and production conditions. The aim of this study was to approach the scaling of the effect of the application of modern EOR using the methodology of the clustering of wells with similar technological characteristics. This paper proposes a methodology for the selection of candidate wells to form clusters based on a set of indicators that determine the choice of enhanced oil recovery technology in oil fields at the final stage. The technological efficiency of sidetracking and multistage hydraulic fracturing application was evaluated based on the analytical method of well flow rate estimation. By applying cluster analysis to selected wells, three clusters were formed, each including three wells, united by the geological properties of their reservoir rocks and the filtration–capacitive properties of the oil. After this, the optimal technologies were selected for two clusters—hydraulic fracturing and sidetracking. The accumulated oil production, recovered due to the application of the technologies, from six wells for the first 7 years after the operation was estimated at 306.92 thousand tons of oil. Due to the achieved technological effect, the economic efficiency of the development of the studied oil field will increase due to the proceeds from the sales of the extracted additional oil. The results of this study can be used in the calculation of technical and economic efficiency at oil fields with similar conditions. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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15 pages, 3934 KiB  
Article
A New Approach to a Fracturing Sweet Spot Evaluation Method Based on Combined Weight Coefficient Method—A Case Study in the BZ Oilfield, China
by Mao Jiang, Chengyong Peng, Jianshu Wu, Zongyong Wang, Yi Liu, Bingjin Zhao and Yan Zhang
Processes 2024, 12(9), 1830; https://doi.org/10.3390/pr12091830 - 28 Aug 2024
Viewed by 925
Abstract
The Sha3 member of the BZ Oilfield in Bohai Sea represents a typical ultra-low permeability thin interbedding reservoir. Hydraulic fracturing is an effective method for increasing oil and gas production. However, the complex geological conditions make it difficult to screen out the optimal [...] Read more.
The Sha3 member of the BZ Oilfield in Bohai Sea represents a typical ultra-low permeability thin interbedding reservoir. Hydraulic fracturing is an effective method for increasing oil and gas production. However, the complex geological conditions make it difficult to screen out the optimal frac spot. Consequently, the design of hydraulic fracturing exhibits certain limitations. A novel method for evaluating sweet spots is proposed, based on a refined geological reservoir model that considers the varying degrees of influence that geological and engineering factors have on fracturing effectiveness. This method utilizes grey correlation and hierarchical analysis to quantify and characterize the weight coefficients of each factor, ultimately leading to a combined weight coefficient approach. The results indicate that permeability and fracturing scale are the primary factors that impact the post-frac production of the BZ oilfield, with their respective combined weights being 0.33 and 0.25. The average weight for geological factors is 0.18, while for engineering factors it is 0.15. This suggests that geological factors have a greater influence on production than engineering factors. Furthermore, the correlation coefficient between the dual sweet spot index and the production is 0.96, indicating a strong positive correlation between the two variables. After comparing the predicted and actual production of each well, it was determined that the anastomosis rate is 80%. This finding holds significant guiding significance for selecting the optimal fracturing spot. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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14 pages, 1791 KiB  
Article
Research on Gas Channeling Identification Using the Fuzzy Comprehensive Evaluation Method
by Yang Liu, Mingqiang Hao, Ran Bi, Chaoliang Bian and Xiaoqing Wang
Energies 2024, 17(16), 3908; https://doi.org/10.3390/en17163908 - 8 Aug 2024
Cited by 5 | Viewed by 1468
Abstract
With the development of the petroleum industry and advancements in technology, gas injection techniques have gradually matured and become an important means to enhance oil recovery in reservoir development. Gas channeling is a major challenge in the process of gas injection development. The [...] Read more.
With the development of the petroleum industry and advancements in technology, gas injection techniques have gradually matured and become an important means to enhance oil recovery in reservoir development. Gas channeling is a major challenge in the process of gas injection development. The presence of gas channeling can lead to a decrease in the swept volume of gas flooding, severely affecting the effectiveness of gas injection development. This paper focuses on low-permeability reservoirs, comprehensively analyzing the development characteristics of low-permeability reservoirs and the dynamic characteristics of gas flooding production. It selects and evaluates indicators for assessing the development degree of gas channeling and establishes a fuzzy comprehensive evaluation method for evaluating gas channeling in the gas injection development of low-permeability reservoirs. Based on the evaluation values derived from the fuzzy comprehensive evaluation, it classifies the development levels of gas channeling. Application in oilfield cases shows that the evaluation results of this method are generally consistent with the dynamic response of production data, with high evaluation accuracy. This provides strong support for implementing gas channeling prevention and control measures on site and improving the effectiveness of gas injection development. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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15 pages, 3345 KiB  
Article
Identification of Multi-Parameter Fluid in Igneous Rock Reservoir Logging—A Case Study of PL9-1 in Bohai Oilfield
by Jiakang Liu, Kangliang Guo, Shuangshuang Zhang, Xinchen Gao, Jiameng Liu and Qiangyu Li
Processes 2024, 12(7), 1537; https://doi.org/10.3390/pr12071537 - 22 Jul 2024
Cited by 2 | Viewed by 1038
Abstract
Since the “13th Five-Year Plan”, the exploration of large-scale structural oil and gas reservoirs in the Bohai oilfield has become more complex, and the exploration of igneous oil and gas reservoirs has become the focus of current attention. At present, igneous rock reservoir [...] Read more.
Since the “13th Five-Year Plan”, the exploration of large-scale structural oil and gas reservoirs in the Bohai oilfield has become more complex, and the exploration of igneous oil and gas reservoirs has become the focus of current attention. At present, igneous rock reservoir fluid identification methods are mainly based on the evaluation method of logging single parameter construction, which is primarily a qualitative identification due to lithology, physical property, and engineering factors. Accurate acquisition of interference logging data, and multi-parameter coupling and recording coupling methods are few, lacking systematic and comprehensive evaluation and analysis of logging data. Since conventional logging data in the study area have difficulty accurately and quickly identifying reservoir fluid properties, a systematic analysis was conducted of three factors: lithology, physical properties, and engineering, as well as a variety of logging parameters (gas measurement, three-dimensional quantitative fluorescence, geochemical, FLAIR, etc.) that can reflect fluid properties were integrated. Based on parameter sensitivity analysis, the quantitative characterization index FI of multi-parameter coupling fluid identification was established using the data from testing, sampling, and laboratory testing to develop the identification standard. The sensitivity analysis and optimization of characteristic parameters were carried out by integrating the data reflecting fluid properties such as gas surveys, geochemical data, and related logging data. Combined with gas logging-derived parameters and improved engineering parameters (the value of alkanes released by rock cracking per unit volume Cadjust, C1 abnormal multiple values, three-dimensional quantitative fluorescence correlation factor N), the fluid properties were identified, evaluation factors were constructed based on factor analysis, and fluid identification interactive charts were established. By analyzing test wells in the PL9-1 well area, the results of comparison test data are more reliable. Compared with conventional methods, this method reduces the dependence of a single parameter by synthesizing multiple parameters and reduces the influence of lithology, physical properties, and engineering parameters on fluid identification. It is more reasonable and practical. It can accurately and quickly identify the fluid properties of igneous rock reservoirs in the study area. It has a guiding significance for improving the accurate evaluation of logging data and increasing exploration benefits. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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19 pages, 3037 KiB  
Article
Wavelet Cross-Correlation Signal Processing for Two-Phase Flow Control System in Oil Well Production
by Dmitry Arseniev, Galina Malykhina and Dmitry Kratirov
Processes 2024, 12(7), 1479; https://doi.org/10.3390/pr12071479 - 15 Jul 2024
Cited by 1 | Viewed by 1424
Abstract
An algorithm based on continuous measurement of multiphase flows of oil well production has been designed to improve the efficiency of the technical control of oil production processes in the field. Separation-free, non-contact measurement of multiphase flows of oil well products allows increasing [...] Read more.
An algorithm based on continuous measurement of multiphase flows of oil well production has been designed to improve the efficiency of the technical control of oil production processes in the field. Separation-free, non-contact measurement of multiphase flows of oil well products allows increasing the efficiency of managing oil production processes in the field. Monitoring the current density using radioisotope measuring transducers (RMTs) allows obtaining information about the structure of the flow in the form of the distribution of gas inclusions and the speed of movement of liquid and gas in a two-phase flow. Fluid velocity measurement is based on digital processing of RMT signals, applying a continuous or discrete undecimated wavelet transform to them, and assessing the cross-correlation of wavelet coefficients in individual subspaces of the wavelet decomposition. The cross-correlation coefficients of two RMT signals located at a base distance, calculated in the subspaces of the wavelet decomposition, characterize the speed of movement of gas bubbles of different sizes in a vertical pipe. The measurement assumes that the velocity of the liquid phase of the oil flow in a vertical pipe mainly corresponds to the velocity of small bubbles. This speed should be determined by the maximum cross-correlation of wavelet coefficients in the corresponding decomposition subspace. Computer modeling made it possible to evaluate the characteristics of the algorithm for controlling the speed of liquid movement in the gas–liquid flow of oil well products and determine the mass flow rate of the liquid and the relative value of the gas content. The implementation of the algorithm in a multi-channel version of the device allows monitoring an entire cluster of wells in the field. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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14 pages, 6498 KiB  
Article
Evaluation of the Synergistic Oil Displacement Effect of a CO2 Low Interfacial Tension Viscosity-Increasing System in Ultra-Low Permeability Reservoirs
by Zequn Chen, Yuanwu Dong, Hao Hu, Xinyue Zhang and Shanfa Tang
Processes 2024, 12(7), 1476; https://doi.org/10.3390/pr12071476 - 14 Jul 2024
Cited by 3 | Viewed by 1360
Abstract
In addressing the issue of poor control over gas permeability during the CO2 flooding process in ultra-low permeability reservoirs, this study proposes the use of a low interfacial tension viscosity-increasing system as a substitute for water in CO2–water alternating flooding [...] Read more.
In addressing the issue of poor control over gas permeability during the CO2 flooding process in ultra-low permeability reservoirs, this study proposes the use of a low interfacial tension viscosity-increasing system as a substitute for water in CO2–water alternating flooding to enhance CO2 mobility control and increase oil recovery. The performance of the system was evaluated through tests of viscosity, interfacial tension, wettability, and emulsification properties, and the injection behavior and gas channeling prevention effect of the viscosity-increasing system with CO2 alternate flooding were investigated. The results indicate that the low interfacial tension viscosity-increasing fluid exhibits good thickening properties, interfacial activity, hydrophilic wettability, and oil–water emulsification performance, also demonstrating strong environmental adaptability. The CO2–low interfacial tension viscosity-increasing fluid alternate flooding shows good injectivity in ultra-low permeability cores (1.085 mD). Following water flooding in heterogeneous ultra-low permeability cores, the implementation of CO2 low interfacial tension viscosity-increasing fluid alternate flooding can lead to a 15.91% increase in overall recovery compared to water flooding, outperforming CO2 flooding and CO2–water alternating flooding. The mechanisms by which the CO2 low interfacial tension viscosity-increasing fluid enhances oil recovery include reducing interfacial tension, improving mobility ratio, altering rock surface wettability, and emulsification effects. The low interfacial tension viscosity-increasing systems demonstrate effective mobility control and oil displacement capabilities and synergistically enhance the efficiency of CO2, presenting potential application prospects in the development of CO2 flooding in ultra-low permeability reservoirs. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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29 pages, 10242 KiB  
Article
Evaluation of the Hydraulic Fracturing Tendencies of Consolidated Sandstone Reservoirs Based on the Catastrophe Theory
by Haowei Feng, Ping Wang, Zhan Qu, Hai Huang, Liang Wang, Yongsheng Wei and Yawen He
Processes 2024, 12(7), 1439; https://doi.org/10.3390/pr12071439 - 10 Jul 2024
Viewed by 1127
Abstract
The evaluation of rock hydraulic fracturing tendency plays a crucial role in the selection of fracturing layers within reservoirs and the evaluation of post-compression capacity. The sandstone reservoirs in the Yihuang New Area have poor physical properties and are deeply buried. It is [...] Read more.
The evaluation of rock hydraulic fracturing tendency plays a crucial role in the selection of fracturing layers within reservoirs and the evaluation of post-compression capacity. The sandstone reservoirs in the Yihuang New Area have poor physical properties and are deeply buried. It is necessary to increase the production of oil and gas by hydraulic fracturing. Regarding the sandstones in the region, the following parameters were considered: combined compressive strength, bulk modulus, shear modulus, fracture index, horizontal-stress difference coefficient, and fracture toughness. In accordance with the catastrophe theory, a multi-level structure was established for the hydraulic fracturing-tendency evaluation of sandstone reservoirs, consisting of a target layer, a guide layer, and an indicator layer. A catastrophic model for evaluating the hydraulic fracturing tendency of sandstone reservoirs was established. The results are consistent with those obtained from the Analytic Hierarchy Process. However, the catastrophe theory significantly reduces subjective interference. The results indicate that when the hydraulic fracturing-tendency evaluation value is greater than 0.8, the reservoir can be fractured well; when the hydraulic fracturing-tendency evaluation value is between 0.7 and 0.8, the fracture reservoir is moderate; and when the hydraulic fracturing-tendency evaluation value is less than 0.7, the fractured reservoir is poor. The optimal fracture intervals for the Yi 70 well are 1320–1323 m, 1350–1355 m, and 1355–1360 m. The optimal fracture planes for the Yi 76 well are 1921–1925 m and 1925–1930 m. The optimal fracture planes for the Yi 10-1-26 well are 2487–2495 m, 2585–2587 m, and 2589–2591 m. The hydraulic fracturing-tendency model developed in this study has been applied to several well sections of sandstone reservoirs in the Yihuang New Area. Additionally, the model was compared with existing hydraulic fracturing-tendency evaluation models. The evaluation results are in agreement with the post-pressure capacity-monitoring data. The accuracy of the model presented in this study has been verified, as has its applicability to other sandstone reservoirs. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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19 pages, 5769 KiB  
Article
An Experimental Investigation of Surfactant-Stabilized CO2 Foam Flooding in Carbonate Cores in Reservoir Conditions
by Madiyar Koyanbayev, Randy Doyle Hazlett, Lei Wang and Muhammad Rehan Hashmet
Energies 2024, 17(13), 3353; https://doi.org/10.3390/en17133353 - 8 Jul 2024
Cited by 2 | Viewed by 1528
Abstract
Carbon dioxide (CO2) injection for enhanced oil recovery (EOR) has attracted great attention due to its potential to increase ultimate recovery from mature oil reservoirs. Despite the reported efficiency of CO2 in enhancing oil recovery, the high mobility of CO [...] Read more.
Carbon dioxide (CO2) injection for enhanced oil recovery (EOR) has attracted great attention due to its potential to increase ultimate recovery from mature oil reservoirs. Despite the reported efficiency of CO2 in enhancing oil recovery, the high mobility of CO2 in porous media is one of the major issues faced during CO2 EOR projects. Foam injection is a proven approach to overcome CO2 mobility problems such as early gas breakthrough and low sweep efficiency. In this experimental study, we investigated the foam performance of a commercial anionic surfactant, alpha olefin sulfonate (AOS), in carbonate core samples for gas mobility control and oil recovery. Bulk foam screening tests demonstrated that varying surfactant concentrations above a threshold value had an insignificant effect on foam volume and half-life. Moreover, foam stability and capacity decreased with increasing temperature, while variations in salinity over the tested range had a negligible influence on foam properties. The pressure drop across a brine-saturated core sample increased with an increasing concentration of surfactant in the injected brine during foam flooding experiments. Co-injection of CO2 and AOS solution at an optimum concentration and gas fractional flow enhanced oil recovery by 6–10% of the original oil in place (OOIP). Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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13 pages, 3105 KiB  
Article
Importance of Fluid/Fluid Interactions in Enhancing Oil Recovery by Optimizing Low-Salinity Waterflooding in Sandstones
by Jose Villero-Mandon, Nurzhan Askar, Peyman Pourafshary and Masoud Riazi
Energies 2024, 17(13), 3315; https://doi.org/10.3390/en17133315 - 5 Jul 2024
Cited by 1 | Viewed by 1037
Abstract
Low-salinity waterflooding/smart waterflooding (LSWF/SWF) is a technique involving the injection of water with a modified composition to alter the equilibrium between rock and fluids within porous media to enhance oil recovery. This approach offers significant advantages, including environmental friendliness and economic efficiency. Rock/fluid [...] Read more.
Low-salinity waterflooding/smart waterflooding (LSWF/SWF) is a technique involving the injection of water with a modified composition to alter the equilibrium between rock and fluids within porous media to enhance oil recovery. This approach offers significant advantages, including environmental friendliness and economic efficiency. Rock/fluid mechanisms such as wettability alteration and fines migration and fluid/fluid mechanisms such as a change in interfacial tension and viscoelasticity are considered active mechanisms during LSWF/SWF. In this study, we evaluated the effect of these mechanisms, by LSWF/SWF, on sandstones. To investigate the dominant mechanisms, coreflooding studies were performed using different injected fluid composition/salinity and wettability states. A comparative analysis of the recovery and mobility reduction factor was performed to clarify the conditions at which fluid/fluid mechanisms are also effective. Our studies showed that wettability alteration is the most dominant mechanism during LSWF/SWF, but, for weak oil-wet cases, optimizing brine compositions may activate fluid/fluid mechanisms. Brine composition significantly influences interface stability and performance, with sulfate content playing a crucial role in enhancing interface properties. This was observed via mobility behavior. A comparative analysis of pressure differentials showed that fines migration may act as a secondary mechanism and not a dominant one. This study highlights the importance of tailored brine compositions in maximizing oil recovery and emphasizes the complex interplay between rock and fluid properties in enhanced oil recovery strategies. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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19 pages, 2624 KiB  
Article
Method for the Quantitative Evaluation of Low-Permeability Reservoir Damage in the East China Sea Based on Experimental Evaluation and Modeling Calculation
by Xingbin Zhao, Yiming Jiang, Peng Xu, Jun Yu and Lingzhi Xie
Processes 2024, 12(7), 1406; https://doi.org/10.3390/pr12071406 - 5 Jul 2024
Viewed by 1158
Abstract
Reservoir damage is a key factor affecting reservoir evaluation, ensuring stable reservoir production and improving the utilization rate of oil and gas resources. At present, the evaluation of damage caused by reservoir drilling fluid is too empirical, and there is a lack of [...] Read more.
Reservoir damage is a key factor affecting reservoir evaluation, ensuring stable reservoir production and improving the utilization rate of oil and gas resources. At present, the evaluation of damage caused by reservoir drilling fluid is too empirical, and there is a lack of methods for the high-precision evaluation of reservoir damage after drilling fluid invasion and pollution. In a block in the East China Sea, the production capacity is limited due to an excessive balance of drilling fluid and long exposure time. In order to ensure safe drilling, the dynamic damage mechanism of drilling fluid during drilling was analyzed. The core of the main reservoir of well XH-1 in a block in the East China Sea was selected for carrying out an experiment evaluating the dynamic damage caused by drilling fluid. According to the experimental results, the damage rate of reservoir permeability caused by drilling fluid invasion ranges between 58.25 and 87.25%, and the overall dynamic damage degree can be classified between medium and high. Combined with the experimental parameters, a mathematical model of drilling fluid invasion depth was established, and the calculation formulas of drilling fluid invasion depth and contaminated skin were derived. The results showed that the drilling fluid depth of the reservoir section corresponding to the core of well XH-1 was 0.47~0.83 m, and the contaminated skin factor was 1.22~13.41, which made up for the lack of evaluation methods of reservoir damage caused by drilling fluid and provided a theoretical basis for the optimization of drilling fluid parameters and exploration drilling technology in oilfield operations. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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21 pages, 4187 KiB  
Article
Analysis of Factors Influencing Three-Dimensional Multi-Cluster Hydraulic Fracturing Considering Interlayer Effect
by Xin Zhou, Xiangjun Liu and Lixi Liang
Appl. Sci. 2024, 14(12), 5330; https://doi.org/10.3390/app14125330 - 20 Jun 2024
Cited by 1 | Viewed by 996
Abstract
This study establishes a three-dimensional cohesive model of multi-cluster hydraulic fracturing using finite element method (FEM). It fully considers the interaction between the interlayer and the reservoir and analyzes the key factors influencing fracture propagation. The results show that during the initial stage [...] Read more.
This study establishes a three-dimensional cohesive model of multi-cluster hydraulic fracturing using finite element method (FEM). It fully considers the interaction between the interlayer and the reservoir and analyzes the key factors influencing fracture propagation. The results show that during the initial stage of hydraulic fracturing, the width of the edge fracture is greater than that of the mid fracture, while the situation is reversed for the fracture length. A larger cluster spacing leads to less interaction between fractures, while a greater number of clusters increases the interaction between fractures. With an increase in displacement, the lost fracturing fluid entering the formation enhances the interaction between fractures. An increase in elastic modulus results in a decrease in the width and height of edge fractures but an increase in their length, with little impact on mid fractures. As Poisson’s ratio increases, there is little change in the fracture morphology of edge fractures, while the width and height of mid fractures increase significantly. With an increase in permeability, the influx of fracturing fluid into the interlayer decreases, leading to a reduction in the interaction between fractures. Finally, the study analyzes and discusses the impact of these parameters on the SRV (stimulated reservoir volume) in both the reservoir and the interlayer. These findings provide new insights for hydraulic fracturing and contribute to improving its productivity. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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17 pages, 3219 KiB  
Article
Risk Assessment Method for Analyzing Borehole Instability Considering Formation Heterogeneity
by Xiangsen Gao, Min Wang, Xian Shi, Cui Li and Mingming Zhang
Processes 2024, 12(1), 70; https://doi.org/10.3390/pr12010070 - 28 Dec 2023
Cited by 2 | Viewed by 1415
Abstract
In the study of borehole instability, the majority of input parameters often rely on the average values that are treated as fixed values. However, in practical engineering scenarios, these input parameters are often accompanied by a high degree of uncertainty. To address this [...] Read more.
In the study of borehole instability, the majority of input parameters often rely on the average values that are treated as fixed values. However, in practical engineering scenarios, these input parameters are often accompanied by a high degree of uncertainty. To address this limitation, this paper establishes a borehole stability model considering the uncertainty of input parameters, adopts the Monte Carlo method to calculate the borehole stability reliability at different drilling fluid densities, evaluates the sensitivity of borehole instability to a single parameter, and studies the safe drilling fluid density window at different borehole stability reliability values under multi-parameter uncertainties. The results show that the uncertainty of rock cohesion has a great influence on the fracture pressure of the vertical and horizontal wells. The minimum horizontal stress has the greatest influence on the fracture pressure of the vertical and horizontal wells, followed by pore pressure. In the analysis of borehole stability, the accuracy of cohesion and minimum horizontal stress parameters should be improved. In scenarios involving multiple parameter uncertainties, while the overall trend of the analysis results remains consistent with the conventional borehole stability outcomes, there is a noteworthy narrowing of the safe drilling fluid density window. This suggests that relying on conventional borehole stability analysis methods for designing the safe drilling fluid density window can considerably increase the risks of borehole instability. Uncertainty assessment is crucial to determine the uncertainties associated with the minimum required mud pressure, thereby ensuring more informed decision-making during drilling operations. To meet practical application demands, structure and boundary condition uncertainties should be implemented for a more comprehensive assessment of borehole stability. Full article
(This article belongs to the Topic Enhanced Oil Recovery Technologies, 3rd Edition)
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