Enhanced Oil Recovery Technologies, 3rd Volume

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

Participating Journals

Journal Name	Impact Factor	CiteScore	Launched Year	First Decision (median)	APC
Applied Sciences applsci	2.5	5.3	2011	17.8 Days	CHF 2400	Submit
Energies energies	3.0	6.2	2008	17.5 Days	CHF 2600	Submit
Geosciences geosciences	2.4	5.3	2011	26.2 Days	CHF 1800	Submit
Polymers polymers	4.7	8.0	2009	14.5 Days	CHF 2700	Submit
Processes processes	2.8	5.1	2013	14.4 Days	CHF 2400	Submit

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Published Papers (8 papers)

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19 pages, 3037 KiB  

Open AccessArticle

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

Viewed by 175

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 Volume)

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14 pages, 6498 KiB  

Open AccessArticle

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

Viewed by 413

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 Volume)

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29 pages, 10242 KiB  

Open AccessArticle

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 329

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 Volume)

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19 pages, 5769 KiB  

Open AccessArticle

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

Viewed by 353

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 Volume)

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13 pages, 3105 KiB  

Open AccessArticle

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

Viewed by 364

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 Volume)

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19 pages, 2624 KiB  

Open AccessArticle

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 450

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 Volume)

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21 pages, 4187 KiB  

Open AccessArticle

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

Viewed by 342

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 Volume)

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17 pages, 3219 KiB  

Open AccessArticle

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

Viewed by 751

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 Volume)

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