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Advances in Integrated Technology of Fracturing and Enhanced Oil Recovery in Tight Reservoirs

A special issue of Sustainability (ISSN 2071-1050). This special issue belongs to the section "Sustainable Engineering and Science".

Deadline for manuscript submissions: 14 June 2024 | Viewed by 5895

Special Issue Editors

Dr. Yanjun Zhang

E-Mail Website
Guest Editor
College of Petroleum Engineering, Xi’an Shiyou University, Xi’an 710065, China
Interests: inter-well fracturing interference; integration of hydraulic fracturing and enhanced oil recovery
Special Issues, Collections and Topics in MDPI journals
Dr. Luyu Wang

E-Mail Website
Guest Editor
Department of Civil and Environmental Engineering, The Hong Kong Polytechnic University, Hung Hom, Kowloon, Hong Kong
Interests: damage and fracture of geomaterials; flow and transport in fractured reservoirs; stability analysis of subsurface engineering
Dr. Qiang Sun

E-Mail Website
Guest Editor
College of Geology and Environment, Xi’an University of Science and Technology, Xi’an 710000, China
Interests: high-temperature rock mechanics; geological hazard prevention and environmental protection; surface process and environmental effect
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues:

A large volume of fracturing fluids is injected into fracturing formations to create complex fracture networks. This procedure can increase the conductive pathway for the flow of oil and gas in tight reservoirs. During the fracturing, the liquid injected into the reservoirs at a speed exceeding the water uptake capacity of the formation not only helps create fractures, but also causes the deformation of the rock mass, water–rock reactions, and the redistribution of oil and water in matrix pores. Therefore, there are many underlying physical processes, as well as the technical issues, behind the hydraulic fracturing processes. The injection scale of thousands of sands and ten thousand of liquid renders the in situ stress field in a state of dynamic change, which directly affects the initiation and propagation of fractures. When tight reservoirs are developed using a well factory, excessive propagation of fractures will cause engineering risks, such as inter-well fracturing interference, casing deformation resulted from stress evolution, and reductions in the oil and gas recovery. Enhanced oil recovery involves the multiphase and multi-scale flow of oil and gas in matrix pores and fractures. Integrated technology of fracturing and enhanced oil recovery is an effective means of solving the above problems.

In light of the above issues, this Special Issue aims to define the evolution law of stress fields during large-scale fracturing, control the scale of fracture propagation, reduce the negative impact of inter-well fracturing interference on productivity, prevent casing deformation resulted from in-situ stress changes in advance, and improve the utilization efficiency of fracturing fluid. The above related studies should provide theoretical guidance for the development of tight reservoirs.

In this Special Issue, original research articles and reviews are welcome. Research areas may include (but are not limited to) the following:

  • New theories and methods of Integrated Technology of Fracturing and EOR
  • Stress field evolution during fracturing in the real-field scales
  • Numerical and experimental analyses of fracture propagation and control
  • Inter-well fracturing interference mechanisms
  • Casing deformation resulting from stress evolution
  • Utilization efficiency of fracturing fluids
  • The properties of fracturing fracture
  • Flow and coupled geomechanical–hydraulic processes
  • New techniques of enhanced oil recovery

We look forward to receiving your contributions.

Dr. Yanjun Zhang
Dr. Luyu Wang
Dr. Qiang Sun
Guest Editors

Manuscript Submission Information

Manuscripts should be submitted online at www.mdpi.com by registering and logging in to this website. Once you are registered, click here to go to the submission form. Manuscripts can be submitted until the deadline. All submissions that pass pre-check are peer-reviewed. Accepted papers will be published continuously in the journal (as soon as accepted) and will be listed together on the special issue website. Research articles, review articles as well as short communications are invited. For planned papers, a title and short abstract (about 100 words) can be sent to the Editorial Office for announcement on this website.

Submitted manuscripts should not have been published previously, nor be under consideration for publication elsewhere (except conference proceedings papers). All manuscripts are thoroughly refereed through a single-blind peer-review process. A guide for authors and other relevant information for submission of manuscripts is available on the Instructions for Authors page. Sustainability is an international peer-reviewed open access semimonthly journal published by MDPI.

Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2400 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

  • stress field evolution fracture control
  • inter-well fracturing interference
  • casing deformation
  • utilization of fracturing fluids
  • fracturing
  • EOR

Published Papers (6 papers)

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Research

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15 pages, 3134 KiB  
Article
Experimental and EOR Mechanism Study of Water Shutoff Effects on Fractured Tight Sand Gas Reservoirs Using Fuzzy Ball Fluids
by Xiujuan Tao, Guoliang Liu, Yue Wang, Pinwei Li, Wei Gao, Panfeng Wei and Lihui Zheng
Sustainability 2023, 15(19), 14528; https://doi.org/10.3390/su151914528 - 06 Oct 2023
Viewed by 686
Abstract
In recent years, there has been quite a dispute over the water shutoff effect of fuzzy ball fluids in fractured tight sandstone gas reservoirs. The core issue of this dispute is to try and make fuzzy ball fluid stabilize gas during the water [...] Read more.
In recent years, there has been quite a dispute over the water shutoff effect of fuzzy ball fluids in fractured tight sandstone gas reservoirs. The core issue of this dispute is to try and make fuzzy ball fluid stabilize gas during the water shutoff process for sustainable development. In order to solve this dispute, the Linxing He-2 reservoir matrix core and a core with artificial fractures were used to simulate interlayer water, artificial fractures, and water output channels from the side and bottom. Simulated formation water and nitrogen were used as the two-phase flow phase. The breakthrough pressure of the air and water phases was tested after plugging with fuzzy ball fluid in order to simulate and analyze the water shutoff effect of the fuzzy ball fluid and its ability to achieve air establishment and water control. The results of this study show that for the core matrix, the breakthrough pressure gradient for water and gas varied from 0.200 MPa/cm to 0.210 MPa/cm and 0.015 MPa/cm to 0.025 MPa/cm, and for artificial fractured cores, the breakthrough pressure gradient of water and gas varied from 0.035 MPa/cm to 0.040 MPa/cm and 0.015 MPa/cm to 0.020 MPa/cm. These results prove that fuzzy ball fluid can block small-scale water output channels, such as matrix pores, through the polymer film-forming structure, and plug the artistic cracks and large-scale water output channels of the water flowing into the sides and bottom through the accumulation of a large number of fuzzy balls, which greatly improves the flow resistance of water. The amount of fuzzy ball fluid should be carefully adjusted with consideration of the water output and formation conditions. For large-scale water output channels and side and bottom water shutoff operations, it is recommended that the amount of fuzzy balls be increased along with the number of fuzzy balls in the system in order to increase the breakthrough pressure of water and achieve the stable control of air and water. It is believed that the fuzzy balls would quickly change their shapes to match the sizes of fracture channels to enter into fractured reservoirs and that an active hydrophobic membrane would form on the surface of fractured rocks, with macromolecules and surfactants being dispersed in the fluid system. In addition, the interface between the fuzzy balls is also hydrophobic, which would slow down the flow of water and provide a continuous gas percolating channel after aggregating and entering into the fractures. This increases the persistence of water intruding into the formation and does not affect the percolation of the gas of fractured tight sandstone gas reservoirs. This research is of great significance for the EOR of tight sand gas reservoirs and the sustainable development of oil and gas resources in China. Full article
(This article belongs to the Special Issue Advances in Integrated Technology of Fracturing and Enhanced Oil Recovery in Tight Reservoirs)
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23 pages, 10699 KiB  
Article
Influencing Factors of Drainage and Production and Quantitative Evaluation in Shale Gas Reservoirs
by Hao Xu, Tuan Gu, Shuangliang Wu, Shucan Xu, Xiang Yu, Xiaochao Guo, Tao Fan and Desheng Zhou
Sustainability 2023, 15(17), 12944; https://doi.org/10.3390/su151712944 - 28 Aug 2023
Viewed by 660
Abstract
As a transitional energy source, natural gas plays a crucial role in the energy transition. In the efficient development of shale gas, the drainage and production process, as an important link between hydraulic fracturing and production, determines the recovery rate of individual wells. [...] Read more.
As a transitional energy source, natural gas plays a crucial role in the energy transition. In the efficient development of shale gas, the drainage and production process, as an important link between hydraulic fracturing and production, determines the recovery rate of individual wells. To clarify the main controlling factors of shale gas drainage and production, provide strategies for classification, and improve the recovery rates of individual wells, a numerical simulation method was proposed to analyze the factors affecting drainage and production, and the VIKOR method was used for quantitative evaluation of the drainage and production effects. The research results showed that: (1) The study identified nine main controlling factors affecting drainage and production performance, including gas saturation, permeability, stress difference, burial depth, formation pressure, cumulative fracture volume, final fracture loss rate, average final diversion ability, and wellbore liquid loading. (2) A workflow for quantitatively evaluating the drainage and production effectiveness of shallow shale gas wells and selecting wells with potential for optimized drainage and production was proposed. The correlation between the evaluation results and EUR fitting had an R2 value of 0.71, indicating a good level of credibility. (3) The evaluation results for the target gas field indicated that out of the 16 representative wells, 12 wells have optimization potential, with 5 wells showing significant optimization potential. Studying the rules of shale gas drainage and production and evaluating the drainage and production effects can help us to propose refined drainage and production strategies, which are essential for improving the estimated ultimate recovery (EUR). Full article
(This article belongs to the Special Issue Advances in Integrated Technology of Fracturing and Enhanced Oil Recovery in Tight Reservoirs)
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28 pages, 15531 KiB  
Article
Numerical Simulation Study of Pressure Transfer Based on the Integration of Fracturing, Shut-in and Production in Tight Reservoirs
by Tuan Gu, Le Yan, Tao Fan, Xiaochao Guo, Feng Fan and Yanjun Zhang
Sustainability 2023, 15(16), 12184; https://doi.org/10.3390/su151612184 - 09 Aug 2023
Viewed by 917
Abstract
As an important replacement resource for conventional oil and gas, tight oil and gas are quite abundant. Long horizontal wells and multi-stage fracturing have become key technologies for developing tight oil and gas, and reasonable shut-in measures can improve the utilization efficiency of [...] Read more.
As an important replacement resource for conventional oil and gas, tight oil and gas are quite abundant. Long horizontal wells and multi-stage fracturing have become key technologies for developing tight oil and gas, and reasonable shut-in measures can improve the utilization efficiency of fracturing fluid. Therefore, it is especially critical to master the pressure transfer law during the shut-in process in tight reservoirs to further improve the energy efficiency of fracturing fluid. However, many studies have mostly focused on the separate design of fracturing, shut-in and production, and have not yet revealed the pressure transfer law during shutting in well based on the integration of fracturing, shut-in and production, which makes it difficult to realize the efficient development of tight oil and gas. Taking the tight oil reservoir in Block M as an example, the geological model of the target block was established using an integrated fracturing development software platform, on which the simulation of fracture extension, well shut-in and production was carried out. The changes in the reservoir pressure field during shutting in well were analyzed, and the influence law of fracturing fluid volume, shut-in time, reservoir original formation pressure and fracture network complexity on the effect of well shut-in were studied to optimize the shut-in system. It was found that the retained fluid increases, the pore pressure of the near-fracture matrix increases, and the diffusion distance of fracturing fluid to the distant matrix increases. The tight oil production increased after shutting in well, and the optimal retained fluid volume of 9600 m3 was actually preferred based on the model. The pore pressure of the near-fracture matrix decreases as the shut-in time increases, the diffusion distance of fracturing fluid to the distant matrix increases, and the pore pressure decreases with an increase in diffusion distance. The tight oil production increased after shutting in well, and the optimal shut-in time was actually preferred to be 90 days based on the model. The increase in formation pressure on abnormal low pressure formation is larger, and the production can be significantly improved after shutting in well. The more complex the fracture network is, the more obvious the non-uniform variation in matrix pore pressure during shutting in well. The research is of great significance for the optimal design of a shut-in system for tight reservoirs and the sustainable development of oil and gas resources in China. Full article
(This article belongs to the Special Issue Advances in Integrated Technology of Fracturing and Enhanced Oil Recovery in Tight Reservoirs)
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15 pages, 3870 KiB  
Article
Numerical Investigation of the Effects of Stress Heterogeneity on the Propagation Behaviors of Hydraulic Fractures in a Shale Oil Reservoir
by Shikun Zhang, Zuo Chen, Xiaohui Wang, Xuyang Zhao, Jiaying Lin, Bolong Zhu, Qian Wen and Qi Jing
Sustainability 2023, 15(14), 11209; https://doi.org/10.3390/su151411209 - 18 Jul 2023
Viewed by 824
Abstract
Minimum principal stress is a key factor governing the hydraulic fracturing behaviors in shale oil reservoirs. Due to the existence of stress heterogeneity, the hydraulic fracture growth and footprints can be affected, and the hydraulic fracturing efficacy can be consequently altered. This phenomenon [...] Read more.
Minimum principal stress is a key factor governing the hydraulic fracturing behaviors in shale oil reservoirs. Due to the existence of stress heterogeneity, the hydraulic fracture growth and footprints can be affected, and the hydraulic fracturing efficacy can be consequently altered. This phenomenon is especially common during the development of shale oil reservoirs associated with continental sedimentary facies. This study uses a numerical workflow to analyze the effect of stress heterogeneity on hydraulic fracture growth. The numerical workflow consists of an open-source planar hydraulic fracturing model and a derived coupled flow and geomechanics model, which can address the effect of minimum principal stress heterogeneity on hydraulic fracturing. Two types of stress heterogeneity are considered: stress heterogeneity caused by legacy production in the horizontal direction and stress heterogeneity caused by high-stress interlayers in the vertical direction. Simulation results indicate that stress heterogeneity in the horizontal and vertical directions leads to asymmetric fracture growth horizontally and vertically. The corresponding fracture footprints and widths also become asymmetric accordingly. Thin interlayers cannot fully limit the fracture growth, and the fracture height growth can still penetrate through. When the high-stress interlayers are thick enough, the fracture cannot penetrate through them vertically, while the corresponding fracture growth is no longer highly sensitive to the thickness of the interlayer. Full article
(This article belongs to the Special Issue Advances in Integrated Technology of Fracturing and Enhanced Oil Recovery in Tight Reservoirs)
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21 pages, 11686 KiB  
Article
Productivity Analysis and Evaluation of Fault-Fracture Zones Controlled by Complex Fracture Networks in Tight Reservoirs: A Case Study of Xujiahe Formation
by Jiujie Cai, Haibo Wang and Fengxia Li
Sustainability 2023, 15(12), 9736; https://doi.org/10.3390/su15129736 - 18 Jun 2023
Viewed by 1073
Abstract
The development of tight gas reservoirs presents a significant challenge for sustainable development, as it requires specialized techniques that can have adverse environmental and social impacts. To address these challenges, efficient development technologies, such as multistage hydraulic fracturing, have been adopted to enable [...] Read more.
The development of tight gas reservoirs presents a significant challenge for sustainable development, as it requires specialized techniques that can have adverse environmental and social impacts. To address these challenges, efficient development technologies, such as multistage hydraulic fracturing, have been adopted to enable access to previously inaccessible natural gas resources, increase energy efficiency and security, and minimizing environmental impacts. This paper proposes a novel evaluation method to analyze the post fracturing productivity controlled by complex fault fracture zones in tight reservoirs. In this article, a systematic method to evaluate stimulated reservoir volume (SRV) and fault-fracture zone complexity after stimulation was established, along with the analysis and prediction of productivity through coupled fall-off and well-test analyses. Focusing on the Xujiahe formation in the Tongnanba anticline of northeastern Sichuan Basin, a 3D geological model was developed to analyze planar heterogeneity. The fall-off analytical model, coupled with rock mechanical parameters and fracturing parameters such as injection rates, fracturing fluid viscosity, and the number of clusters within a single stage, was established to investigate the fracture geometric parameters and complexities of each stage. The trilinear flow model was used to solve the well-test analysis model of multi-stage fractured horizontal wells in tight sandstone gas reservoirs, and well-test curves of the heterogeneous tight sandstone gas fracture network model were obtained. The results show that hydraulic fractures connect the natural fractures in fault-fracture zones. An analysis of the relationship between the fracture geometric outcomes of each segment and the net pressure reveals that as the net pressure in the fracture increases, the area ratio of natural fractures to main fractures increases notably, whereas the half length of the main fracture exhibits a decreasing trend. The overall area of natural fractures following stimulation is 7.64 times greater than that of the main fractures and is mainly a result of the extensive development of natural fractures in the target interval. As the opening ratio of natural fractures increases, the length of the main fractures decreases accordingly. Therefore, increasing net pressure within fractures will significantly enhance the complexity of fracturing fractures in shale gas reservoirs. Furthermore, the initial production of Well X1–10, which is largely controlled by fault-fracture zones, and the cumulative gas production after one year, are estimated. The systematic evaluation method in this study proposed a new way to accurately measure fracturing in tight reservoirs, which is a critical and helpful component of sustainable development in the natural gas industry. Full article
(This article belongs to the Special Issue Advances in Integrated Technology of Fracturing and Enhanced Oil Recovery in Tight Reservoirs)
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Review

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23 pages, 8255 KiB  
Review
Review: Microemulsions for the Sustainable Development of EOR
by Haibin Hu, Qun Zhang, Maozhang Tian, Yuan Li, Xu Han and Rui Guo
Sustainability 2024, 16(2), 629; https://doi.org/10.3390/su16020629 - 11 Jan 2024
Cited by 1 | Viewed by 724
Abstract
Global oil and gas resources are declining continuously, and sustainable development has become a common challenge worldwide. In terms of environmental protection and economic benefits, the application of microemulsions for enhanced oil recovery often requires fewer chemical agents, showing distinct advantages. This paper [...] Read more.
Global oil and gas resources are declining continuously, and sustainable development has become a common challenge worldwide. In terms of environmental protection and economic benefits, the application of microemulsions for enhanced oil recovery often requires fewer chemical agents, showing distinct advantages. This paper analyzes the application prospects and trends of middle-phase microemulsions in tertiary oil recovery. The properties of middle-phase microemulsions are introduced, and an overview of the historical development, theoretical framework, influencing factors, and preparation methods of emulsions are provided. From the perspective of oil displacement systems, this paper reviews the selection and characterization methods of emulsions, as well as the interaction mechanisms between emulsions and reservoirs, proposing future research directions. The focus of the paper is on the evaluation and characterization of emulsions, the mechanisms of micro-oil displacement, and the application of advanced CT scanning technology, which gives a new understanding of wettability changes, capillary forces, and miscible solubilization processes, contributing to the reduction in displacement costs and the improvement of economic benefits. In conclusion, the middle-phase microemulsion flooding technique can significantly enhance oil recovery through the comprehensive action of various mechanisms and has been widely used in oil field development. Full article
(This article belongs to the Special Issue Advances in Integrated Technology of Fracturing and Enhanced Oil Recovery in Tight Reservoirs)
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