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Application and Optimization of CCUS Technology in Shale Gas Production and Storage

A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: closed (15 April 2025) | Viewed by 9819

Special Issue Editors

Dr. Jun Liu

E-Mail Website
Guest Editor
Institute of New Energy and Low-Carbon Technology, Sichuan University, Chengdu 610065, China
Interests: CO2-enhanced shale gas extraction and geological storage (CCUS); the interaction and dynamic geological effects of gas–water multiphase media (microscopic) in shale reservoir; heterogeneous distribution of shale gas reservoir characteristics and geological control mechanism
Special Issues, Collections and Topics in MDPI journals
Dr. Gan Feng

E-Mail Website
Guest Editor
Key Laboratory of Deep Underground Science and Engineering, Ministry of Education, Sichuan University, Chengdu 610065, China
Interests: deep rock mechanics and engineering; water jet theory and new technology of geothermal exploitation and application; unconventional green energy extraction; mining engineering
Special Issues, Collections and Topics in MDPI journals
Dr. Peng Zhao

E-Mail Website
Guest Editor
State Key Laboratory of Geohazard Prevention and Geoenvironment Protection, Chengdu University of Technology, Chengdu 610059, China
Interests: deep rock mechanics; deep unconventional energy mining; dynamic response of disaster environment protection structure

Special Issue Information

Dear Colleagues,

Worldwide climate change enables a major challenge to the current situation of energy consumption and, accordingly, much attention has been drawn to the development of comprehensive technology as a way of enhancing the energy supply and simultaneously reducing carbon emissions. In this context, in recent years, a technique known as CCUS in shale gas production and storage raised increasing concerns because it usually promotes synthetic rewards, namely, acquiring energy from geological formation and trapping CO2 in underground strata. Basically, the shale gas reservoir has been widely accepted and recognized to be a suitable geological target to deploy CCUG technology; however, it is not mature enough to experience large-scale field promotion and implementation. As a result, shale-based CCUS is the focus of considerable scientific investigations, and these drive the organization of this Special Issue. Herein, this Special Issue welcomes all achievements regarding CCUS technology related to shale gas, including all outlines from laboratory experiments, numerical simulations, engineering evaluations, economic judgements, etc.

Dr. Jun Liu
Dr. Gan Feng
Dr. Peng Zhao
Guest Editors

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Published Papers (8 papers)

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Editorial

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3 pages, 190 KiB  
Editorial
Application and Optimization of CCUS Technology in Shale Gas Production and Storage
by Jun Liu, Gan Feng and Peng Zhao
Energies 2023, 16(14), 5483; https://doi.org/10.3390/en16145483 - 19 Jul 2023
Cited by 2 | Viewed by 1313
Abstract
Global climate change is a crucial issue confronting the international community [...] Full article
(This article belongs to the Special Issue Application and Optimization of CCUS Technology in Shale Gas Production and Storage)

Research

Jump to: Editorial

26 pages, 8826 KiB  
Article
Research on the Mechanism and Prediction Model of Pressure Drive Recovery in Low-Permeability Oil Reservoirs
by Haicheng Liu and Binshan Ju
Energies 2024, 17(21), 5253; https://doi.org/10.3390/en17215253 - 22 Oct 2024
Viewed by 771
Abstract
China boasts significant reserves of low-permeability oil reservoirs, and the economic and efficient development of these reservoirs plays a crucial role in enhancing oil and gas production. However, the “difficult injection and difficult recovery” issue in low-permeability oil reservoirs is a major challenge. [...] Read more.
China boasts significant reserves of low-permeability oil reservoirs, and the economic and efficient development of these reservoirs plays a crucial role in enhancing oil and gas production. However, the “difficult injection and difficult recovery” issue in low-permeability oil reservoirs is a major challenge. To address this, research is conducted on the mechanism of pressure drive based on the mathematical model of oil-water seepage in low-permeability reservoirs and the model of fracture permeability. The study finds that pressure drive technology, by directly delivering the pressure drive agent deep into the low-permeability reservoir, effectively prevents viscosity loss and adhesion retention of the agent in the near-wellbore area. This technology expands the swept volume, improves oil washing efficiency, replenishes formation energy, and facilitates the gathering and production of scattered remaining oil. For reservoirs with higher permeability, pressure drive yields quick results, and high-pressure water injection can be directly adopted for pressure drive to reduce costs. On the other hand, reservoirs with lower permeability have difficulty in water absorption, and the use of surfactant-based pressure drive can effectively reduce the seepage resistance of the reservoir, enhancing its water absorption capacity and improving development outcomes. Based on the mechanism of pressure drive development, further research is conducted on the production characteristics of pressure drive mines. Addressing the variability in pressure drive effects, big data analysis tools such as SHAP analysis and correlation analysis are employed to evaluate the main controlling factors of pressure drive in both new and old areas. Additionally, non-time series and time series pressure drive production forecasting models are established based on pressure drive data. Full article
(This article belongs to the Special Issue Application and Optimization of CCUS Technology in Shale Gas Production and Storage)
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19 pages, 4624 KiB  
Article
Investigation of the Pore Characteristics and Capillary Forces in Shale before and after Reaction with Supercritical CO2 and Slickwater
by Chi Zhang, Qian Li, Yanlin Liu, Jiren Tang, Yunzhong Jia and Tianyi Gong
Energies 2024, 17(16), 3870; https://doi.org/10.3390/en17163870 - 6 Aug 2024
Viewed by 1236
Abstract
CO2–slickwater hybrid fracturing technology is an essential part of shale gas recovery and CO2 geo-storage. However, the exposure to supercritical CO2 (ScCO2) and slickwater can result in potential changes of the pore structures and surface wetting behavior, [...] Read more.
CO2–slickwater hybrid fracturing technology is an essential part of shale gas recovery and CO2 geo-storage. However, the exposure to supercritical CO2 (ScCO2) and slickwater can result in potential changes of the pore structures and surface wetting behavior, which affect the gas transportation and CO2 sequestration security in shale reservoirs. Therefore, in this paper, X-ray diffraction (XRD), low-pressure nitrogen gas adsorption (N2GA), mercury intrusion porosimetry (MIP), and fractal analysis were used to describe the pore characteristics of shale before and after ScCO2–slickwater coupling treatments. Shale’s surface wettability was confirmed by contact angle measurements. After the ScCO2–slickwater treatments, the number of micropores (<3.5 nm) and mesopores (3.5–50 nm) increased, while that of macropores (>50 nm) declined based on the N2GA and MIP experiments. Combined with fractal analysis, we argue that the pore connectivity diminished and the pore structure became more complicated. By analyzing the results of XRD, shale pore changes occurring after the ScCO2–slickwater treatment can be explained by the adsorption of polyacrylamide (PAM). Contact angle measurement results showed that the shale’s surface treated by ScCO2 and slickwater was more hydrophilic than that treated by ScCO2 and water, and indirectly prove our argument above. Hence, the coupling using effect of ScCO2 and slickwater can impair the negative effect of CO2 on the shale capillary force to improve shale gas productivity, but it can negatively affect the security of CO2 sequestration in shale reservoirs. Full article
(This article belongs to the Special Issue Application and Optimization of CCUS Technology in Shale Gas Production and Storage)
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17 pages, 22872 KiB  
Article
Insights into the Co-Exploration Potential of Gas in the Shale and Tight Sandstone of the Lower Silurian Formation in the Gongtan Syncline Area in Southeastern Sichuan Basin, SW China
by Shengxiu Wang, Ye Zhang, Wei Wang, Yang Yang, Qiaoli Wang, Chuan Yu, Difei Zhao, Chunlin Zeng and Yao Xu
Energies 2024, 17(15), 3735; https://doi.org/10.3390/en17153735 - 29 Jul 2024
Viewed by 970
Abstract
This work aims to explore the Lower Silurian shale gas and tight sandstone gas accumulation conditions in the Gongtan Syncline, southeastern Sichuan Basin. The sedimentary environment, organic geochemical characteristics, reservoir characteristics, gas content, and preservation conditions of the reservoir were comprehensively analyzed. The [...] Read more.
This work aims to explore the Lower Silurian shale gas and tight sandstone gas accumulation conditions in the Gongtan Syncline, southeastern Sichuan Basin. The sedimentary environment, organic geochemical characteristics, reservoir characteristics, gas content, and preservation conditions of the reservoir were comprehensively analyzed. The results show that the Wufeng–Longmaxi Formation shale formed in a deep-water shelf characterized by a large thickness (50–70 m), appropriate total organic carbon content (0.5–5.47%), high maturity (2.38%), high brittle mineral content (67.10%), and large gas content (0.71–1.64 m3/t), and the formations show the good resource potential of the shale gas. The Xintan Formation formed in a lower shore phase, and the tight sandstone is locally developed with a small thickness. The Xiaoheba Formation formed in an upper-middle shore phase, and the tight sandstone is stably distributed with large thicknesses. The porosity and permeability of the two sets of sandstone are small and some natural fractures are developed in the sandstone, but the fracture filling degree is higher. The results of well logging show that there are abnormally high values of total hydrocarbon in both the Xintan Formation and Xiaoheba Formation; this indicates that tight sandstone gas is developed in the Lower Silurian strata. A comprehensive study indicates that the Lower Silurian of the Gongtan Syncline has the geological conditions for the formation of shale gas and tight sandstone gas, which are the “Two gases” with good co-exploration prospects. Full article
(This article belongs to the Special Issue Application and Optimization of CCUS Technology in Shale Gas Production and Storage)
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14 pages, 4181 KiB  
Article
Comparison of the Sample Preparation Strategies and Impacts on the Tensile Strength of Gas Shale with Variable Moisture Conditions
by Liuqing Shu, Lingzhi Xie, Bo He and Yao Zhang
Energies 2024, 17(10), 2327; https://doi.org/10.3390/en17102327 - 11 May 2024
Viewed by 1069
Abstract
Moisture significantly affects the mechanical behavior of gas shale and further determines the hydraulic fracturing performance, as it is more attractive. Nevertheless, batch experiments have usually involved variable methodologies regarding the preparation of moisture-contained shale specimens in the sequence (and/or frequency) of drying [...] Read more.
Moisture significantly affects the mechanical behavior of gas shale and further determines the hydraulic fracturing performance, as it is more attractive. Nevertheless, batch experiments have usually involved variable methodologies regarding the preparation of moisture-contained shale specimens in the sequence (and/or frequency) of drying and soaking treatments. Accordingly, this work investigates how the preparation methodology influences the test results of moisture-contained shale samples. This study compares three commonly used shale sample preparation strategies for acquiring different moisture contents, that is, “dry-wet”, “dry-wet-dry”, and “wet-dry-wet” strategies, followed by a Brazilian splitting test for the mechanical parameters. The results show that under the same saturation conditions, the longer the soaking time during sample preparation, the higher the degradation degree of shale tensile strength. Meanwhile, prolonged soaking can lead to a more discrete distribution of strength values, and the failure mode may deviate from the Brazilian splitting theory model. Under the combined influence of moisture content and soaking time, the tensile strength of shale decreases approximately linearly with increasing saturation, while the degradation degree increases nonlinearly with increasing saturation, and the degradation rate changes from slow to fast. According to the observation of the microstructure of hydrated shale, prolonged soaking can lead to an increase in the expansion of clay minerals in shale by hydration, resulting in looser and more fragmented internal structure, and further degradation in shale strength. In order to weaken the interference of hydration when studying the effect of moisture content on the tensile strength of shale, the soaking time should be minimized as much as possible during the preparation process. Full article
(This article belongs to the Special Issue Application and Optimization of CCUS Technology in Shale Gas Production and Storage)
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23 pages, 8671 KiB  
Article
Characterization of the Macroscopic Impact of Diverse Microscale Transport Mechanisms of Gas in Micro-Nano Pores and Fractures
by Yintao Dong, Laiming Song, Fengpeng Lai, Qianhui Zhao, Chuan Lu, Guanzhong Chen, Qinwan Chong, Shuo Yang and Junjie Wang
Energies 2024, 17(5), 1145; https://doi.org/10.3390/en17051145 - 28 Feb 2024
Cited by 1 | Viewed by 1060
Abstract
The objective of this study is to construct a refined microscopic transport model that elucidates the transport mechanisms of gas flow within micro-nano pores and fractures. The collective impact of various microscopic transport mechanisms was explained through the apparent permeability model, specifically related [...] Read more.
The objective of this study is to construct a refined microscopic transport model that elucidates the transport mechanisms of gas flow within micro-nano pores and fractures. The collective impact of various microscopic transport mechanisms was explained through the apparent permeability model, specifically related to gases such as methane and carbon dioxide, within the shale matrix. The apparent permeability models, taking into account microscopic transport mechanisms such as slippage flow, Knudsen diffusion, transition flow, and surface diffusion, were established individually. Subsequently, the influencing factors on apparent permeability were analyzed. The results demonstrate that the apparent permeability of the shale reservoir matrix is significantly influenced by pore pressure, temperature, pore size, and total organic carbon (TOC). As pressure decreases, the apparent permeability of Knudsen diffusion and surface diffusion increases, while the apparent permeability of slippage flow decreases. In addition, the apparent permeability of the reservoir matrix initially decreases and then increases. With increasing temperature, the apparent permeability of slippage flow, Knudsen diffusion, and surface diffusion all increase, as does the apparent permeability of the reservoir matrix. As pore size increases, the apparent permeability of surface diffusion and Knudsen diffusion decreases, while the apparent permeability of slippage flow and the reservoir matrix increases. Furthermore, an increase in TOC leads to no change in the apparent permeability of slippage flow and Knudsen diffusion, but an increase in the apparent permeability of surface diffusion and the reservoir matrix. The model presented in this paper enhances the multi-scale characterization of gas microflow mechanisms in shale and establishes the macroscopic application of these micro-mechanisms. Moreover, this study provides a theoretical foundation for the implementation of carbon capture, utilization, and storage (CCUS) in shale gas production. Full article
(This article belongs to the Special Issue Application and Optimization of CCUS Technology in Shale Gas Production and Storage)
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19 pages, 6736 KiB  
Article
Numerical Simulation of the Simultaneous Development of Multiple Fractures in Horizontal Wells Based on the Extended Finite Element Method
by Enshun Ping, Peng Zhao, Haiyan Zhu, Yuzhong Wang, Zixi Jiao, Qingjie Zhao and Gan Feng
Energies 2024, 17(5), 1057; https://doi.org/10.3390/en17051057 - 23 Feb 2024
Cited by 3 | Viewed by 1135
Abstract
Simultaneous multiple-fracture treatments in horizontal wellbores have become an essential technology for the economic development of shale gas reservoirs. During hydraulic fracturing, fracture initiation and propagation always induce additional stresses on the surrounding rock. When multiple fractures develop simultaneously, the development of some [...] Read more.
Simultaneous multiple-fracture treatments in horizontal wellbores have become an essential technology for the economic development of shale gas reservoirs. During hydraulic fracturing, fracture initiation and propagation always induce additional stresses on the surrounding rock. When multiple fractures develop simultaneously, the development of some fractures is limited due to the stress-shadow effect. An in-depth understanding of the multiple-fracture propagation mechanism as reflected by fracture morphology and flow rate distribution can help to set reasonable operation parameters for improving the uniformity of multiple fractures and forming a complex fracture network according to the different in situ stress conditions in a reservoir to increase the shale gas recovery and reduce the cost. In this study, a two-dimensional (2D) fracture propagation model was developed based on the extended finite element method (XFEM). Then, the influences of various factors, including geological and operational factors, on the development of multiple fractures were studied. The results of numerical simulations showed that increasing the cluster spacing or injecting fracturing fluid with lower viscosity can help reduce the stress-shadow effect. In the case of smaller in situ stress differences, the deflection of the fractures was larger due to the stress-shadow effect. As the stress difference increased, the direction of the propagation of the fracture was gradually biased towards the direction of maximum horizontal stress. In addition, the injection rate had some effects on the fracture morphology and flow rate distribution. However, as the injection rate increased, the dominant fracture developed rapidly, and the fracture length significantly increased. Full article
(This article belongs to the Special Issue Application and Optimization of CCUS Technology in Shale Gas Production and Storage)
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21 pages, 5491 KiB  
Article
Multi-Fracture Propagation Considering Perforation Erosion with Respect to Multi-Stage Fracturing in Shale Reservoirs
by Lin Tan, Lingzhi Xie, Bo He and Yao Zhang
Energies 2024, 17(4), 828; https://doi.org/10.3390/en17040828 - 9 Feb 2024
Cited by 2 | Viewed by 1218
Abstract
Shale gas is considered a crucial global energy source. Hydraulic fracturing with multiple fractures in horizontal wells has been a crucial method for stimulating shale gas. During multi-stage fracturing, the fracture propagation is non-uniform, and fractures cannot be induced in some clusters due [...] Read more.
Shale gas is considered a crucial global energy source. Hydraulic fracturing with multiple fractures in horizontal wells has been a crucial method for stimulating shale gas. During multi-stage fracturing, the fracture propagation is non-uniform, and fractures cannot be induced in some clusters due to the influence of stress shadow. To improve the multi-fracture propagation performance, technologies such as limited-entry fracturing are employed. However, perforation erosion limits the effect of the application of these technologies. In this paper, a two-dimensional numerical model that considers perforation erosion is established based on the finite element method. Then, the multi-fracture propagation, taking into account the impact of perforation erosion, is studied under different parameters. The results suggest that perforation erosion leads to a reduction in the perforation friction and exacerbates the uneven propagation of the fractures. The effects of erosion on multi-fracture propagation are heightened with a small perforation diameter and perforation number. However, reducing the perforation number and perforation diameter remains an effective method for promoting uniform fracture propagation. As the cluster spacing is increased, the effects of erosion on multi-fracture propagation are aggravated because of the weakened stress shadow effect. Furthermore, for a given volume of fracturing fluid, although a higher injection rate is associated with a shorter injection time, the effects of erosion on the multi-fracture propagation are more severe at a high injection rate. Full article
(This article belongs to the Special Issue Application and Optimization of CCUS Technology in Shale Gas Production and Storage)
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