Exploitation and Underground Storage of Oil and Gas

Topic Information

Dear Colleagues,

As one of the most important fuels in modern society, oil and gas exploitation has been a research focus for a long period. Meanwhile, amidst the escalating global energy demand and accelerating energy transition, underground resource storage, including natural gas, carbon dioxide (CO₂), hydrogen (H₂), oil, etc., has attracted much attention in recent years. This Topic aims to converge the forefront scientific achievements in this research field and delve into novel theories, technologies, materials, processes, and equipment for oil and gas exploration, development, and underground storage. Sharing case studies and experiences in oil and gas development from deep-sea, deep-earth, and complex geological environments is encouraged, while also emphasizing environmental protection and carbon neutrality pathways throughout the development of storage processes . We eagerly anticipate your submissions and look forward to collectively contributing to the establishment of a safer, cleaner, and more efficient energy system. Topics of interest for publication include, but are not limited to, the following:

• Carbon dioxide fracturing for enhanced permeability and carbon sequestration;
• Multiphase fluid transport with phase change in fractured porous media;
• Heat and mass transport in fractured porous media;
• Mechanism of thermal fluid solidification in rock mass under the influence of fracture networks;
• New advances in experimental modeling methods;
• New advances in numerical modeling and simulation software;
• Artificial intelligence and big data applications;
• Coupled thermal–hydraulic–mechanical–chemical modeling and experiments;
• Hydraulic fracturing and waterless fracturing in unconventional reservoirs.

Prof. Dr. Jianjun Liu
Prof. Dr. Rui Song
Dr. Liuke Huang
Dr. Yao Wang
Dr. Mingyang Wu
Dr. Gang Hui
Topic Editors

Keywords

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	Submit
Energies energies	3.0	6.2	2008	16.8 Days	CHF 2600	Submit
Journal of Marine Science and Engineering jmse	2.7	4.4	2013	16.4 Days	CHF 2600	Submit
Processes processes	2.8	5.1	2013	14.9 Days	CHF 2400	Submit
Resources resources	3.6	7.2	2012	26.1 Days	CHF 1600	Submit
Gases gases	-	-	2021	25.8 Days	CHF 1000	Submit

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Published Papers (18 papers)

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20 pages, 10937 KiB  

Open AccessArticle

Modelling Pressure Dynamic of Oil–Gas Two-Phase Flow in Three-Zone Composite Double-Porosity Media Formation with Permeability Stress Sensitivity

by Guo-Tao Shen and Ren-Shi Nie

Energies 2025, 18(9), 2209; https://doi.org/10.3390/en18092209 (registering DOI) - 26 Apr 2025

Abstract

In view of the flow zoning phenomenon existing in condensate gas reservoirs and the complex pore structure and strong heterogeneity of carbonate rock reservoirs, this study investigates the pressure dynamic behavior during the development process of such gas reservoirs by establishing corresponding models. [...] Read more.

In view of the flow zoning phenomenon existing in condensate gas reservoirs and the complex pore structure and strong heterogeneity of carbonate rock reservoirs, this study investigates the pressure dynamic behavior during the development process of such gas reservoirs by establishing corresponding models. The model divides the reservoir into three zones. The fluid flow patterns and reservoir physical property characteristics in the three regions are different. In particular, the fracture system in zone 1 has permeability stress sensitivity. The model is solved and the sensitivity analysis of the key parameters is carried out. The research results show that reservoir flow can be divided into 12 stages. Stress sensitivity affects all stages except the wellbore storage stage and becomes increasingly obvious over time. The closed boundary causes fracture closure from the lack of external energy, reducing effective flow channels and triggering the boundary response stage earlier. The increased condensate oil increases the flow resistance and pressure loss, and shortens the duration of the flow stage. The research suggests that improving reservoir conditions and enhancing fluid fluidity can reduce pressure loss and increase production capacity, providing valuable theoretical and practical guidance for the development of carbonate rock condensate gas reservoirs. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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16 pages, 11150 KiB  

Open AccessArticle

Study on the Long-Term Influence of Proppant Optimization on the Production of Deep Shale Gas Fractured Horizontal Well

by Siyuan Chen, Shiming Wei, Yan Jin and Yang Xia

Appl. Sci. 2025, 15(5), 2365; https://doi.org/10.3390/app15052365 - 22 Feb 2025

Viewed by 502

Abstract

As shale gas development gradually advances to a deeper level, the economic exploitation of deep shale gas has become one of the key technologies for sustainable development. Large-scale, long-term and effective hydraulic fracturing fracture networks are the core technology for achieving economic exploitation [...] Read more.

As shale gas development gradually advances to a deeper level, the economic exploitation of deep shale gas has become one of the key technologies for sustainable development. Large-scale, long-term and effective hydraulic fracturing fracture networks are the core technology for achieving economic exploitation of deep shale gas. Due to the high-pressure and high-temperature characteristics of deep shale gas reservoirs, traditional seepage models cannot effectively simulate gas flow in such environments. Therefore, this paper constructs a fluid–solid–thermal coupling model, considering the creep characteristics of deep shale, the effects of proppant embedment and deformation on fracture closure, and deeply analyzes the effects of proppant parameters on the shale gas production process. The results show that factors such as proppant concentration, placement, mechanical properties and particle size have a significant effect on fracture width, fracture surface seepage characteristics and final gas production. Specifically, an increase in proppant concentration can expand the fracture width but has limited effect on increasing gas production; uneven proppant placement will significantly reduce the fracture conductivity, resulting in a significant decrease in gas production; proppants with smaller sizes are more suitable for deep shale gas fracturing construction, which not only reduces construction costs but also improves gas seepage capacity. This study provides theoretical guidance for proppant optimization in deep shale gas fracturing construction. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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17 pages, 5583 KiB  

Open AccessArticle

Experimental Investigation of Factors Influencing Spontaneous Imbibition in Shale Reservoirs

by Li Liu, Yi-Min Wang, Ai-Wei Zheng, Ji-Qing Li, Qian Zhang, Ya-Wan Tang, Wen-Xin Yang, Mingjun Chen and Shuqiang Shi

Processes 2025, 13(2), 503; https://doi.org/10.3390/pr13020503 - 11 Feb 2025

Viewed by 611

Abstract

The flowback rate of fracturing fluid in shale reservoirs is often notably low, primarily due to the spontaneous imbibition of the water-based fracturing fluid. Despite their significance, the factors influencing spontaneous imbibition in shale reservoirs remain insufficiently understood. Moreover, whether spontaneous imbibition is [...] Read more.

The flowback rate of fracturing fluid in shale reservoirs is often notably low, primarily due to the spontaneous imbibition of the water-based fracturing fluid. Despite their significance, the factors influencing spontaneous imbibition in shale reservoirs remain insufficiently understood. Moreover, whether spontaneous imbibition is ultimately beneficial or detrimental to shale reservoirs is still a subject of debate. This study investigates the spontaneous imbibition process in shale, the factors (the bedding, contact area, porosity, initial water saturation, and fluid type) affecting it, and its impact on shale porosity and permeability. The results reveal that the spontaneous imbibition process can be categorized into three distinct stages: the rapid imbibition stage, the transitional stage, and the stable stage. It is observed that bedding significantly influences the imbibition rate, and the imbibition rate in the parallel bedding direction is greater than that in the vertical bedding direction. The imbibition capacity increases with larger contact area and higher porosity, while it decreases with higher initial water saturation. Furthermore, the imbibition capacity varies with the type of fluid, following this order: distilled water > 5% KCl solution > kerosene. The maximum imbibed volume per unit pore volume of shale in distilled water is twice that in kerosene. Lastly, spontaneous imbibition is found to enhance the porosity and permeability of shale. After three instances of imbibition, the porosity of the matrix and fractured sample increased by 0.85% and 1.68%, and the permeability increased by 0.636 mD and 0.829 mD, respectively. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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17 pages, 12219 KiB  

Open AccessArticle

Multi-Scale Characterization of Reservoir Space Features in Yueman Area of Fuman Oilfield in Tarim Basin

by Yintao Zhang, Chengyan Lin, Lihua Ren, Chong Sun, Jing Li, Xingyu Zhao and Mingyang Wu

Processes 2025, 13(2), 310; https://doi.org/10.3390/pr13020310 - 23 Jan 2025

Viewed by 517

Abstract

Reservoir space characteristics are the key to reservoir evaluation and the evaluation of reservoir capacity. The reservoir space of fracture-vuggy carbonate reservoirs is complex and diverse, and it develops from micro to macro. There is a lack of systematic study on the reservoir [...] Read more.

Reservoir space characteristics are the key to reservoir evaluation and the evaluation of reservoir capacity. The reservoir space of fracture-vuggy carbonate reservoirs is complex and diverse, and it develops from micro to macro. There is a lack of systematic study on the reservoir space of the Ordovician fracture-vuggy carbonate reservoir. Therefore, taking the Ordovician Yijianfang Formation in Yueman Block of Fuman Oilfield in Tarim Basin as an example, the microscopic reservoir space characteristics of the study area were characterized by rock thin section identification, X-ray diffraction, scanning electron microscopy, high-pressure mercury injection, and low-temperature nitrogen adsorption experiments, and the macroscopic reservoir space characteristics of the study area were characterized by core observation, drilling and logging data, and imaging logging data. The results showed that (1) the lithology of the Ordovician Yijianfang Formation in the Yueman area of Fuman Oilfield is mainly micrite and sparry grain limestone. The mineral composition is mainly calcite, accounting for 97.35%, containing a small amount of quartz and dolomite, accounting for 1.1% and 1.55%, respectively. (2) At the micro level, the reservoir space of Yijianfang Formation in Yueman Block is not developed in primary pores, mainly having developed dissolution pores, structural fractures, and pressure solution fractures, and the pore size is distributed from the nanometer to micron scale. (3) The dissolution caves in the study area are developed at the macro level, mainly including pore-type, cave-type, fracture-pore-type, and fracture-type reservoirs. The research results provide technical support for the accurate evaluation of fractured-vuggy carbonate reservoirs and the improvement of exploration and development effects. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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18 pages, 12789 KiB  

Open AccessArticle

A Study on the Residual Oil Distribution in Tight Reservoirs Based on a 3D Pore Structure Model

by Rujun Wang, Yintao Zhang, Chong Sun, Jing Li, Xiaoyu Meng, Chengqiang Yang and Zhaoyang Chen

Processes 2025, 13(1), 203; https://doi.org/10.3390/pr13010203 - 13 Jan 2025

Viewed by 674

Abstract

A tight reservoir is characterized by low porosity and permeability as well as a complex pore structure, resulting in low oil recovery efficiency. Understanding the micro-scale distribution of residual oil is of great significance for improving oil production and water flooding recovery rates. [...] Read more.

A tight reservoir is characterized by low porosity and permeability as well as a complex pore structure, resulting in low oil recovery efficiency. Understanding the micro-scale distribution of residual oil is of great significance for improving oil production and water flooding recovery rates. In this study, a 3D pore structure model of tight sandstone was established using CT scanning to characterize the residual oil distribution after water flooding. The effects of displacement methods and wettability on residual oil distribution at the micro-scale were then studied and discussed. Moreover, increasing the displacement rate has little effect on the distribution area and dominant seepage channels. Microscopic residual oil is classified into five discontinuous phases according to the oil–water–pore–throat contact relationship. The microscopic residual oil exhibits characteristics of being dispersed overall but locally concentrated. Under water-wet conditions, the injected water tends to strip the oil phase along the pore walls. Under oil-wet conditions, the pore walls have an improved adsorption capacity for the oil phase, resulting in a large amount of porous and membranous residual oil retained in the pores, which leads to a decrease in the overall recovery rate. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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19 pages, 8252 KiB  

Open AccessArticle

Saline–CO₂ Solution Effects on the Mechanical Properties of Sandstones: An Experimental Study

by Motao Duan, Haijun Mao, Guangquan Zhang, Junxin Liu, Sinan Zhu, Di Wang and Hao Xie

Appl. Sci. 2025, 15(2), 607; https://doi.org/10.3390/app15020607 - 10 Jan 2025

Viewed by 727

Abstract

In deep brine oil and gas injection–production operations, the combined long-term effects of brine and carbon dioxide on rock mechanical properties are not clear. In order to solve this problem, the influence of long-term salt–CO₂ environment on the mechanical properties of sandstone [...] Read more.

In deep brine oil and gas injection–production operations, the combined long-term effects of brine and carbon dioxide on rock mechanical properties are not clear. In order to solve this problem, the influence of long-term salt–CO₂ environment on the mechanical properties of sandstone is discussed. The mechanism of interaction evolution and fracture propagation was studied in detail by NMR, the triaxial compression test and a CT scan. The results show that the triaxial compressive strength and mass of sandstone decrease first and then increase with the prolonging of soaking time. The proportion of micropores first decreased and then increased, while the proportion of medium and large pores first increased and then decreased. The pores obtained by Avizo’s segmentation of the threshold value of CT sections first increased and then decreased, and the fractal dimensions obtained first increased and then decreased. In particular, the calcium ions in the immersion solution increased first and then decreased. The reaction rate was obtained and verified according to the changes in calcium carbonate mass and calcium ion mineralization at different times. The failure mode of the sample gradually changed from /-shaped failure to V-shaped composite failure, then to local /-shaped failure, and finally to X-shaped composite failure. On this basis, the process of sandstone was divided into the dissolution stage, precipitation stage and secondary dissolution stage, and the rock microstructure change model under a salt–CO₂ environment was established. The mechanics, temperature, chemical interaction mechanism and fracture propagation mechanism of sandstone under a salt–CO₂ environment are discussed. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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19 pages, 7266 KiB  

Open AccessArticle

Experimental Study on Fracture Propagation in Carbonate Rocks by Acid Fracturing Using the Image-Based 3D Object Reconstruction Technique

by Chenhao Jin, Haijun Mao, Jun Zhou, Yiming Liu, Motao Duan, Zechen Guo and Kaijie Wang

Processes 2025, 13(1), 98; https://doi.org/10.3390/pr13010098 - 3 Jan 2025

Viewed by 731

Abstract

Acid fracturing is an effective method of reservoir stimulation and has been widely used for carbonate reservoir development. However, knowledge on the propagation characteristics of acid-etched fracture is still poor due to the complexities of acidization and stress conditions, as well as the [...] Read more.

Acid fracturing is an effective method of reservoir stimulation and has been widely used for carbonate reservoir development. However, knowledge on the propagation characteristics of acid-etched fracture is still poor due to the complexities of acidization and stress conditions, as well as the limitations of the fracture network reconstruction method, especially when dealing with large specimens. In this paper, a new method based on image-based 3D object reconstruction is proposed to study the fracture networks of specimens after acid fracturing by cutting rock specimens into thin slices, scanning them, and reconstructing 3D fracture networks. This method is more precise than the method of separating specimens into pieces and scanning, and it has advantages over the method of CT X-ray scanning when dealing with large specimens. Using this approach, the effects of natural fractures, stress conditions, and acid systems on the fracture propagation of specimens after true triaxial acid-fracturing tests were investigated. The fracture initiation and propagation patterns of specimens under different conditions were summarized. The results of the study show that the presence of a natural fracture will induce the propagation of fractures, in addition to demonstrating the positive effect of high horizontal stress difference on fracture initiation and provide an acid system conducive to the formation of a fracture network. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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17 pages, 6406 KiB  

Open AccessArticle

Research on the Application Potential of New Nano-Oil Displacement Agents to Improve Shale Oil Recovery Rates

by Haibo He, Jixiang Guo, Bo Wang, Yuzhi Zhang, Fan Lei, Tao Wang, Tiantian Zhang and Jing Wang

Energies 2025, 18(1), 61; https://doi.org/10.3390/en18010061 - 27 Dec 2024

Viewed by 556

Abstract

To meet the demand for enhanced oil recovery in shale reservoirs and to improve the fluidity of shale oil while strengthening its imbibition effect, a multifunctional, thermally stable nanofluid agent, SDP-3, was synthesized using acrylamide (AM) and 2-acrylamido-2-methylpropanesulfonicacid (AMPS) as the primary raw [...] Read more.

To meet the demand for enhanced oil recovery in shale reservoirs and to improve the fluidity of shale oil while strengthening its imbibition effect, a multifunctional, thermally stable nanofluid agent, SDP-3, was synthesized using acrylamide (AM) and 2-acrylamido-2-methylpropanesulfonicacid (AMPS) as the primary raw materials. A series of characterizations and tests were conducted to evaluate its interfacial properties, stability, viscosity reduction performance, wettability, and imbibition-driven oil recovery capabilities. Furthermore, the mechanisms by which SDP-3 enhances the recovery of shale oil were analyzed. The results demonstrated that a mass concentration of 2% SDP-3 could reduce the oil–water interfacial tension to 0.071 mN/m. When the concentration increased to 2.0%, the interfacial tension further decreased to 0.071 mN/m, at which point the viscosity reduction rate for shale oil reached 92.02%, and the imbibition recovery rate was 36.57%. Microscopic observations revealed that SDP-3 could disperse shale oil into fibrous and spherical forms, effectively detaching the adhering shale oil from minute pores. This nanofluid agent not only exhibits excellent compatibility and stability but also achieves an ideal oil recovery effect while significantly improving recovery rates, showcasing its immense application potential in oilfield development. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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15 pages, 6881 KiB  

Open AccessArticle

Experimental Study on the Changes to the Microstructures and Dynamic Mechanical Properties of Layered Sandstone After High-Temperature Treatment

by Shang Gao, Yueyu Wu and Xuqing Yang

Appl. Sci. 2024, 14(24), 11729; https://doi.org/10.3390/app142411729 - 16 Dec 2024

Viewed by 734

Abstract

In this study, changes in the basic physical properties, mineral composition, mass, and microstructure of layered sandstone were evaluated following heat treatment at 200–800 °C. Dynamic impact compression tests were performed using a split-Hopkinson pressure bar test system (SHPB), and digital image correlation [...] Read more.

In this study, changes in the basic physical properties, mineral composition, mass, and microstructure of layered sandstone were evaluated following heat treatment at 200–800 °C. Dynamic impact compression tests were performed using a split-Hopkinson pressure bar test system (SHPB), and digital image correlation (DIC) was used to monitor the dynamic failure processes of the involved specimens. Results indicate that high-temperature treatment reduces the mass, wave velocity and peak stress of layered sandstone; increases the porosity, pore length, and pore aperture. The rates of decrease in the wave velocity and peak stress considerably increase with increasing temperature above a threshold of 400 °C. This is because at temperatures above 400 °C, thermal cracks will form both between and within particles. As the number of cracks increases, they will propagate and connect with each other, forming a network of cracks. DIC results show that as the heat treatment temperature rises, the range of the strain-concentration areas, which are formed by sandstone failures, substantially expands. However, the increase in the heat treatment temperature only negligibly influences the propagation direction of primary sandstone cracks, which mainly propagate along the weak bedding planes. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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11 pages, 8807 KiB  

Open AccessArticle

Experimental Study on Damage Evaluation of Working Fluid Invasion in Tight Sandstone Gas Reservoirs

by Luyao Chen, Feifei Fang, Sijie He, Yong Hu, Jiping Wang, Chunyan Jiao, Jianning Luo, Yuanyuan Zhang and Changmin Guo

Processes 2024, 12(12), 2857; https://doi.org/10.3390/pr12122857 - 13 Dec 2024

Viewed by 675

Abstract

The scientific evaluation of the damage caused by working fluid invasion in tight sandstone gas reservoirs is critical for optimizing drilling design, fracturing fluid systems, and construction design. This study focused on the tight sandstone core of the Qingshimao gas field in the [...] Read more.

The scientific evaluation of the damage caused by working fluid invasion in tight sandstone gas reservoirs is critical for optimizing drilling design, fracturing fluid systems, and construction design. This study focused on the tight sandstone core of the Qingshimao gas field in the Ordos Basin. A set of experimental methods and equipment were designed to facilitate the visual monitoring and quantitative evaluation of the reservoir damage caused by working fluids. Systematic evaluation experiments were conducted to analyze the extent of reservoir damage caused by working fluid invasion under varying pore pressure and permeability conditions. The results show the following: (1) As permeability increases, the real-time invasion flow rate rises, and the invasion rate accelerates. Meanwhile, as pore pressure increases, the real-time invasion flow rate decreases, and the invasion rate slows down. (2) The core’s fluid saturation after working fluid invasion exceeds 70%, with permeability damage reaching 95% or higher. (3) At the same reservoir pore pressure, cores with permeability ranges between 0.1 × 10⁻³ μm² and 1 × 10⁻³ μm² exhibit higher fluid-phase saturation and greater invasion damage. For cores with similar permeability, the higher the pore pressure, the higher the invasion-phase saturation, and the greater the extent of invasion damage. The research results provide certain guiding significance for evaluating the extent of the damage caused by working fluid invasion in tight sandstone gas reservoirs and achieving efficient gas reservoir development. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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12 pages, 2102 KiB  

Open AccessArticle

Research on Nanoparticle-Enhanced Cooling Technology for Oil-Based Drilling Fluids

by Xudong Wang, Pengcheng Wu, Ye Chen, Ergang Zhang, Xiaoke Ye, Qi Huang, Ruolan Wang, Gui Wang and Gang Xie

Appl. Sci. 2024, 14(23), 10969; https://doi.org/10.3390/app142310969 - 26 Nov 2024

Cited by 1 | Viewed by 733

Abstract

Drilling fluids are critical in oil and gas well drilling, particularly deep shale gas drilling. In recent years, applying nanoparticles as additives in drilling fluids has received widespread attention to address the various challenges associated with deep shale gas drilling. This study focused [...] Read more.

Drilling fluids are critical in oil and gas well drilling, particularly deep shale gas drilling. In recent years, applying nanoparticles as additives in drilling fluids has received widespread attention to address the various challenges associated with deep shale gas drilling. This study focused on the performance of three nanoparticle-enhanced oil-based drilling fluids (OBDFs), carbon nanotubes (CNTs), silicon dioxide (SiO₂), and aluminums oxide (Al₂O₃) in terms of improving thermal capacity and cooling efficiency. The potential of the nanoparticles to improve the thermal management capability of the drilling fluids was evaluated by measuring specific heat capacity and thermal conductivity. The results showed that CNTs exhibited the most significant improvement, with thermal conductivity increasing by 7.97% and specific heat capacity by 19.38%. The rheological properties and high temperature and high pressure (HTHP) filtration performance of the nanoparticle-enhanced OBDFs were evaluated, demonstrating that CNTs and SiO₂ significantly improved the rheological stability of the drilling fluids and reduced the filtration loss under high temperature conditions. When 3% CNTs were added, the HTHP filtration loss was reduced by 42.86%, exhibiting excellent sealing properties. The cooling effect of different nanoparticles was evaluated by calculating their effects on the bottomhole temperature. The results showed that CNTs performed the best in lowering the bottomhole temperature by 4.53 °C, followed by SiO₂ by 1.47 °C and Al₂O₃ by only 0.88 °C. The results showed that CNTs were the most effective in lowering the bottomhole temperature. These results indicated that nanoparticles as additives to drilling fluids could significantly increase the thermal capacity and cooling efficiency of OBDFs, making them effective additives for high-temperature deep shale gas drilling applications. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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16 pages, 6534 KiB  

Open AccessArticle

Experimental Study on Miscible Phase and Imbibition Displacement of Crude Oil Injected with CO₂ in Shale Oil Reservoir

by Haibo He, Xinfang Ma, Bo Wang, Yuzhi Zhang, Jianye Mou and Jiarui Wu

Appl. Sci. 2024, 14(22), 10474; https://doi.org/10.3390/app142210474 - 14 Nov 2024

Viewed by 816

Abstract

Jimsar shale oil in China has undergone a rapid decline in formation energy and has a low recovery rate, with poor reservoir permeability. CO₂ injection has become the main method for improving oil recovery. Pre-fracturing with CO₂ energy storage in Jimsar [...] Read more.

Jimsar shale oil in China has undergone a rapid decline in formation energy and has a low recovery rate, with poor reservoir permeability. CO₂ injection has become the main method for improving oil recovery. Pre-fracturing with CO₂ energy storage in Jimsar shale oil has been performed, yielding a noticeable increase in oil recovery. However, the CO₂ injection mechanism still requires a deeper understanding. Focusing on Jimsar shale oil in China, this paper studies the effect of CO₂ on crude oil viscosity reduction, miscible phase testing, and the law of imbibition displacement. The results show that CO₂ has a significant viscosity reduction effect on Jimsar shale oil, with a minimum miscible pressure between CO₂ and Jimsar shale oil of 25.51 MPa, which can allow for miscibility under formation conditions. A rise in pressure increased the displacement capacity of supercritical CO₂, as well as the displacement volume of crude oil. However, the rate of increase gradually declined. This research provides a theoretical basis for CO₂ injection fracturing in Jimsar shale oil, which is helpful for improving the development effects of Jimsar shale oil. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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19 pages, 6834 KiB  

Open AccessArticle

Experimental Study on the Efficiency of Fracturing Integrated with Flooding by Slickwater in Tight Sandstone Reservoirs

by Pingtian Fan, Yuetian Liu, Ziyu Lin, Haojing Guo and Ping Li

Processes 2024, 12(11), 2529; https://doi.org/10.3390/pr12112529 - 13 Nov 2024

Viewed by 809

Abstract

Tight reservoirs, with their nanoscale pore structures and limited permeability, present significant challenges for oil recovery. Composite fracturing fluids that combine both fracturing and oil recovery capabilities show great potential to address these challenges. This study investigates the performance of a slickwater-based fracturing [...] Read more.

Tight reservoirs, with their nanoscale pore structures and limited permeability, present significant challenges for oil recovery. Composite fracturing fluids that combine both fracturing and oil recovery capabilities show great potential to address these challenges. This study investigates the performance of a slickwater-based fracturing fluid, combined with a high-efficiency biological oil displacement agent (HE-BIO), which offers both production enhancement and environmental compatibility. Key experiments included tests on single-phase flow, core damage assessments, interfacial tension measurements, and oil recovery evaluations. The results showed that (1) the slickwater fracturing fluid effectively penetrates the rock matrix, enhancing oil recovery while minimizing environmental impact; (2) it causes substantially less damage to the reservoir compared to traditional guar gum fracturing fluid, especially in cores with little higher initial permeability; and that (3) oil recovery improves as HE-BIO concentration increases from 0.5% to 2.5%, with 2.0% as the optimal concentration for maximizing recovery rates. These findings provide a foundation for optimizing fracturing oil displacement fluids in tight sandstone reservoirs, highlighting the potential of the integrated fracturing fluid to enhance sustainable oil recovery. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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15 pages, 3856 KiB  

Open AccessArticle

A Prediction Method for Calculating Fracturing Initiation Pressure Considering the Modification of Rock Mechanical Parameters After CO₂ Treatment

by Cuilong Kong, Yuxue Sun, Hao Bian, Jianguang Wei, Guo Li, Ying Yang, Chao Tang, Xu Wei, Ziyuan Cong and Anqi Shen

Processes 2024, 12(11), 2525; https://doi.org/10.3390/pr12112525 - 13 Nov 2024

Viewed by 682

Abstract

The establishment of a more realistic CO₂ fracturing model serves to elucidate the intricate mechanisms underlying CO₂ fracturing transformation. Additionally, it furnishes a foundational framework for devising comprehensive fracturing construction plans. However, current research has neglected to consider the influence of [...] Read more.

The establishment of a more realistic CO₂ fracturing model serves to elucidate the intricate mechanisms underlying CO₂ fracturing transformation. Additionally, it furnishes a foundational framework for devising comprehensive fracturing construction plans. However, current research has neglected to consider the influence of CO₂ on rock properties during CO₂ fracturing, resulting in an inability to precisely replicate the alterations in the reservoir post-CO₂ injection into the formation. This disparity from the actual conditions poses a substantial limitation to the application and advancement of CO₂ fracturing technology. This work integrates variations in the physical parameters of rocks after complete contact and reaction with CO₂ into the numerical model of crack propagation. This comprehensive approach fully acknowledges the impact of pre-CO₂ exposure on the mechanical parameters of reservoir rocks. Consequently, it authentically restores the reservoir state following CO₂ injection, ensuring a more accurate representation of the post-fracturing conditions. In comparison with conventional numerical simulation methods, the approach outlined in this paper yields a reduction in the error associated with predicting fracturing pressure by 9.8%. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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18 pages, 3400 KiB  

Open AccessArticle

Seepage–Diffusion Mechanism of Gas Kick Considering the Filtration Loss of Oil-Based Muds During Deepwater Drilling

by Yanli Guo, Weiqi Liu, Chaojie Song, Qingtao Gong and Yao Teng

J. Mar. Sci. Eng. 2024, 12(11), 2035; https://doi.org/10.3390/jmse12112035 - 10 Nov 2024

Cited by 1 | Viewed by 1100

Abstract

As oil and gas exploration gradually advances into deep waters, the combined effects of various types of gas kick and the accurate calculation of the gas-kick volume have gained increasing attention. This study focused on gas kicks from permeable gas-bearing formations, considering the [...] Read more.

As oil and gas exploration gradually advances into deep waters, the combined effects of various types of gas kick and the accurate calculation of the gas-kick volume have gained increasing attention. This study focused on gas kicks from permeable gas-bearing formations, considering the mass transfer of gas in the filtration region of the drilling fluids and revealed the mechanisms of seepage-driven and diffusion-driven gas kicks. Based on seepage mechanics and diffusion theory, a comprehensive model for calculating gas-kick volume was established, considering the synergistic effect of gas-concentration-diffusion and negative-differential-pressure, as well as mass transfer in both the filtrate zone and the filter-cake zone. The new model showed high calculation accuracy. The sensitivity analysis showed that both the seepage-driven and diffusion-driven gas-kick volumes in the wellbore increased with increasing formation porosity and open-hole length, while the thickness of the filter cake had a strong inhibitory effect on both. Additionally, a “seepage–diffusion ratio” was introduced to reveal the gas-kick evolution pattern under a seepage–diffusion mechanism. Under specific case conditions, when the seepage–diffusion ratio was less than approximately 1%, diffusion-driven gas kick contributed more than seepage-driven gas kick; when the seepage–diffusion ratio exceeded 1%, seepage-driven gas kick contributed more than diffusion-driven gas kick. The research can provide crucial parameters for wellbore multiphase flow calculation and wellbore pressure prediction. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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17 pages, 4939 KiB  

Open AccessArticle

Experimental and Numerical Study on Nonlinear Shear Behavior and Constitutive Model of Deep Shale Laminae Planes

by Renyan Zhuo, Xinfang Ma, Jianmin Li, Shicheng Zhang and Junxiu Ma

Processes 2024, 12(11), 2445; https://doi.org/10.3390/pr12112445 - 5 Nov 2024

Viewed by 887

Abstract

The direct shear tests showed that the degradation of unevenness and waviness of the laminae plane is the primary reason for the dynamic decrease in shear strength. A shear constitutive model was proposed which considers the scale effect and the asperity geometry of [...] Read more.

The direct shear tests showed that the degradation of unevenness and waviness of the laminae plane is the primary reason for the dynamic decrease in shear strength. A shear constitutive model was proposed which considers the scale effect and the asperity geometry of the unevenness and waviness of the laminar plane. The evolution of the shear strength and stiffness with a normal stress and scale effect during the shearing of shale laminae planes was explored. The results show that high normal stress aggravates the stiffness hardening of laminae planes and forms larger peak shear stress and peak shear displacement. At the lab scale, the increase in the unevenness wavelength has a hardening effect on the shear stiffness and strength. The small-scale unevenness contributes most to the shear strength of shale laminae planes at the lab scale. At the field scale, the increase in the waviness wavelength has a softening effect on the shear stiffness and strength. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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24 pages, 10284 KiB  

Open AccessArticle

Deep-Learning-Based Amplitude Variation with Angle Inversion with Multi-Input Neural Networks

by Shiping Tao, Yintong Guo, Haoyong Huang, Junfeng Li, Liqing Chen, Junchuan Gui and Guokai Zhao

Processes 2024, 12(10), 2259; https://doi.org/10.3390/pr12102259 - 16 Oct 2024

Cited by 2 | Viewed by 1182

Abstract

Deep-learning-based (DL-based) seismic inversion has emerged as one of the state-of-the-art research areas in exploration geophysics with the development of artificial intelligence technology. Due to its good portability and high computational efficiency, this method has emerged as a data-driven approach for estimating subsurface [...] Read more.

Deep-learning-based (DL-based) seismic inversion has emerged as one of the state-of-the-art research areas in exploration geophysics with the development of artificial intelligence technology. Due to its good portability and high computational efficiency, this method has emerged as a data-driven approach for estimating subsurface properties. However, most of the current DL-based methods rely solely on seismic data, lacking the incorporation of prior information. In addition, these methods are usually performed trace-by-trace, resulting in insufficient horizontal constraints. These limitations make traditional methods less robust, particularly when dealing with high noise levels or limited data. To address these challenges, we propose a multi-input deep learning network for pre-stack inversion, which combines data-driven and model-driven approaches for optimization. The proposed method separately extracts features from the model and data, merging them to improve feature utilization. Moreover, by adopting a 2-D training unit, rather than a trace-by-trace approach, the method improves the horizontal continuity of the results. Tests on synthetic and real seismic data confirmed the robustness and improved stability of the proposed method, even under challenging conditions. This dual-driven approach significantly enhances the reliability of seismic inversion. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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13 pages, 13631 KiB  

Open AccessArticle

Sensitivity Analysis of Depth-Controlled Oriented Perforation in Horizontal Wells Based on the 3D Lattice Method

by Haining Zhang, Yanhong Gou, Daojie Cheng, Fengsheng Zhang, Xunan Jia, Rui Gao and Yuwei Li

Processes 2024, 12(10), 2192; https://doi.org/10.3390/pr12102192 - 9 Oct 2024

Viewed by 937

Abstract

The main method used to exploit unconventional oil and gas reservoirs involves multi-cluster perforation combined with hydraulic fracturing in horizontal wells. However, as the use of this technology has expanded, challenges like reduced perforation efficiency and elevated fracture initiation pressure have surfaced. The [...] Read more.

The main method used to exploit unconventional oil and gas reservoirs involves multi-cluster perforation combined with hydraulic fracturing in horizontal wells. However, as the use of this technology has expanded, challenges like reduced perforation efficiency and elevated fracture initiation pressure have surfaced. The depth-controlled oriented perforation technique helps achieve uniform fracture initiation, enhance efficiency, and lower initiation pressure. In this study, a hydraulic fracturing fluid–solid coupling model at the perforation scale was established using the 3D lattice method to compare the near-wellbore fracture morphologies of depth-controlled oriented perforation, spiral perforation, and oriented perforation. Additionally, this study analyzes the effects of injection rate, reservoir elastic modulus, and horizontal stress difference on the fracture morphology and initiation pressure of depth-controlled oriented perforation. This study clarifies the applicability of depth-controlled oriented perforation in different types of reservoirs for the first time. The results indicate that intermediate fractures between spiral and oriented perforations are hindered, while depth-controlled oriented perforation ensures uniform fracture initiation. In the injection rate range of 0.144 to 0.360 L/min, an increase in injection rate accelerates the rise of fluid pressure within the perforations, leading to an increase in fracture initiation pressure. Therefore, excessively high injection rates are unfavorable for fracture initiation. Through depth-controlled oriented perforation, long and singular fractures can be formed in reservoirs with significant horizontal stress differences and high elastic moduli. Full article

(This article belongs to the Topic Exploitation and Underground Storage of Oil and Gas)

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