Processes

Research

Jump to: Review

15 pages, 5147 KiB

Open AccessArticle

Effect of Microfractures on Counter-Current Imbibition in Matrix Blocks: A Numerical Study and Modified Shape Factor

by Guanlin Li, Yuhu Bai, Maojun Fang and Yuetian Liu

Processes 2025, 13(4), 983; https://doi.org/10.3390/pr13040983 - 26 Mar 2025

Viewed by 223

Abstract

Spontaneous counter-current imbibition is a crucial recovery mechanism in water-wet fractured reservoirs, especially in unconventional formations like tight and shale reservoirs. The geometric characteristics of microscale fractures require further clarification regarding their impact on imbibition. In this paper, the numerical simulation method is [...] Read more.

Spontaneous counter-current imbibition is a crucial recovery mechanism in water-wet fractured reservoirs, especially in unconventional formations like tight and shale reservoirs. The geometric characteristics of microscale fractures require further clarification regarding their impact on imbibition. In this paper, the numerical simulation method is used to study the influence of fracture aperture, length, density, and relative position between fracture and imbibition open face on the counter-current imbibition process of a matrix block. For fractures perpendicular to the imbibition surface and in contact with water, the embedded discrete fracture model is utilized to simulate the impact of varying fracture apertures on counter-current imbibition. For fractures parallel to the imbibition surface, considering the impact of fracture on the capillary discontinuity of the matrix, the effects of varying fracture lengths and densities on counter-current imbibition are simulated. The results show that when fractures are perpendicular to the imbibition surface and in contact with water, the imbibition rate can be increased, and as the fracture aperture decreases, the imbibition rate first increases and then decreases. On the other hand, fractures parallel to the imbibition surface inhibit the imbibition process, with the imbibition rate decreasing as fracture length or density increases. This paper proposes an empirical shape factor considering the geometric characteristics of fractures, which can effectively characterize the influence of microfractures on matrix block imbibition, thus improving the dual-medium numerical simulation model. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

35 pages, 6458 KiB

Open AccessArticle

Comprehensive Assessment of Paleogene Hydrocarbon Source Rocks in the Hydrocarbon-Rich Sub-Sag of the Zhu-1 Depression

by Junyan Zhan, Guosheng Xu, Yuling Shi, Wanlin Xiong and Shengli Niu

Processes 2025, 13(3), 914; https://doi.org/10.3390/pr13030914 - 20 Mar 2025

Viewed by 397

Abstract

There are two sets of hydrocarbon source rock formations developed in the Paleogene of the Zhu-1 Depression: the Wenchang Formation of semi deep lacustrine facies and the Enping Formation of lacustrine facies. Their basic geochemical characteristics, chemical structures, kerogen components, sedimentary paleoenvironments, etc., [...] Read more.

There are two sets of hydrocarbon source rock formations developed in the Paleogene of the Zhu-1 Depression: the Wenchang Formation of semi deep lacustrine facies and the Enping Formation of lacustrine facies. Their basic geochemical characteristics, chemical structures, kerogen components, sedimentary paleoenvironments, etc., are not the same. High quality hydrocarbon source rocks are the basic conditions for oil and gas generation. This article comprehensively evaluates the key depression Paleogene hydrocarbon source rocks in the Zhu-1 Depression, and studies the development mechanism and controlling factors of hydrocarbon source rocks in this area, which is of great significance for understanding the development conditions, quality, and predicting potential high-quality hydrocarbon source rocks. After conducting rock pyrolysis, major and trace element analysis, and infrared spectroscopy experiments on the samples, it was found that the main source rock type of the Wenchang Formation is type II₁, which has a high HI value; the Enping Formation is mainly composed of II₂-III types with low HI values (with a small number of II₁ types), and the source rocks of the Wenchang Formation have a strong hydrocarbon producing aliphatic structure, with the sapropelic and shell formations being larger than the Enping Formation source rocks. By using methods such as CIA values, C values, and Mo-U covariant models, it can be concluded that during the Wenchang to Enping periods, the climate changed from warm and dry to cool and humid, and the overall environment was characterized by freshwater, weak oxidation weak reduction, and gradually decreasing paleo-productivity. At the same time, it was analyzed that the formation of organic rich sediments in the source rocks of the Zhu-1 Depression played an important role in the relative oxygen phase. The ratio of V/(V + Ni) to V/Cr can better indicate the redox environment of the water body and show a good correlation with TOC. Two sets of development models of source rocks controlled by paleooxygen phase were initially established, providing sufficient scientific basis for oil and gas exploration in the area. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

16 pages, 4163 KiB

Open AccessArticle

Two-Phase Production Performance of Multistage Fractured Horizontal Wells in Shale Gas Reservoir

by Hongsha Xiao, Siliang He, Man Chen, Changdi Liu, Qianwen Zhang and Ruihan Zhang

Processes 2025, 13(2), 563; https://doi.org/10.3390/pr13020563 - 17 Feb 2025

Viewed by 445

Abstract

Shale gas extraction is hindered by the complex geological conditions of shale reservoirs, such as deep burial, low permeability, and multi-zone characteristics. Therefore, horizontal well hydraulic fracturing is essential for improving reservoir permeability. However, fracture interference and fracturing fluid retention can lead to [...] Read more.

Shale gas extraction is hindered by the complex geological conditions of shale reservoirs, such as deep burial, low permeability, and multi-zone characteristics. Therefore, horizontal well hydraulic fracturing is essential for improving reservoir permeability. However, fracture interference and fracturing fluid retention can lead to gas–water co-production. Existing models for predicting the productivity of fractured horizontal wells typically focus on single-phase flow or do not fully account for fracture interactions and dynamic water saturation changes. In contrast, this study introduces a novel fast prediction model for the steady-state productivity of fractured horizontal wells under a gas–water two-phase flow. The model extends single-phase fluid seepage theory by incorporating a gas–water two-phase pseudo-pressure function, while also accounting for fracture interference using potential theory and the superposition principle. Furthermore, it dynamically integrates formation pressure and water saturation variations, offering a more accurate prediction of productivity. The result demonstrates that fracture interference significantly affects the distribution of productivity, with end fractures producing up to 5.6 × 10⁴ m³ while intermediate fractures maintain a relatively uniform production of around 0.9 × 10⁴ m³. The sensitivity analysis reveals that productivity increases with an increase in formation pressure, fracture number, fracture half-length, and fracture angle, while an increcase in water saturation and skin factor reduce it. These results highlight the importance of optimizing fracture design and production strategies. This work provides a more comprehensive and efficient method for predicting and optimizing the gas–water two-phase productivity of fractured horizontal wells. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

19 pages, 5335 KiB

Open AccessArticle

Evaluating Nitrogen Gas Injection Performance for Enhanced Oil Recovery in Fractured Basement Complex Reservoirs: Experiments and Modeling Approaches

by Ying Jia, Jingqi Ouyang, Feng Xu, Xiaocheng Gao, Juntao Zhang, Shiliang Liu and Da Li

Processes 2025, 13(2), 326; https://doi.org/10.3390/pr13020326 - 24 Jan 2025

Viewed by 710

Abstract

This study explored the effectiveness of gas injection for enhanced oil recovery (EOR) in fractured basement complex reservoirs, combining laboratory experiments with numerical simulation analyses. The experiments simulated typical field conditions, focusing on understanding the interaction between the injected gas and the reservoir’s [...] Read more.

This study explored the effectiveness of gas injection for enhanced oil recovery (EOR) in fractured basement complex reservoirs, combining laboratory experiments with numerical simulation analyses. The experiments simulated typical field conditions, focusing on understanding the interaction between the injected gas and the reservoir’s fracture–matrix system. The laboratory results showed that under the current reservoir pressure and temperature conditions, nitrogen gas flooding in the fractured matrix achieved a superior oil recovery efficiency compared to that of the other gases tested (CO₂, APG, and oxygen-reduced air), exhibiting the most favorable movable oil saturation range and the lowest residual oil saturation. To evaluate the performance of nitrogen gas injection in a fractured basement complex reservoir, a 3D reservoir model with complex natural fractures was built in a numerical reservoir simulator. Special methods were required for the geological modeling and reservoir simulation, with the specific principles outlined. Numerical simulations of gas injection into fractured basement complex reservoirs revealed that cyclic gas injection was identified as the most effective strategy, balancing incremental oil recovery with minimized gas channeling risks. This study demonstrated that the optimal injection location and rate are crucial factors affecting the recovery performance. These findings provided actionable insights for implementing gas injection EOR strategies in fractured basement complex reservoirs, highlighting the importance of optimizing the injection parameters to maximize the recovery. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

16 pages, 6667 KiB

Open AccessArticle

Nanoscale Pore Evolution of Terrestrial Shale with Thermal Maturation Level Increase Induced by Hydrous Pyrolysis

by Haiyan Hu, Wangpeng Li, Yifan Yang and Shuai Chen

Processes 2025, 13(1), 246; https://doi.org/10.3390/pr13010246 - 16 Jan 2025

Viewed by 761

Abstract

A series of terrestrial shale samples with different thermal maturities were subjected to hydrous artificial pyrolysis to study the evolution of terrestrial shale pores. The original shale was obtained from the terrestrial interval of a core sample, the total organic carbon (TOC) content [...] Read more.

A series of terrestrial shale samples with different thermal maturities were subjected to hydrous artificial pyrolysis to study the evolution of terrestrial shale pores. The original shale was obtained from the terrestrial interval of a core sample, the total organic carbon (TOC) content was 8.34 wt%, and the vitrinite reflectance (R_o) was 5.31%. The original shale core was cut into eight parts, which were heated at temperatures of 300, 350, 400, 420, 450, 500, 550, and 600 °C to obtain samples with different thermal maturities. The pore size distribution (PSD), pore volume (PV), specific surface area (SSA), and pore types were investigated via CO₂ and N₂ adsorption tests and field emission scanning electron microscopy (FE-SEM). Many organic matter (OM) pores and mineral pores were observed via FE-SEM with increasing thermal maturity. The total PV and SSA increased until the sample reached 500 °C and then decreased, and the mesopore volume followed this trend. The micropore volume first decreased, increased until the sample reached 500 °C, and then decreased; the macropore volume increased to a peak in the sample pyrolyzed at 420 °C and then remained stable. Pores with sizes ranging from 10 to 30 nm were the predominant contributors to the shale pore volume. The SSA was affected by pores with diameters less than 20 nm, which accounted for approximately 54% of the SSA. The rate of OM conversion influenced pore creation. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

15 pages, 5057 KiB

Open AccessArticle

Design and Application of Wireless Wall Thickness Monitoring System for Ground Testing Process

by Yufa He, Yu Chen, Jianfei Wei, Zhong Li, Xingwang Guo, Renjun Xie, Ruiling Li, Jian Liu, Zhenxing Tan and Kexin Zhang

Processes 2025, 13(1), 63; https://doi.org/10.3390/pr13010063 - 31 Dec 2024

Viewed by 3360

Abstract

To address the issues of pipeline corrosion and erosion during ground testing, this paper presents an innovative electromagnetic ultrasonic thickness measurement system that utilizes ZigBee wireless communication technology. The system employs a ZigBee mesh topology for creating a wireless distributed network, where node [...] Read more.

To address the issues of pipeline corrosion and erosion during ground testing, this paper presents an innovative electromagnetic ultrasonic thickness measurement system that utilizes ZigBee wireless communication technology. The system employs a ZigBee mesh topology for creating a wireless distributed network, where node devices carry out multi-point monitoring in a configuration of “one master, multiple”. Each node is powered by an STM32 embedded control chip and fitted with ultrasonic sensors. Slave nodes transmit the real-time data they collect to a server via the master node, thus enabling remote monitoring of the system through a web interface. The system incorporates an enhanced data filtering algorithm, allowing for precise monitoring of the pipeline wall thickness and providing immediate data feedback. An experimental validation of the system’s stability and long-distance transmission capabilities was performed on a simulated platform, confirming its viability and applicability for real-world engineering applications. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

16 pages, 4766 KiB

Open AccessArticle

A New Productivity Evaluation Method for Horizontal Wells in Offshore Low-Permeability Reservoir Based on Modified Theoretical Model

by Li Li, Mingying Xie, Weixin Liu, Jianwen Dai, Shasha Feng, Di Luo, Kun Wang, Yang Gao and Ruijie Huang

Processes 2024, 12(12), 2830; https://doi.org/10.3390/pr12122830 - 10 Dec 2024

Viewed by 851

Abstract

In the early stages of offshore low-permeability oil field development, it is crucial to ascertain the productivity of production wells to select high-production, high-quality reservoirs, which affects the design of the development plan. Therefore, accurate evaluation of well productivity is essential. Drill Stem [...] Read more.

In the early stages of offshore low-permeability oil field development, it is crucial to ascertain the productivity of production wells to select high-production, high-quality reservoirs, which affects the design of the development plan. Therefore, accurate evaluation of well productivity is essential. Drill Stem Testing (DST) is the only way to obtain the true productivity of offshore reservoirs, but conducting DST in offshore oilfields is extremely costly. This article introduces a novel productivity evaluation method for horizontal wells in offshore low-permeability reservoirs based on an improved theoretical model, which relieves the limitations of traditional methods. Firstly, a new horizontal well productivity evaluation theoretical model is derived, with the consideration of the effects of the threshold pressure gradient, stress sensitivity, skin factor, and formation heterogeneity on fluid flow in low-permeability reservoirs. Then, the productivity profiles are classified based on differences in the permeability distribution of horizontal well sections. Thirdly, the productivity evaluation equation is modified by calculating correction coefficients to maximize the model’s accuracy. Based on the overdetermined equation concepts and existing DST productivity data, the derived correction coefficients in this paper are x₁ = 3.3182, x₂ = 0.7720, and x₃ = 1.0327. Finally, the proposed method is successfully applied in an offshore low-permeability reservoir with nine horizontal wells, increasing the productivity evaluation accuracy from 65.80% to 96.82% compared with the traditional Production Index (PI) method. This technology provides a novel approach to evaluating the productivity of horizontal wells in offshore low-permeability reservoirs. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

15 pages, 10531 KiB

Open AccessArticle

Mechanical Characterization of Main Minerals in Carbonate Rock at the Micro Scale Based on Nanoindentation

by Ting Deng, Junliang Zhao, Hongchuan Yin, Qiang Xie and Ling Gou

Processes 2024, 12(12), 2727; https://doi.org/10.3390/pr12122727 - 2 Dec 2024

Viewed by 982

Abstract

The mechanical characterization of carbonate rock is crucial for the development of a hydrocarbon reservoir and underground gas storage. As a kind of natural composite material, the mechanical properties of carbonate rock exhibit multiscale characteristics. The macroscopic mechanical properties of carbonate rock are [...] Read more.

The mechanical characterization of carbonate rock is crucial for the development of a hydrocarbon reservoir and underground gas storage. As a kind of natural composite material, the mechanical properties of carbonate rock exhibit multiscale characteristics. The macroscopic mechanical properties of carbonate rock are determined by the mineral composition and structure at the micro scale. To achieve a mechanical investigation at the micro scale, this study designed a scheme for micromechanical characterization of carbonate rock. First, scanning electron microscope observation and energy dispersive spectroscopy analysis were combined to select the appropriate micromechanical test areas and to identify the mineral types in each area. Second, the selected test area was positioned in the nanoindentation instrument through the comparison of different-type microscopic images. Finally, quasi-static nanoindentation was carried out on the surface of different minerals in the selected test area to obtain quantitative mechanical evaluation results. A typical carbonate rock sample from the Huangcaoxia gas storage was investigated in this study. The experimental results indicated apparent micromechanical heterogeneity in the carbonate rock. The Young’s modulus of pyrite was over 200 GPa, while that of clay minerals was only approximately 50 GPa. In addition, the proposed micromechanical characterization scheme was discussed based on experimental results. For minerals with an unknown Poisson’s ratio, the maximum error introduced by the 0.25 assumption was lower than 15%. To discuss the effectiveness of the nanoindentation results, the characterization abilities constituted by lateral spatial resolution and elastic response depth were analyzed. The analysis results revealed that the nanoindentation measurement of clay was more susceptible to influence by the surrounding environment as compared to other kinds of minerals with the experimental setup in this study. The micromechanical characterization scheme for clay minerals can be optimized in future research. The mechanical data obtained at the micro scale can be used for the interpretation of the macroscopic mechanical features of carbonate rock for the parameter input and validation of mineral-related simulation and for the construction of a mechanical upscaling model. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

17 pages, 4329 KiB

Open AccessArticle

Research on Crack Sealing Performance of Polymer Microsphere/Hydrogel Composite System

by Wenjin Liu, Jun Li, Taotao Luo and Xueyuan Long

Processes 2024, 12(11), 2483; https://doi.org/10.3390/pr12112483 - 8 Nov 2024

Viewed by 896

Abstract

Owing to their excellent water-absorption and swelling properties, polymer microspheres have been extensively applied as deep profile control agents in oilfields. These microspheres effectively seal large pore-throat channels in reservoirs, optimizing the water-absorption profile. In this study, a composite system was developed, comprising [...] Read more.

Owing to their excellent water-absorption and swelling properties, polymer microspheres have been extensively applied as deep profile control agents in oilfields. These microspheres effectively seal large pore-throat channels in reservoirs, optimizing the water-absorption profile. In this study, a composite system was developed, comprising polymer microspheres and polyacrylamide polymers, with the inclusion of a cross-linking agent. The system leverages the synergistic effects of polymer microspheres and other plugging techniques to efficiently seal fractured reservoirs. Results indicate that the composite system exhibits strong blocking and scour resistance due to enhanced network integrity, higher viscosity, and improved elastic strength. Additionally, the composite system demonstrates a notable self-repairing capability, maintaining a high sealing efficiency even after a waterflood breakthrough. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

17 pages, 9123 KiB

Open AccessArticle

The Influence of Rock and Natural Weak Plane Properties on the Vertical Propagation of Hydraulic Fractures

by Xuefeng Yang, Cheng Chang, Qiuyang Cheng, Weiyang Xie, Haoran Hu, Yongming Li, Yitao Huang and Yu Peng

Processes 2024, 12(11), 2477; https://doi.org/10.3390/pr12112477 - 7 Nov 2024

Cited by 1 | Viewed by 1000

Abstract

China has abundant shale gas resources with good exploration value and development potential, making it a recent hotspot for exploration and development. It is widely agreed that large-scale hydraulic fracturing is essential for reservoir enhancement in shale formations. However, the evolution of fractures [...] Read more.

China has abundant shale gas resources with good exploration value and development potential, making it a recent hotspot for exploration and development. It is widely agreed that large-scale hydraulic fracturing is essential for reservoir enhancement in shale formations. However, the evolution of fractures during hydraulic fracturing is highly complex, necessitating research on the influence of various factors on the vertical propagation of hydraulic fractures. Based on geological and engineering parameters from the Luzhou block in southern Sichuan, this study employed the finite element method (FEM) and the cohesive element method to establish a coupled fluid-solid model for the vertical propagation of hydraulic fractures. Numerical simulations were conducted to investigate the interaction between hydraulic fractures and natural weak planes, clarifying the mechanisms involved. This study elucidates how different rock and natural weak plane properties affect the vertical propagation of hydraulic fractures and draws diagrams illustrating these interactions. The research indicated three fracture distribution patterns after the intersection of hydraulic fractures with natural weak planes: passive fractures, ‘I’-shaped fractures, and crossing fractures. The main fractures in these patterns exhibit initial damage and damage evolution characterized by tensile failure. Specifically, in passive fractures, the initial damage and damage evolution of natural weak planes manifest as shear failure. In ‘I’-shaped fractures, the initial damage in natural weak planes is characterized by shear failure, with damage evolution showing tensile failure. Crossing fractures show minimal damage in the weak planes. Under conditions of high natural weak plane cohesive strength, high Young’s modulus, low interlayer rock cohesive strength, high vertical stress difference, low interlayer stress difference, and high intersection angles, crossing fractures tend to form. Conversely, conditions of low natural weak plane cohesive strength, low Young’s modulus, high interlayer rock cohesive strength, low vertical stress difference, high interlayer stress difference, and low intersection angles favor the formation of ‘I’-shaped fractures. Passive fractures form under conditions of low natural weak plane cohesive strength and high vertical stress difference. This study found that Poisson’s ratio has a minimal effect on the vertical expansion of hydraulic fractures under the studied conditions, with natural weak plane strength being the primary control factor for fracture patterns. These findings enhance the theoretical foundation for the vertical propagation of hydraulic fractures in deep shale formations, facilitating the development and implementation of strategies for enhancing production in shale reservoirs with natural weak planes and better optimizing production in different types of shale reservoirs. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

15 pages, 5215 KiB

Open AccessArticle

Molecular Insights into CO₂ Diffusion Behavior in Crude Oil

by Chunning Gao, Yongqiang Zhang, Wei Fan, Dezhao Chen, Keqin Wu, Shuai Pan, Yuchuan Guo, Haizhu Wang and Keliu Wu

Processes 2024, 12(10), 2248; https://doi.org/10.3390/pr12102248 - 15 Oct 2024

Cited by 1 | Viewed by 1422

Abstract

CO₂ flooding plays a significant part in enhancing oil recovery and is essential to achieving CCUS (Carbon Capture, Utilization, and Storage). This study aims to understand the fundamental theory of CO₂ dissolving and diffusing into crude oil and how these processes [...] Read more.

CO₂ flooding plays a significant part in enhancing oil recovery and is essential to achieving CCUS (Carbon Capture, Utilization, and Storage). This study aims to understand the fundamental theory of CO₂ dissolving and diffusing into crude oil and how these processes vary under reasonable reservoir conditions. In this paper, we primarily use molecular dynamics simulation to construct a multi-component crude oil model with 17 hydrocarbons, which is on the basis of a component analysis of oil samples through laboratory experiments. Then, the CO₂ dissolving capacity of the multi-component crude was quantitatively characterized and the impacts of external conditions—including temperature and pressure—on the motion of the CO₂ dissolution and diffusion coefficients were systematically investigated. Finally, the swelling behavior of mixed CO₂–crude oil was analyzed and the diffusion coefficients were predicted; furthermore, the levels of CO₂ impacting the oil’s mobility were analyzed. Results showed that temperature stimulation intensified molecular thermal motion and increased the voids between the alkane molecules, promoting the rapid dissolution and diffusion of CO₂. This caused the crude oil to swell and reduced its viscosity, further improving the mobility of the crude oil. As the pressure increased, the voids between the internal and external potential energy of the crude oil models became wider, facilitating the dissolution of CO₂. However, when subjected to external compression, the CO₂ molecules’ diffusing progress within the oil samples was significantly limited, even diverging to zero, which inhabited the improvement in oil mobility. This study provides some meaningful insights into the effect of CO₂ on improving molecular-scale mobility, providing theoretical guidance for subsequent investigations into CO₂–crude oil mixtures’ complicated and detailed behavior. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

13 pages, 3660 KiB

Open AccessArticle

A Novel Surrogate-Assisted Multi-Objective Well Control Parameter Optimization Method Based on Selective Ensembles

by Lian Wang, Rui Deng, Liang Zhang, Jianhua Qu, Hehua Wang, Liehui Zhang, Xing Zhao, Bing Xu, Xindong Lv and Caspar Daniel Adenutsi

Processes 2024, 12(10), 2140; https://doi.org/10.3390/pr12102140 - 1 Oct 2024

Cited by 1 | Viewed by 1157

Abstract

Multi-objective optimization algorithms are crucial for addressing real-world problems, particularly with regard to optimizing well control parameters, which are often computationally expensive due to their reliance on numerical simulations. Surrogate-assisted models help to reduce this computational burden, but their effectiveness depends on the [...] Read more.

Multi-objective optimization algorithms are crucial for addressing real-world problems, particularly with regard to optimizing well control parameters, which are often computationally expensive due to their reliance on numerical simulations. Surrogate-assisted models help to reduce this computational burden, but their effectiveness depends on the quality of the surrogates, which can be affected by candidate dimension and noise. This study proposes a novel surrogate-assisted multi-objective optimization framework (MOO-SESA) that combines selective ensemble support-vector regression with NSGA-II. The framework’s uniqueness lies in its adaptive selection of a diverse subset of surrogates, established prior to iteration, to enhance accuracy, robustness, and computational efficiency. To our knowledge, this is the first instance in which selective ensemble techniques with multi-objective optimization have been applied to reservoir well control problems. Through employing an ensemble strategy for improving the quality of the surrogate model, MOO-SESA demonstrated superior well control scenarios and faster convergence compared to traditional surrogate-assisted models when applied to the SPE10 and Egg reservoir models. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

18 pages, 6286 KiB

Open AccessArticle

The Gas Production Characteristics of No. 3 Coal Seam Coalbed Methane Well in the Zhengbei Block and the Optimization of Favorable Development Areas

by Cong Zhang, Qiujia Hu, Chunchun Liu, Huimin Jia, Guangjie Sang, Dingquan Wu, Kexin Li and Qian Wang

Processes 2024, 12(9), 2018; https://doi.org/10.3390/pr12092018 - 19 Sep 2024

Viewed by 894

Abstract

The characteristics and influencing factors of gas production in CBM wells are analyzed based on the field geological data and the productivity data of coalbed methane (CBM) wells in the Zhengbei block, and then the favorable areas are divided. The results show that [...] Read more.

The characteristics and influencing factors of gas production in CBM wells are analyzed based on the field geological data and the productivity data of coalbed methane (CBM) wells in the Zhengbei block, and then the favorable areas are divided. The results show that the average gas production of No. 3 coal seam CBM wells in the study area is in the range of 0~1793 m³/d, with an average of 250.97 m³/d; 80% of the wells are less than 500 m³/d, and there are fewer wells above 1000 m³/d. The average gas production is positively correlated with gas content, critical desorption pressure, permeability, Young’s modulus, and Schlumberger ratio, and negatively correlated with fracture index, fault fractal dimension, Poisson’s ratio, and horizontal stress difference coefficient. The relationship between coal seam thickness and the minimum horizontal principal stress is not strong. The low-yield wells have the characteristics of multiple pump-stopping disturbances, unstable casing pressure control, overly rapid pressure reduction in the single-phase flow stage, sand and pulverized coal production, and high-yield water in the later stage during the drainage process. It may be caused by the small difference in compressive strength between the roof and floor and the coal seam, and the small difference in the Young’s modulus of the floor. The difference between the two high-yield wells is large, and the fracturing cracks are easily controlled in the coal seam and extend along the level. The production control factors from strong to weak are as follows: critical desorption pressure, permeability, Schlumberger ratio, fault fractal dimension, Young’s modulus, horizontal stress difference coefficient, minimum horizontal principal stress, gas content, Poisson’s ratio, fracture index, coal seam thickness. The type I development unit (development of favorable areas) of the Zhengbei block is interspersed with the north and south of the block on the plane, and the III development unit is mainly located in the east of the block and near the Z-56 well. The comprehensive index has a significant positive correlation with the gas production, and the prediction results are accurate. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

20 pages, 2173 KiB

Open AccessArticle

A Full-Stage Productivity Equation for Constant-Volume Gas Reservoirs and Its Application

by Lei Zhang, Shiying Cheng, Keliu Wu, Cuiping Xin, Jiaxuan Song, Tao Zhang, Xiaofei Xie and Zidan Zhao

Processes 2024, 12(9), 1855; https://doi.org/10.3390/pr12091855 - 30 Aug 2024

Viewed by 956

Abstract

Gas well production involves various stages, including stable, variable, and declining production. However, existing production-capacity equations typically apply only to the stable production stage, limiting their effectiveness in evaluating gas well productivity across all stages. To address this, the material balance equation and [...] Read more.

Gas well production involves various stages, including stable, variable, and declining production. However, existing production-capacity equations typically apply only to the stable production stage, limiting their effectiveness in evaluating gas well productivity across all stages. To address this, the material balance equation and Darcy’s equation were employed to account for changes in average formation pressure due to pressure drop funnels. The concept of a pressure-conversion skin factor was introduced, and its approximation was developed, leading to the establishment and solution of a full-stage productivity equation. Numerical simulations were then conducted to verify the accuracy and applicability of this equation. The findings are as follows: ① The full-stage productivity equation remains effective even when production rates and pressure are not constant, with the only potential source of inaccuracy being the approximative solution for the pressure conversion-skin factor. ② Numerical simulations demonstrated that the approximate solution closely matched the numerical simulation results for average formation pressure across various production stages and fundamental parameters, showing a consistent trend and high precision. The approximate and independent approximation solutions for absolute open-flow capacity were nearly identical, indicating the full-stage productivity equation’s applicability throughout the production of gas wells. ③ Application results revealed that the full-stage productivity equation offers superior accuracy compared to the modified isochronous well test. ④ The approximate solution generally provides slightly higher accuracy, and the independent approximate solution effectively eliminates the influence of gas leakage radius. Therefore, the use of the approximate solution is recommended to calculate the average formation pressure and the independent approximate solution to calculate the absolute open-flow capacity. The full-stage productivity equation developed in this study is not constrained by the production system, making it suitable for productivity evaluation across all stages of gas well production. This has significant implications for the effective development of gas fields. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

13 pages, 16482 KiB

Open AccessArticle

Study on Nonlinear Parameter Inversion and Numerical Simulation in Condensate Reservoirs

by Kuiqian Ma, Chenxu Yang, Zhennan Gao, Xifeng Wang and Xinrong Liu

Processes 2024, 12(9), 1823; https://doi.org/10.3390/pr12091823 - 27 Aug 2024

Cited by 1 | Viewed by 779

Abstract

The B6 metamorphic buried hill condensate gas reservoir exhibits a highly compact matrix, leading to a rapid decline in bottom-hole pressure during initial production. The minimal difference between formation and saturation pressures results in severe retrograde condensation, with multiphase flow further increasing resistance. [...] Read more.

The B6 metamorphic buried hill condensate gas reservoir exhibits a highly compact matrix, leading to a rapid decline in bottom-hole pressure during initial production. The minimal difference between formation and saturation pressures results in severe retrograde condensation, with multiphase flow further increasing resistance. Conventional numerical simulations often overestimate reservoir energy supply due to their failure to account for this additional resistance, leading to inaccuracies in bottom-hole pressure predictions and gas–oil ratio during history matching. To address these challenges, this study conducted research on nonlinear numerical simulation for buried hill condensate gas reservoirs and established a method for calculating a multiphase pressure sweep range based on the well testing theory. By correcting and fitting the pressure propagation boundaries with numerical simulation, the nonlinear flow parameters applicable to the B6 gas field were inversed. This study revealed that conventional Darcy flow is inadequate for predicting pressure propagation boundaries and that it is possible to reasonably characterize the pressure sweep range through nonlinear flow. This approach resulted in an improvement in the accuracy of historical matching for bottom-hole pressure and gas–oil ratio, which improve the historical fitting accuracy to 85%, providing valuable insights for the development of similar reservoirs. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

15 pages, 6518 KiB

Open AccessArticle

Experimental and Numerical Simulation Study on Enhancing Gas Recovery with Impure CO₂ in Gas Reservoirs

by Zihan Zhao, Shaomu Wen, Mengyu Wang, Lianjin Zhang, Cheng Cao, Changcheng Yang and Longxin Li

Processes 2024, 12(8), 1663; https://doi.org/10.3390/pr12081663 - 8 Aug 2024

Cited by 1 | Viewed by 1130

Abstract

To achieve carbon peaking and carbon neutrality goals, using CO₂ to enhance natural gas recovery has broad application prospects. However, the potential for CO₂ to increase recovery rates remains unclear, the mechanisms are not fully understood, and the cost of purifying [...] Read more.

To achieve carbon peaking and carbon neutrality goals, using CO₂ to enhance natural gas recovery has broad application prospects. However, the potential for CO₂ to increase recovery rates remains unclear, the mechanisms are not fully understood, and the cost of purifying CO₂ is high. Therefore, studying the effects of impure CO₂ on natural gas extraction is of significant importance. This study investigated the effects of injection timing and gas composition on natural gas recovery through high-temperature, high-pressure, long-core displacement experiments. Based on the experimental results, numerical simulations of CO₂-enhanced gas recovery and sequestration were conducted, examining the impact of impurity gas concentration, injection timing, injection speed, and water saturation on recovery efficiency. The results indicate that higher impurity levels in CO₂ increase gas diffusion, reducing the effectiveness of natural gas recovery and decreasing CO₂ sequestration. Earlier injection timing improves recovery efficiency but results in a lower ultimate recovery rate. Higher injection speeds and water saturation levels both effectively enhance recovery rates. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

29 pages, 4031 KiB

Open AccessArticle

Productivity Model Study of Water-Bearing Tight Gas Reservoirs Considering Micro- to Nano-Scale Effects

by Feifei Chen, Yonggang Duan and Kun Wang

Processes 2024, 12(7), 1499; https://doi.org/10.3390/pr12071499 - 17 Jul 2024

Cited by 2 | Viewed by 799

Abstract

Tight sandstone is rich in micron- and nano-scale pores, making the two-phase flow of gas and water complex. Establishing reliable relative permeability and productivity models is an urgent issue. In this study, we first used a slip model to correct the gas phase’s [...] Read more.

Tight sandstone is rich in micron- and nano-scale pores, making the two-phase flow of gas and water complex. Establishing reliable relative permeability and productivity models is an urgent issue. In this study, we first used a slip model to correct the gas phase’s no-slip Hagen–Poiseuille equation for nano- and micropores. Then, combined with the fractal theory of porous media and the tortuous capillary bundle model, we established two-phase relative permeability models for nanopores and micropores. These relative permeability models comprehensively consider the gas slippage effect, the initiation pressure gradient, the pores’ fractal characteristics, and water film mechanisms. Based on these models, we developed a three-region coupling productivity model for water-bearing tight gas reservoirs with multi-stage fractured horizontal wells. This productivity model considered the micro- and nano-scale effects and the heterogeneity of fracture networks. Then, the model was solved and validated with a field case. The results indicated that the three-region composite unsteady productivity model for water-bearing tight gas reservoirs, which incorporated micro- and nano-scale effects (with consideration of micro-scale and nano-scale phenomena in the fluid flow), could accurately predict a gas well’s productivity. An analysis of the factors influencing productivity showed that ignoring the micro- and nano-scale effects in water-bearing tight gas reservoirs will underestimate the reservoir’s productivity. The initial water saturation, the two-phase flow’s initiation pressure gradient, and capillary force are all negatively correlated with the productivity of gas wells, while the conductivity of the fractures is positively correlated with gas well productivity. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

Review

Jump to: Research

20 pages, 2169 KiB

Open AccessReview

A Review on the Water Invasion Mechanism and Enhanced Gas Recovery Methods in Carbonate Bottom-Water Gas Reservoirs

by Xian Peng, Yuhan Hu, Fei Zhang, Ruihan Zhang and Hongli Zhao

Processes 2024, 12(12), 2748; https://doi.org/10.3390/pr12122748 - 3 Dec 2024

Viewed by 1164

Abstract

Carbonate gas reservoirs are crucial in gas field development, with carbonate bottom-water gas reservoirs being a significant subset. However, the development of these reservoirs often faces challenges such as water invasion, leading to a low gas recovery rate. Enhancing gas recovery is a [...] Read more.

Carbonate gas reservoirs are crucial in gas field development, with carbonate bottom-water gas reservoirs being a significant subset. However, the development of these reservoirs often faces challenges such as water invasion, leading to a low gas recovery rate. Enhancing gas recovery is a primary goal for researchers in this field. This study provides a systematic review of the mechanisms, identification, and dynamic prediction of water invasion in these gas reservoirs. The technical adaptability and application range of different enhanced recovery methods are summarized, and their application effects are evaluated. The results indicate that carbonate gas reservoirs have diverse types of storage and permeability spaces, with a wide distribution of pore size scales, leading to various types of enclosed gas caused by water invasion. The prediction accuracy of water invasion models for bottom-water gas reservoirs with fractures and vugs is relatively low. Therefore, numerical simulation research on the basis of fine reservoir characterization is the key technology. The control of bottom-water invasion and the rescue measures after the bottom-water invasion are the keys to improving gas recovery, which can be divided into four types: drainage gas recovery, water control production, active drainage, and injection medium. Gas production by drainage is the main technology for improving gas recovery, among which foam drainage is the most widespread. The optimization of development parameters in production by water control has a good effect in the early stages of development. The active drainage technology on the water invasion channel is the bottom-up technology for the effective development of strong water-flooded gas reservoirs. CO₂ injection may have great potential to improve the recovery of bottom-water gas reservoirs, which is one of the important research directions under the background of “carbon peaking and carbon neutrality”. The research provides theoretical and technical reference significance for enhanced recovery of carbonate bottom-water gas reservoirs. Full article

(This article belongs to the Special Issue Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition)

► Show Figures

Figure 1

Journal Menu

Journal Browser

Advances in Enhancing Unconventional Oil/Gas Recovery, 2nd Edition

Share This Special Issue

Special Issue Editors

Special Issue Information

Keywords

Benefits of Publishing in a Special Issue

Related Special Issue

Published Papers (18 papers)

Research

Review

Further Information

Guidelines

MDPI Initiatives

Follow MDPI