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Dr. Hu Li

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School of Economics, Sichuan University of Science & Engineering, Yibin 644000, China

Dr. Ahmed E. Radwan

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Kraków Institute of Geological Sciences, Jagiellonian University, Krakow, Poland

Dr. Shuai Yin

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School of Earth Science and Engineering, Xi'an Shiyou University, Xi'an 710065, China

Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs

Abstract submission deadline

31 January 2025

Manuscript submission deadline

31 March 2025

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21413

Topic Information

Dear Colleagues,

The existence of reservoir fractures in oil and gas reservoirs not only improves the percolation performance of the reservoir but also controls the formation and distribution of the oil and gas. Fractures are widely distributed in tight carbonate rock, tight sandstone, mud shale and volcanic rock reservoirs. Fractured oil and gas reservoirs have become an important field for increasing oil and gas reserves and production and are also an important part of unconventional energy resources. Therefore, the development of reservoir geomechanics and engineering evaluation is an urgent need for the efficient development of this type of oil and gas reservoir. Because fractured reservoirs often have well-developed natural fractures, strong heterogeneity and anisotropy, and complex in situ stress distribution, it is difficult to carry out engineering and geological evaluation of fractured formations. At the same time, it brings major challenges to drilling and production, such as frequent leakage, wellbore instability, stuck pipes, low hydraulic fracturing conductivity, rapid water cut rise, and rapid production decline. In particular, the drilling safety accident caused by the instability of the wellbore severely restricts the exploration and development of oil and gas. The current research on geomechanics of fractured oil and gas reservoirs includes geological and engineering sweet spot prediction, pore-fracture coupling and evolution, quantitative characterization of natural fractures, in situ stress prediction and evaluation, coupling mechanism of natural fractures and artificial fractures, wellbore stability evaluation, hydraulic fracturing optimization, etc. These theoretical innovations and engineering practices provide support for drilling engineering in the development of fractured oil and gas resources, and provide feasible technical means and guarantees for increasing the rate of drilling in fractured formations and improving the efficiency of low-grade gas reservoirs. The theme of this Topic is to bring together original research and review articles discussing the research progress of the evaluation of geomechanics and engineering of fractured oil and gas reservoirs (tight carbonate rocks, tight sandstones, shale, volcanic rocks, etc.). We invite potential authors to discuss how to advance theoretical research and engineering applications such as pore–fracture coupling and quantitative characterization, natural fracture evolution and prediction, geomechanics, drilling and completion, and wellbore stability evaluation to further improve the exploration and development of fractured oil and gas reservoirs. Potential topics include, but are not limited to, the following:

Core elements and evaluation of reservoir geomechanics;
Formation, evolution mechanism, and controlling factors of pores and fractures;
Natural fracture prediction methods based on geology, logging, or seismic;
Coupling mechanism of natural fractures and artificial fractures;
Diagenetic evolution and classification of fractured reservoirs;
In situ stress distribution and quantitative evaluation of fractured reservoirs;
Drilling in fractured formations and evaluation of wellbore stability;
Prediction of geomechanical sweet spots in fractured reservoirs;
Hydraulic fracturing optimization of fractured oil and gas reservoirs;
Geomechanical changes caused by fluid–rock interactions in fractured reservoirs;
Engineering evaluation of fracturing fluids in efficient development of fractured reservoirs.

Dr. Hu Li
Dr. Ahmed E. Radwan
Dr. Shuai Yin
Topic Editors

Keywords

fractured reservoir
fracture characterization
geomechanics
engineering evaluation
sweet spot prediction
pore-fracture coupling
tight reservoir
diagenetic evolution
in-situ stress evaluation

Participating Journals

Journal Name	Impact Factor	CiteScore	Launched Year	First Decision (median)	APC
Applied Sciences applsci	2.5	5.3	2011	17.8 Days	CHF 2400	Submit
Energies energies	3.0	6.2	2008	17.5 Days	CHF 2600	Submit
Geosciences geosciences	2.4	5.3	2011	26.2 Days	CHF 1800	Submit
Minerals minerals	2.2	4.1	2011	18 Days	CHF 2400	Submit
Remote Sensing remotesensing	4.2	8.3	2009	24.7 Days	CHF 2700	Submit

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20 pages, 8601 KiB

Open AccessArticle

Mechanisms of Reservoir Space Preservation in Ultra-Deep Shales: Insights from the Ordovician–Silurian Wufeng–Longmaxi Formation, Eastern Sichuan Basin

by Pengwan Wang, Xiaolong He, Ya’na Chen, Chuan Xu, Quanbin Cao, Kai Yang and Bing Zhang

Minerals 2024, 14(10), 1046; https://doi.org/10.3390/min14101046 - 18 Oct 2024

Viewed by 626

Abstract

This study aims to explore the reservoir characteristics and formation mechanisms of ultra-deep shale gas in the Ordovician–Silurian Wufeng–Longmaxi Formation in the Sichuan Basin in order to provide theoretical support and practical guidance for the exploration and development of ultra-deep shale gas. With recent breakthroughs in ultra-deep shale gas exploration, understanding its organic matter development, mineral composition, and reservoir space characteristics has become particularly important. The background of this research lies in the significant potential of ultra-deep shale gas, which remains inadequately understood, necessitating an in-depth analysis of its pore structure and reservoir quality. Through a systematic study of the ultra-deep shale in well FS1 of Sichuan Basin, that the following was found: (i) The ultra-deep shale in the Wufeng–Longmaxi Formation is mainly composed of quartz and clay minerals, exhibiting high total organic carbon (TOC) and high porosity characteristics, indicating it is in an overmature thermal evolution stage. (ii) Organic pores and microcracks in the ultra-deep shale are more developed compared to middle-shallow and deep shale, forming a complex pore structure that is conducive to gas storage. (iii) In the diagenesis process, the dissolution and recrystallization of the biogenic skeleton promote the cementation between autogenetic quartz particles, forming a rigid skeleton that effectively inhibits the impact of mechanical compaction. (iv) The overpressure environment created by the hydrocarbon generation process, along with gas production from hydrocarbon cracking, can effectively offset the mechanical compaction of overburden pressure on micropores, and this overpressure environment also promotes the further development of microfractures, which is beneficial for the development and preservation of ultra-deep shale pores. In summary, this study not only reveals the reservoir characteristics and formation mechanisms of ultra-deep shale but also provides essential references for the exploration and development of ultra-deep shale gas in the Sichuan Basin and similar regions, emphasizing the ongoing significance of research in this field. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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17 pages, 2671 KiB

Open AccessArticle

Experimental Study on Improving the Recovery Rate of Low-Pressure Tight Oil Reservoirs Using Molecular Deposition Film Technology

by Chun Shao and Xiaoyang Chen

Appl. Sci. 2024, 14(20), 9197; https://doi.org/10.3390/app14209197 - 10 Oct 2024

Viewed by 691

Abstract

The intricate geological characteristics of tight oil reservoirs, characterized by extremely low porosity and permeability as well as pronounced heterogeneity, have led to a decline in reservoir pressure, substantial gas expulsion, an accelerated decrease in oil production rates, and the inadequacy of traditional water injection methods for enhancing oil recovery. As a result, operators encounter heightened operational costs and prolonged timelines necessary to achieve optimal production levels. This situation underscores the increasing demand for advanced techniques specifically designed for tight oil reservoirs. An internal evaluation is presented, focusing on the application of molecular deposition film techniques for enhanced oil recovery from tight oil reservoirs, with the aim of elucidating the underlying mechanisms of this approach. The research addresses fluid flow resistance by employing aqueous solutions as transmission media and leverages electrostatic interactions to generate nanometer-thin films that enhance the surface properties of the reservoir while modifying the interaction dynamics between oil and rock. This facilitates the more efficient displacement of injected fluids to replace oil during pore flushing processes, thereby achieving enhanced oil recovery objectives. The experimental results indicate that an improvement in oil displacement efficiency is attained by increasing the concentration of the molecular deposition film agent, with 400 mg/L identified as the optimal concentration from an economic perspective. It is advisable to commence with a concentration of 500 mg/L before transitioning to 400 mg/L, considering the adsorption effects near the well zone and dilution phenomena within the reservoir. Molecular deposition films can effectively reduce injection pressure, enhance injection capacity, and lower initiation pressure. These improvements significantly optimize flow conditions within the reservoir and increase core permeability, resulting in a 7.82% enhancement in oil recovery. This molecular deposition film oil recovery technology presents a promising innovative approach for enhanced oil recovery, serving as a viable alternative to conventional water flooding methods. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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17 pages, 10823 KiB

Open AccessArticle

Logging Identification Method for Reservoir Facies in Fractured-Vuggy Dolomite Reservoirs Based on AI: A Case Study of Ediacaran Dengying Formation, Sichuan Basin, China

by Yu Ye, Zengzheng Jiang, Xiangjun Liu, Zhanlei Wang and Yifan Gu

Appl. Sci. 2024, 14(17), 7504; https://doi.org/10.3390/app14177504 - 25 Aug 2024

Viewed by 663

Abstract

As an important target for deep to ultra-deep carbonate oil and gas exploration, Fractured-Vuggy dolomite reservoirs have strong heterogeneity. Accurate characterization of reservoir facies is crucial for their exploration and exploitation. Three methods, including the unsupervised intelligent clustering method of improved Fuzzy C-means clustering Algorithm Based on Density Sensitive Distance and Fuzzy Partrition (FCM-DSDFP), the fusion method of Principal Components Analysis (PCA) dimensionality reduction and noise reduction, and the principle of clustering feature analysis are applied to identify reservoir facies based on logging data. Based on the PCA method, the logging response characteristics of the reservoir facies are excavated, and the fusion characterization data of dimensionality reduction and noise reduction are extracted. The FCM-DSDFP unsupervised intelligent clustering method, a model that approximates the subsurface conditions is established, and the reliability of the model is tested according to the elbow rule and silhouette coefficient. Combining drilling core observation, Fractured-Vuggy type, partially cemented Fractured-Vuggy type, Pore-Vuggy type, Pore Type I, Pore Type II, Tight Type I, and Tight Type II are divided in the Dengying Formation 4th Member. Fractured-Vuggy type, partially cemented Fractured-Vuggy type, Pore-Vuggy Type I, Pore-Vuggy Type II, Pore Type I, Pore Type II, and Tight Type are divided in the Dengying Formation 2nd Member, respectively. Two methods were applied to verify the reservoir facies identification results based on intelligent algorithms. The first method is to compare the identification results with the reservoir facies types identified by core observations (Well PT103 and PS13). The second method is to verify the recognition results of intelligent algorithms by utilizing the relationship between reservoir facies types and bitumen. The test results show that the accuracy of the reservoir level identification is higher than 0.9, and the applicability is better than the commonly used algorithms such as FCM and K-means. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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19 pages, 11018 KiB

Open AccessArticle

Experimental Study on Pulsed Plasma Stimulation and Matching with Simulation Work

by Mina Khalaf, M. Soliman, S. M. Farouq-Ali, Craig Cipolla and Ron Dusterhoft

Appl. Sci. 2024, 14(11), 4752; https://doi.org/10.3390/app14114752 - 31 May 2024

Cited by 1 | Viewed by 617

Abstract

Plasma stimulation is a form of waterless fracturing as it requires that only the wellbore be filled with an aqueous fluid. The technique creates multiple fractures propagating in different directions around the wellbore. The intent of this paper is to present an experimental and numerical investigation of the degree of competitiveness of plasma stimulation with hydraulic fracturing, especially in the case of stimulating tight formation. Several cases were run experimentally. The samples included limestone and sandstone to investigate plasma fracturing in different rock types. In addition, the main goal of the experiments was to study the creation of fracture(s) under confining stresses, the type of rock, the amount of electrical energy used in the experiment, and the length of the wire to generate the plasma reaction. A laboratory plasma equipment was designed and used to accomplish the experimental work. The experiments were then numerically matched using a finite element numerical simulator, HOSS developed by LANL (Los Alamos National Lab). HOSS was developed to simulate high-strain-rate fractures such as those created by plasma stimulation. It accounts for mixed-mode fracture mechanics which are tensile and shear fractures. The simulator governing equations obey the conservation of mass and momentum in a solid-mechanics sense and account for the nonlinear deformation of rock material. The matching of the experiment allowed us to validate the HOSS simulation of the process and showed that the numerical results are in good agreement with the experimental work. Using the HOSS simulator, we also investigated the effect of higher energy levels and/or short release time on a cement rock model. The pressure profile that is developed due to the energy release can vary in the peak pressure and the release time. The results showed that the plasma fracturing technique is an effective stimulation method in sandstone and limestone. Plasma fractures were developed in the rock samples and extended from the sample wellbore to the outer boundaries. The shape of the pressure pulse has an impact on the developed fractures. Moreover, the effect of plasma stimulation on natural fractures was studied numerically. It was found that natural fractures can arrest the plasma-generated fractures that propagate from the wellbore to the outer boundaries. However, new fractures may develop in the rock starting from the natural fracture tips. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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26 pages, 22374 KiB

Open AccessArticle

Characteristics, Controlling Factors and Reservoir Quality Implications of Inner Fracture Zones in Buried Hills of Archean Covered Metamorphic Rock in Block 13-2, Bozhong Depression

by Junjie Lu, Xuanlong Shan, Jian Yi, Huiyong Li, Peng Xu, Guoli Hao, Ang Li, Shuai Yin, Shuyue Ren, Chaoyang Liu and Yunqian Shi

Energies 2024, 17(6), 1345; https://doi.org/10.3390/en17061345 - 11 Mar 2024

Cited by 1 | Viewed by 1048

Abstract

Inner fracture zones play a decisive role in the formation of high-quality reservoirs in buried hill reservoirs in covered metamorphic rock. Based on core, sidewall core, thin section, seismic, logging and reservoir physical property data, the fracture development characteristics of the Bozhong 13-2 block buried hill reservoir are described in detail and the controlling factors and the influence on reservoir quality are discussed. The results showed: (1) three groups of tectonic fractures developed in the study area—near-EW-striking, ENE-striking and nearly N–S-striking fractures—were controlled by the early Indosinian thrusting, the late Indosinian to early Yanshanian sinistral strike-slipping and the late Yanshanian late dextral strike-slipping in the Bohai Bay Basin, respectively. The ENE- and nearly-E-W-striking fractures are the most common, and the dip angles of the fractures are mostly between 35° and 75° and thus oblique. (2) The Indosinian-early Yanshanian was the main fracture-forming period, and the dextral strike-slip action in the late Yanshanian was the key to maintaining effective fractures. Imaging logging shows that 97.87% of the fractures are effective fractures. Based on thin section observation, 14.47% of the fractures are unmodified open fractures and 80.37% of the fractures are effective fractures due to reactivation. (3) The late Yanshanian strike-slip fault transformed the deformation adjustment zone formed by the early Indosinian thrust faulting and the core of the fold structure was more conducive to fracture development. The fracture density of a single well located within the deformation adjustment zone and at the core of the fold is between 0.93–1.49 m⁻¹, the fracture density of a single well located only at the core of the fold is between 0.67–0.75 m⁻¹ and that of a single well located at the wing of the fold is between 0.35–0.59 m⁻¹. Diabase dike intrusions promoted the development of local fractures. (4) Fractures promote the migration and accumulation of oil and gas, and the fracture density in the oil layer is between 0.81–2.19 m⁻¹. That in the nonoil layer is between 0.25–1.12 m⁻¹. In addition, fractures not only provide storage space but also effectively improve the reservoir capacity of the inner fracture zones of buried hill reservoirs by concentrating dissolution. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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23 pages, 7087 KiB

Open AccessArticle

Paleotectonic Stress and Present Geostress Fields and Their Implications for Coalbed Methane Exploitation: A Case Study from Dahebian Block, Liupanshui Coalfield, Guizhou, China

by Jilin Wang, Youkun Wang, Xiaozhi Zhou, Wenxin Xiang and Changran Chen

Energies 2024, 17(1), 101; https://doi.org/10.3390/en17010101 - 23 Dec 2023

Cited by 1 | Viewed by 884

Abstract

The macroscopic structural fractures (joints) and geostress distribution characteristics of coal reservoirs are important factors affecting the exploitation of coalbed methane (CBM). In this study, the joints in the sedimentary strata of the Dahebian block in Liupanshui area, Guizhou Province were investigated. Directional coal samples were collected for observation and statistical analysis of coal microfractures, the paleotectonic stress fields of the study area were reconstructed, and the tectonic evolution was elucidated. The geostress distribution characteristics of the target coal seam (coal seam No. 11, P₃l) in the study area were analyzed using the finite element numerical simulation method. The results indicate that the structural evolution of the Dahebian syncline in the study area can be divided into two stages. The Late Jurassic–Early Cretaceous stage (Early Yanshanian) is the first stage. Affected by the sinistral strike slip of the Weining–Ziyun–Luodian (WZL) fault zone, the derived stress field in the study area exhibits maximum principal stress (σ₁) in the NEE–SWW direction. The Late Cretaceous stage (Late Yanshanian) is the second stage. Affected by the dextral strike slip of the WZL fault zone, the derived stress field exhibits σ₁ in the NNW–SSE direction. The folds and faults formed in the first stage were modified by the structural deformation in the second stage. The dominant strikes of joints in the sedimentary strata are found to be in the NW–NNW (300°–360°) and NE (30°–60°) directions, with dip angles mostly ranging from 60° to 90°. The dominant strikes of coal microfractures are in the NW (285°–304°) and NE (43°–53°) directions. The distribution of geostress in the study area is characterized by high levels of geostress in the syncline center, decreasing towards the surrounding periphery. The overall trend of the geostress contour line is similar to the shape of the syncline and is influenced by folds and faults. The σ₁ of coal seam No. 11 is vertical stress. The prediction results show that the joint density of coal seam No. 11 in the block is 36–50 joints/m, and the shape of the joint density contour line is also affected by the axial direction of the Dahebian syncline and the surrounding faults. The variation in coal seam joint density and the control effect of geostress on joints opening or closing affects the permeability of coal reservoirs. The study results provide significant guidance for the exploitation of CBM. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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17 pages, 5246 KiB

Open AccessArticle

Viscoelastic Strains of Palaeozoic Shales under the Burger’s Model Description

by Przemyslaw Michal Wilczynski, Jerzy Cieslik, Andrzej Domonik and Pawel Lukaszewski

Appl. Sci. 2023, 13(19), 10981; https://doi.org/10.3390/app131910981 - 5 Oct 2023

Cited by 1 | Viewed by 959

Abstract

This article presents the results of creep studies of Palaeozoic shales from the Baltic Basin in which the exploitation of shale gas in Poland was planned. Knowledge of instantaneous and long-term properties investigated in triaxial stress conditions is important from the point of view of exploitation techniques related to hydraulic fracturing. Rheological phenomena also play an important role in the analysis of the initial stress in shales, the knowledge of which is indispensable in the hydraulic fracturing process. The tests were carried out on samples representing four siltstone–claystone lithostratigraphic units occurring in the Baltic Basin. The studies and analyses were aimed at determining the character of creep in shales, selection of the appropriate rheological model for the analyzed rocks, and determination of the threshold of the linear creep under triaxial compression conditions. An original approach together with analysis results are presented here, which enable the separation and monitoring of shear and volume creep effects, and on this basis, the determination of the significance of the contribution of volume creep in the entire creep process. A relatively simple methodology for determination of the parameters of the Burgers model using this division is presented. The original value of the article is also due to the test results themselves and the parameter values of the analyzed model for triaxial creep of shales, which are not numerous in the literature. The investigations were performed at various loading levels in relation to the triaxial strength of the shales. Depending on the load, at its low values up to 0.7 (σ₁ − σ₃)_max, creep had a determined character and did not show features of progressive creep. The linear creep threshold was also analyzed in this range. The loading level of 0.7 (σ₁ − σ₃)_max was the limit of linear creep. Exceeding this load resulted in the loss of the linear character of creep, which in consequence lead to the subsequent third creep phase ending with rock damage. Parameters of the Burger’s model for gas shales from the Baltic Basin (northern Poland) were identified. There are significant differences in the behavior of shales depending on the lithostratigraphic unit from which the samples were collected. The mineral composition of the shales also influenced their behavior. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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31 pages, 28254 KiB

Open AccessArticle

Reservoir Characteristics and Development Model of Subaqueous Pyroclastic Rocks in a Continental Lacustrine Basin: A Case Study of the Chaganhua Subsag in the Changling Fault Depression, Songliao Basin

by Yunqian Shi, Jian Yi, Weihua Bian, Xuanlong Shan, Yuhu Liu, Guoli Hao, Ang Li, Qinglei Leng, Junjie Lu, He Pang and Ruichen Zhang

Energies 2023, 16(13), 4968; https://doi.org/10.3390/en16134968 - 26 Jun 2023

Viewed by 1618

Abstract

Industrial oil and gas eruptions underwater have been found in the pyroclastic rocks of the Huoshiling Formation in the continental lacustrine basin of the Changling fault depression, Songliao Basin. This paper investigates the reservoir space characteristics, physical characteristics, and pore structure differences of subaqueous pyroclastic reservoirs in the Huoshiling Formation, and the causes of physical property differences of different types of reservoirs and their formation and evolution processes are analyzed. (1) The content of volcanic glass in tuff is higher, the reservoir space is dominated by devitrification pores and dissolution pores, and the coarser the grain size, the more favorable the physical properties, with larger pore sizes and higher porosities. The content of clay minerals in sedimentary tuff is high, the pores between clay minerals are the main pores, and the physical properties of sedimentary tuff are poor. The content of soluble components such as feldspar, debris, and laumontite is high in tuffaceous sandstone, which is dominated by dissolution pores. (2) Primary pores are not developed in the pyroclastic reservoirs in the study area, and the reservoirs are relatively dense, with an average porosity of 2.43% and an average permeability of 0.076 mD. The coarse-grained tuff has the highest porosity, followed by tuffaceous sandstone and fine-grained tuff, and the sedimentary tuff has the least favorable physical properties. (3) Devitrification was an important cause of the high-porosity and ultralow permeability of tuff reservoirs. Two oil and gas charges in the middle diagenetic stage led to the organic acid dissolution of rocks. In addition, fractures can provide migration channels for organic acids and deep hydrothermal fluids, leading to late dissolution, and can connect various scattered dissolution pores to improve the effectiveness of the reservoir space. (4) Coarse-grained tuff reservoirs that developed in the proximal facies are favorable targets for hydrocarbon exploration. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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26 pages, 6134 KiB

Open AccessArticle

Effect of Sedimentary Facies Characteristics on Deep Shale Gas Desserts: A Case from the Longmaxi Formation, South Sichuan Basin, China

by Meng Wang, Jiang He, Shu Liu, Chunlin Zeng, Song Jia, Zhou Nie, Shengxiu Wang, Wei Wang and Chun Zhang

Minerals 2023, 13(4), 476; https://doi.org/10.3390/min13040476 - 28 Mar 2023

Cited by 2 | Viewed by 1850

Abstract

Shale gas is one of the hot spots of energy development. Due to the strong heterogeneity and low physical properties of shale gas reservoirs, and the complex influencing factors of pore development, it is necessary to conduct a comprehensive analysis of the control factors of high-quality reservoirs. The sedimentary characteristics, mineral composition, pore structure and controlling factors of high quality reservoir development are studied on the basis of thin section, scanning electron microscopy (SEM) and QEMSCAN analysis, X-ray diffraction (XRD), total organic carbon (TOC), Nano-CT scanning and Low-pressure N₂ adsorption (N₂GA) analysis on shale samples from the Longmaxi Formation in South Sichuan Basin. The results show the following: (1) According to lithology, sedimentary structure, organic carbon content and mineral composition, six sedimentary microfacies can be divided. (2) Organic matter pores are developed in organic-rich siliceous shale and organic-rich silty shale at the bottom of the first member of the Longmaxi formation, with average porosity of more than 5% and permeability of more than 2 × 10⁻³ μm², which is conducive to the formation of high-quality shale gas reservoirs. (3) The contents of siliceous and TOC are positively correlated with porosity and specific surface area, while the contents of carbonate and clay minerals are negatively correlated with reservoir quality. (4) In the first member of the Longmaxi formation, the sedimentary water depth becomes shallower from bottom to top, and the sedimentary environment changes from a reduction to an oxidation environment. The contents of siliceous and organic matter decrease, while the contents of clay minerals and carbonate minerals show the opposite trend. The difference in sedimentary microfacies affects the distribution of mineral and organic matter and controls the heterogeneity of the shale reservoir. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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12 pages, 5189 KiB

Open AccessArticle

The Role of Fluid Overpressure on the Fracture Slip Mechanism Based on Laboratory Tests That Stimulating Reservoir-Induced Seismicity

by Yujie Zhu, Chen Xu, Danqing Song, Xiaoli Liu and Enzhi Wang

Appl. Sci. 2023, 13(6), 3382; https://doi.org/10.3390/app13063382 - 7 Mar 2023

Viewed by 1379

Abstract

A critically stressed fracture will slide in response to the increase in fluid pressure inside the fracture while impounding, which will trigger induced seismicity. The mechanism of fluid overpressure is regarded as a significant factor in the reaction of the fracture slip after water diffusing. This study uses a shearing test with a cylinder of granite, with 100 mm height and 50 mm diameter, under the condition of hydraulic-mechanic (HM) coupling to figure out how fluid overpressure alters the mechanical behavior of the critically stressed fracture. The cyclic water pressurization simulates periodical impounding in the water reservoir. Results show that several slip events happen when water pressure continues to rise higher than the stable state. The change of roughness also indicates the deterioration of the fracture surface while sliding. According to the results, we conclude that the difference between inlet pressure and outlet pressure leads to an overpressure of the fracture, promoting a series of slips and induced seismicity. Hydraulic energy is introduced to explain the relationship between the input and output energy, which is also strong evidence to illustrate that fluid overpressure is a crucial mechanism in reservoir-induced seismicity. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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16 pages, 6023 KiB

Open AccessArticle

Evaluating the Degree of Tectonic Fracture Development in the Fourth Member of the Leikoupo Formation in Pengzhou, Western Sichuan, China

by Qiang Xie, Gao Li, Xu Yang and Hongli Peng

Energies 2023, 16(4), 1797; https://doi.org/10.3390/en16041797 - 11 Feb 2023

Cited by 2 | Viewed by 2185

Abstract

The extent of fracture development is associated with the degree of enrichment of a natural gas reservoir and its productivity. Based on numerical simulation results of the paleotectonic stress field, a set of evaluation methods for determining the degree of development of reservoir tectonic fractures were established using rock rupture criteria. Taking the fourth member of the Leikoupo Formation in the Pengzhou area of western Sichuan as an example, a finite element (FE) method was employed to simulate the paleo-tectonic stress field during the period of fracture development, and the degree of tectonic fracture development was further evaluated using the above methods. The results indicated that effective fractures were created in the Himalayan period. In this time, mainly NE–NEE and nearly E–W strike tectonic fractures were developed in the target layer. The fractures were mainly low-angle and oblique fractures, while the high-angle fractures were less developed. According to the integrative fracture index (F), five typical fracture development areas were determined: the fault zone, and the northern, eastern, southeastern, and central regions of the study area. The reliability of the fracture prediction results was verified using fracture distribution statistics and gas production test results. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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21 pages, 8765 KiB

Open AccessArticle

Reservoir Characteristics and Their Controlling Factors in Siliceous Shales of the Upper Permian Dalong Formation, Western Hubei Province, South China

by Ke Duan, Tong Xie, Yi Wang, Yanlin Zhang, Wanzhong Shi and Yongchao Lu

Appl. Sci. 2023, 13(3), 1434; https://doi.org/10.3390/app13031434 - 21 Jan 2023

Cited by 1 | Viewed by 1671

Abstract

To evaluate the reservoir characteristics of siliceous shale in the Dalong Formation within the late Permian intra-platform rift trough in Western Hubei (China), we studied a drill core from well ED-2 in Western Hubei. To analyze the physical characteristics, pore structure, methane adsorption performance, and their influences on the siliceous shale reservoir, we performed X-ray diffraction, total organic carbon (TOC) content, vitrinite reflectance (R_o, indicating thermal evolution), total porosity and permeability, field emission scanning electron microscopy, CO₂ and N₂ physical adsorption, and methane isothermal adsorption analyses, among others. Our results show that the Dalong Formation in Western Hubei is an organic-rich (2.6–14.3 wt.%), highly thermally evolved (R_o = 2.59–2.76%), siliceous shale containing mainly type-I and type-II₁ organic matter. The Dalong siliceous shale has low porosity and permeability and belongs to a larger reservoir with low horizontal permeability (0.002–335.209 mD) and porosity (1.2–7.8%). Pores in the shale are mainly organic, inorganic, and microfractures; the organic pores are very developed. The pore volume and specific surface area of the shale are mainly due to micropores and mesopores and are positively correlated with TOC and clay mineral contents and weakly negatively correlated with quartz and carbonate contents. The micropores and mesopores are well developed, improving the methane adsorption capacity, which, in turn, is strongly positively correlated with TOC content. Comprehensive analysis shows that the high organic matter content of the Dalong siliceous shale has the greatest influence on its pore structure; the many organic pores generated after hydrocarbon generation have controlled the development of micropores and mesopores, which is conducive to the adsorption and storage of shale gas. The development of brittle minerals resistant to compaction, such as siliceous minerals, helps preserve organic pores. This study is informative for basin-scale petroleum system investigations, which are essential for understanding oil and gas exploration possibilities and regional petroleum systems. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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Open AccessArticle

Expansive Soil Stabilization with Lime, Cement, and Silica Fume

by Ahmed S. A. Al-Gharbawi, Ahmed M. Najemalden and Mohammed Y. Fattah

Appl. Sci. 2023, 13(1), 436; https://doi.org/10.3390/app13010436 - 29 Dec 2022

Cited by 27 | Viewed by 4656

Abstract

The type of soil known as expansive soil is capable of changing its volume through swelling and contracting. These types of soils are mostly composed of montmorillonite, a mineral with the capacity to absorb water, which causes the soil to heave by increasing its volume. Due to their capacity to contract or expand in response to seasonal fluctuations in the water content, these expansive soils might prove to be a significant risk to engineering structures. Many studies have dealt with swelling soils and investigated the behavior of these soils, as well as their improvement. In this study, three percentages of lime, cement, and silica fume (5, 7, 9%) are used to stabilize the expansive soil, and the work is divided into two sections: the first is using a consolidation test to record the free swell and swell pressure for the untreated and treated soils; in the second part, the grouting technique is utilized as a process that can be applied in the field to maintain the improvement in the bearing capacity. It is concluded that the soil stabilized with different percentages of lime, cement, and silica fume exhibits a decrease in both free swell and swelling pressure by approximately 65% and 76%, respectively, as compared with untreated soil. The soil grouted with silica fume increases the bearing capacity of footings resting on the grouted soil by approximately 64% to 82% for the soil treated with 5% and 9% silica fume, respectively, as compared with untreated soil. Full article

(This article belongs to the Topic Geomechanics and Engineering Evaluation of Fractured Oil and Gas Reservoirs)

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