Simulation of tectonic stress field and prediction of fracture distribution in shale reservoir

In this paper, a finite element-based fracture prediction method for shale reservoirs was proposed using geostress field simulations, uniaxial and triaxial compression deformation tests, and acoustic emission geostress tests. Given the characteristics of tensile and shear fractures mainly developed in organic-rich shales, Griffith and Coulomb – Mohr criteria were used to calculate shale reservoirs' tensile and shear fracture rates. Furthermore, the total fracture rate of shale reservoirs was calculated based on the ratio of tension and shear fractures to the total number of fractures. This method has been effectively applied in predicting fracture distribution in the Lower Silurian Longmaxi Formation shale reservoir in southeastern Chongqing, China. This method provides a new way for shale gas sweet spot optimization. The simulation results have a significant reference value for the design of shale gas horizontal wells and fracturing reconstruction programs.

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Factors Controlling Shale Reservoirs and Development Potential Evaluation: A Case Study

Geofluids ◽

10.1155/2021/6661119 ◽

2021 ◽

Vol 2021 ◽

pp. 1-13

Author(s):

Chao Luo ◽

Hun Lin ◽

Yujiao Peng ◽

Hai Qu ◽

Xiaojie Huang ◽

...

Keyword(s):

Shale Gas ◽

Mineral Content ◽

Gas Content ◽

Longmaxi Formation ◽

Development Potential ◽

Reservoir Characteristics ◽

Lower Silurian ◽

Single Well ◽

Shale Reservoir ◽

Shale Reservoirs

The shale of the Lower Silurian Longmaxi Formation is an important gas-producing layer for shale gas development in southern China. This set of shale reservoir characteristics and shale gas development potential provide an important foundation for shale gas development. This study takes wellblock XN111 in the Sichuan Basin, China, as an example and uses X-ray diffraction (XRD), scanning electron microscopy (SEM), isothermal adsorption, and other techniques to analyze the shale reservoir characteristics of the Lower Silurian Longmaxi Formation. The results show that the Lower Silurian Longmaxi Formation was deposited in a deep-water shelf environment. During this period, carbonaceous shale and siliceous shale characterized by a high brittle mineral content ( quartz > 40 wt . % , carbonate mineral > 10 wt . % ) and a low clay mineral content (<30 wt.%, mainly illite) were widely deposited throughout the region. The total organic carbon (TOC) content reaches up to 6.07 wt.%, with an average of 2.66 wt.%. The vitrinite reflectance is 1.6–2.28%, with an average of 2.05%. The methane adsorption capacity is 0.84–4.69 m3/t, with an average of 2.92 m3/t. Pores and fractures are developed in the shale reservoirs. The main reservoir space is composed of connected mesopores with an average porosity of 4.78%. The characteristics and development potential of the shale reservoirs in the Lower Silurian Longmaxi Formation are controlled by the following factors: (1) the widespread deep-water shelf deposition in wellblock XN111 was a favorable environment for the development of high-quality shale reservoirs with a cumulative thickness of up to 50 m; (2) the high TOC content enabled the shale reservoir to have a high free gas content and a high adsorptive gas storage capacity; and (3) the shale’s high maturity or over maturity is conducive to the development of pores and fractures in the organic matter, which effectively improves the storage capacity of the shale reservoirs. The reservoir characteristic index was constructed using the high-quality shale’s thickness, gas content, TOC, fracture density, and clay content. Using production data from shale gas wells in adjacent blocks, a mathematical relationship was established between the Estimated Ultimate Recovery (EUR) of a single well and the Reservoir Characteristics Index (Rci). The EUR of a single well in wellblock XN111 was estimated.

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Experimental Study on Shut-in-Time Optimization for Multi-Fractured Horizontal Wells in Shale Reservoirs

10.2118/205254-ms ◽

2022 ◽

Author(s):

Liang Tao ◽

Jianchun Guo ◽

Zhongbo Wang ◽

Yi Liu ◽

Yuhang Zhao ◽

...

Keyword(s):

Clay Mineral ◽

Shale Gas ◽

Mineral Content ◽

Type I ◽

Diffusion Experiment ◽

Ion Diffusion ◽

Water Imbibition ◽

Study Results ◽

Shale Reservoir ◽

Shale Reservoirs

Abstract The optimization of shut-in-time in shale gas well is an important factor affecting the production of single well after volume fracturing. In this study, a new method for determining the optimal shut-in-time considering clay mineral content and ion diffusion concentration was proposed. First, a novel water spontaneous imbibition apparatus under the conditions of formation temperature and confining pressure was designed. Then, the water imbibition satuation of 15 shale samples from the Longmaxi Formation (LF) of the Sichuan Basin were measured to quantitatively evaluate the water imbibition ability and classify reservoir types. Finally, the salt ion concentration diffusion experiment was carried out to optimize the shut-in-time of different types of shale reservoirs. The experimental results shown that the clay mineral content was the key factor affecting water wettability of shale, the shale reservoirs can be divided into two types and the critical value of clay mineral content was about 40%. Based on the law of salt ion diffusion in shale, the initiation time of micro-fractures induced by shale hydration was about 10-15 days. Under the experimental conditions, the optimal shut-in time of type I shale reservoir and type II shale reservoir were about 20 days and 15 days respectively. The average daily gas production has increased from 15.6×104 m3/day to 25.1×104 m3/day. The study results can provide scientific basis for the optimization of flowback regime of shale gas resrvoirs.

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Types and Quantitative Characterization of Microfractures in the Continental Shale of the Da’anzhai Member of the Ziliujing Formation in Northeast Sichuan, China

Minerals ◽

10.3390/min11080870 ◽

2021 ◽

Vol 11 (8) ◽

pp. 870

Author(s):

Zhujiang Liu ◽

Hengyuan Qiu ◽

Zhenxue Jiang ◽

Ruobing Liu ◽

Xiangfeng Wei ◽

...

Keyword(s):

Organic Matter ◽

Shale Gas ◽

Gas Flow ◽

Pore Space ◽

Three Dimensional ◽

Total Pore Volume ◽

Ct Scanning ◽

Nitrogen Adsorption ◽

Tectonic Stress ◽

Shale Reservoirs

A number of wells in the Sichuan Basin of China have tested industrial gas flow pressure arising from the shale of the Da’anzhai section of the Ziliujing Formation, revealing good exploration potential. Microfractures in shales affect the enrichment and preservation of shale gas and are important storage spaces and seepage channels for gas. In order to increase productivity and to reduce the risks associated with shale gas exploration, the types, connectivity, and proportion of microfractures in the Da’anzhai Member have been studied in this work by core and thin section observations, micro-CT, scanning electron microscopy, nitrogen adsorption, and high-pressure mercury intrusion. The results show that four types of fractures have developed in the shale of the Da’anzhai section: microfractures caused by tectonic stress, diagenetic shrinkage fractures of clay minerals, marginal shrinkage fractures of organic matter, and microfractures inside mineral particles. Among these, structural fractures and organic matter contraction fractures are the main types and are significant for shale reservoirs and seepage. The structural microfractures are mainly opened and are well-developed in the shale, with a straight shape, mainly between bedding, with the fracture surface being curved, fully opened, and mainly tensile. Organic matter fractures often develop on the edge of the contact between organic matter and minerals, presenting a slit-like appearance. The fractures related to bedding in the shale are particularly developed, with larger openings, wider extensions, intersecting and expanding, and forming a three-dimensional interconnected pore-fracture system. Based on image recognition, generally speaking, microfractures account for about 20% of the total pore volume. However, the degree of the microfractures’ development varies greatly, depending upon the structural environment, with the proportion of microfractures in fault-wrinkle belts and high-steep zones reaching 40% to 90% of the total pore space. On the other hand, micro-fractures in areas with underdeveloped structures account for about 10% of the total pore space.

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Prediction of Shale Gas Reservoirs Using Fluid Mobility Attribute Driven by Post-Stack Seismic Data: A Case Study from Southern China

Applied Sciences ◽

10.3390/app11010219 ◽

2020 ◽

Vol 11 (1) ◽

pp. 219

Author(s):

Jing Zeng ◽

Alexey Stovas ◽

Handong Huang ◽

Lixia Ren ◽

Tianlei Tang

Keyword(s):

Shale Gas ◽

Seismic Data ◽

Spectral Decomposition ◽

Southern China ◽

Gas Reservoirs ◽

Seismic Attribute ◽

Longmaxi Formation ◽

Shale Gas Reservoirs ◽

The Sichuan Basin ◽

Shale Reservoirs

Paleozoic marine shale gas resources in Southern China present broad prospects for exploration and development. However, previous research has mostly focused on the shale in the Sichuan Basin. The research target of this study is expanded to the Lower Silurian Longmaxi shale outside the Sichuan Basin. A prediction scheme of shale gas reservoirs through the frequency-dependent seismic attribute technology is developed to reduce drilling risks of shale gas related to complex geological structure and low exploration level. Extracting frequency-dependent seismic attribute is inseparable from spectral decomposition technology, whereby the matching pursuit algorithm is commonly used. However, frequency interference in MP results in an erroneous time-frequency (TF) spectrum and affects the accuracy of seismic attribute. Firstly, a novel spectral decomposition technology is proposed to minimize the effect of frequency interference by integrating the MP and the ensemble empirical mode decomposition (EEMD). Synthetic and real data tests indicate that the proposed spectral decomposition technology provides a TF spectrum with higher accuracy and resolution than traditional MP. Then, a seismic fluid mobility attribute, extracted from the post-stack seismic data through the proposed spectral decomposition technology, is applied to characterize the shale reservoirs. The application result indicates that the seismic fluid mobility attribute can describe the spatial distribution of shale gas reservoirs well without well control. Based on the seismic fluid mobility attribute section, we have learned that the shale gas enrich areas are located near the bottom of the Longmaxi Formation. The inverted velocity data are also introduced to further verify the reliability of seismic fluid mobility. Finally, the thickness map of gas-bearing shale reservoirs in the Longmaxi Formation is obtained by combining the seismic fluid mobility attribute with the inverted velocity data, and two favorable exploration areas are suggested by analyzing the thickness, structure, and burial depth. The present work can not only be used to evaluate shale gas resources in the early stage of exploration, but also help to design the landing point and trajectory of directional drilling in the development stage.

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Factors affecting reorientation of hydraulically induced fracture during fracturing with oriented perforations in shale gas reservoirs

Frattura ed Integrità Strutturale ◽

10.3221/igf-esis.58.01 ◽

2021 ◽

Vol 15 (58) ◽

pp. 1-20

Author(s):

Qingchao Li ◽

Liang Zhou ◽

Zhi-Min Li ◽

Zhen-Hua Liu ◽

Yong Fang ◽

...

Keyword(s):

Shale Gas ◽

Injection Rate ◽

Single Fracture ◽

Fluid Viscosity ◽

Fracture Conductivity ◽

Factors Affecting ◽

Controllable Factors ◽

Initiation Pressure ◽

Shale Reservoirs ◽

Induced Fractures

Hydraulic fracturing with oriented perforations is an effective technology for reservoir stimulation for gas development in shale reservoirs. However, fracture reorientation during fracturing operation can affect the fracture conductivity and hinder the effective production of shale gas. In the present work, a numerical simulation model for investigating fracture reorientation during fracturing with oriented perforations was established, and it was verified to be suitable for all investigations in this paper. Based on this, factors (such as injection rate and fluid viscosity) affecting both of initiation and reorientation of the hydraulically induced fractures were investigated. The investigation results show that the fluid viscosity has little effect on initiation pressure of hydraulically induced fracture during fracturing operation, and the initiation pressure is mainly affected by perforation azimuth, injection rate and the stress difference. Moreover, the investigation results also show that perforation azimuth and difference between two horizontal principle stresses are the two most important factors affecting fracture reorientation. Based on the investigation results, the optimization of fracturing design can be achieved by adjusting some controllable factors. However, the regret is that the research object herein is a single fracture, and the interaction between fractures during fracturing operation needs to be further explored.

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The Determination of Stress Reorientation in Shale Gas Reservoirs with Complex Natural Fracture Distribution

10.15530/ap-urtec-2021-208284 ◽

2021 ◽

Author(s):

Jia He ◽

Yanli Pei ◽

Kamy Sepehrnoori

Keyword(s):

Shale Gas ◽

Natural Fracture ◽

Gas Reservoirs ◽

Shale Gas Reservoirs ◽

Fracture Distribution

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Brittleness Evaluation in Shale Gas Reservoirs and Its Influence on Fracability

Energies ◽

10.3390/en13020388 ◽

2020 ◽

Vol 13 (2) ◽

pp. 388 ◽

Cited By ~ 2

Author(s):

Yapei Ye ◽

Shuheng Tang ◽

Zhaodong Xi

Keyword(s):

Shale Gas ◽

Evaluation Method ◽

Triaxial Compression ◽

Horizontal Stress ◽

Brittleness Index ◽

X Ray Diffraction ◽

Elastic Parameters ◽

Gas Reservoirs ◽

Shale Gas Reservoirs ◽

Minimum Horizontal Stress

The brittleness index (BI) is a key parameter used to identify the desirable fracturing intervals of shale gas reservoirs. Its correlation with fracability is still controversial. There have been a variety of methods proposed that can estimate BI. The brittleness evaluation method based on stress-strain curves according to the energy-balanced law is the most suitable and reliable in this study. Triaxial compression test, optical microscopy and scanning electron microscopy (SEM) observation, and X-ray diffraction analysis (XRD) were performed on nine drill core samples from well SY3 located in the peripheral regions of Sichuan Basin, China. These tests further evaluated several commonly used methods (brittleness indices based on rock elastic parameters, rock mineral compositions) and determined the relationship between brittleness, rock elastic parameters, and the content of minerals. The results obtained indicate that for sedimentary rocks, a higher Young’s modulus reduces the brittleness of rock, and Poisson’s ratio weakly correlates with brittleness. Excessive amounts of quartz or carbonate minerals can increase the cohesiveness of rock, leading to poor brittleness. Furthermore, the most suitable fracturing layers possess a high brittleness index and low minimum horizontal stress.

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A FRACTAL PERMEABILITY MODEL FOR REAL GAS IN SHALE RESERVOIRS COUPLED WITH KNUDSEN DIFFUSION AND SURFACE DIFFUSION EFFECTS

Fractals ◽

10.1142/s0218348x20500176 ◽

2020 ◽

Vol 28 (01) ◽

pp. 2050017 ◽

Cited By ~ 2

Author(s):

TAO WU ◽

SHIFANG WANG

Keyword(s):

Fractal Dimension ◽

Surface Diffusion ◽

Shale Gas ◽

Gas Transport ◽

Fractal Theory ◽

Knudsen Diffusion ◽

Apparent Permeability ◽

Permeability Model ◽

Real Gas ◽

Shale Reservoirs

A better comprehension of the behavior of shale gas transport in shale gas reservoirs will aid in predicting shale gas production rates. In this paper, an analytical apparent permeability expression for real gas is derived on the basis of the fractal theory and Fick’s law, with adequate consideration of the effects of Knudsen diffusion, surface diffusion and flexible pore shape. The gas apparent permeability model is found to be a function of microstructural parameters of shale reservoirs, gas property, Langmuir pressure, shale reservoir temperature and pressure. The results show that the apparent permeability increases with the increase of pore area fractal dimension and the maximum effective pore radius and decreases with an increase of the tortuosity fractal dimension; the effects of Knudsen diffusion and surface diffusion on the total apparent permeability cannot be ignored under high-temperature and low-pressure circumstances. These findings can contribute to a better understanding of the mechanism of gas transport in shale reservoirs.

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