Effect of acidizing treatment on microstructures and mechanical properties of shale

Lu, Cong; Ma, Li; Guo, Jianchun; Xiao, Senwen; Zheng, Yunchuan; Yin, Chuancun

doi:10.1016/j.ngib.2019.10.007

Cited by 12 publications

(3 citation statements)

References 3 publications

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“…Sand and mud are reversed; mud has a silt size and silt has a mud size. Therefore, the siltstone formed via storms can intercalate with poorer physical properties than mudstone (Lu et al, 2020).…”

Section: Sand-scale Mud Clastic Common In Sandstones Storm Depositsmentioning

confidence: 99%

Discovery and significance of tempestites and storm deposits in the Qingshankou Formation of the Gulong Sag, northeastern China

Zhong²,

Sun³

2023

Front. Earth Sci.

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The Qingshankou Formation in the Gulong Sag has attracted significant attention due to its rich shale oil reserves. However, several fundamental geological problems associated with shale from the Qingshankou Formation remain unresolved. The Qingshankou Formation in the Gulong Sag is a set of deep-lake and semi-deep-lake fine-grained deposits primarily composed of mudstone and shale. Recent studies have shown that tempestites and storm deposits commonly occur in the Qingshankou Formation. Fine liquefaction veins often occur at the bottom of the tempestite, indicating that storm-shaking liquefaction is expected in the swale structure. Meanwhile, the mudstone and shales primarily have a sand structure with fine grain size, indicating that the environment is exposed to an undercurrent activity, with a water flow velocity of 20–55 cm s−1. Unlike previous studies, we posit that the ancient water depth was only 20–30 m or shallower. These phenomena have significance for understanding the formation environment and diagenetic process of shale in the first member of the Qingshankou Formation, which provides a reference for oil and gas exploration and development.

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Section: Sand-scale Mud Clastic Common In Sandstones Storm Depositsmentioning

confidence: 99%

Discovery and significance of tempestites and storm deposits in the Qingshankou Formation of the Gulong Sag, northeastern China

Zhong²,

Sun³

2023

Front. Earth Sci.

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“…The 20 shale samples were cut into standard cores (1 inch diameter, 2 inch length) using RTR-1000 type equipment for rock mechanics experiments at reservoir temperature and pressure conditions (confining pressure of 40 MPa, temperature of 70 °C) (Lu et al, 2019b). As shown in Figure 2, the experimental results show that the Young's modulus of shale from the Longmaxi Formation is between 4438.5 and 27,285.1 MPa, with an average value of 16,153.3 MPa, and a Poisson's ratio of 0.124 to 0.446, with an average value of 0.27.…”

Section: Laboratory Experimentsmentioning

confidence: 99%

Novel method and case study of a deep shale fracability evaluation based on the brittleness index

Guo

et al. 2021

Energy Exploration & Exploitation

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Deep shale has gradually become a focus point for unconventional natural gas exploration and development in China and even the world. The key to deep shale development is the fracability evaluation of a reservoir; conventional evaluation methods cannot provide accurate evaluations of deep shale fracability under high confining pressures. In this study, experimental methods are used to obtain the mechanical parameters, mineral composition, and stress–strain characteristics of shale. The fracture complexity coefficient based on the fractal dimension and fracture angle is defined by analyzing the fracture morphology of shale samples. Using the rock fracturing complexity as an index, the weight coefficients of different factors for the shale fracture morphology are obtained, thus establishing a new evaluation model for the deep shale brittleness index. The results show that the Young's modulus, dilatancy angle, and peak strain are the main factors affecting the complexity of shale fractures. The gray correlation theory is used to calculate the weights of various factors in the model. The weight coefficients of the Young's modulus, dilatancy angle, and peak strain on the rock brittleness index are 0.262, 0.353, and 0.385, respectively. Based on this, a novel method for evaluating the fracability of deep shale using the brittleness index is proposed. The fracability index of the horizontal section of the deep shale gas well in this area was calculated, and the location of the fracturing perforation cluster was optimized accordingly. This technology has been successfully applied in more than 10 deep shale gas wells in the southern Sichuan Basin, effectively reducing the fracturing pressure by 5–10 MPa, increasing the average daily production of a single well by 15.3 × 104 m3. This paper proposes a novel fracability evaluation method for deep shale based on the brittleness index, which provides a reference for optimizing deep shale fracturing design.

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“…The above calculation method for permeability is based on single capillary analysis, and average capillary radius is selected to evaluate the permeability. Frankly speaking, it is the "average permeability" within a certain reservoir area that largely ignores the impact of micro-details on the reservoir as a whole and fails to fully consider the significance of micro-fractures as channeling channels and the reality of micro-flow inrush caused by the non-uniform distribution of pore radius values [2,[19][20][21][22]. In this study, we paid full attention to these existing problems in previous studies.…”

Section: Introductionmentioning

confidence: 99%

Characterizing the Microscopic Anisotropic Permeabilities of Tight Oil Reservoirs Impacted by Heterogeneous Minerals

Wang

Wei

et al. 2022

Energies

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This study aimed to reveal the anisotropic permeabilities of tight oil reservoirs impacted by heterogeneous minerals. SEM imaging, image processing, fractal calculation, microscopic reservoir modeling, and visual flow simulation were carried out to investigate the above problems. Results show that the variation coefficient of two-dimensional permeability for the studied tight reservoir samples ranges from 0.09 to 0.95, with an average value of 0.68. The penetration coefficient ranges from 1.16 to 2.64, with an average value of 2.13. The ratio of maximum to minimum permeability is between 1.25 and 7.67, with an average value of 5.62. The fluid flow in tight reservoirs has significant anisotropy comprising dominant flow through conductive channels. Flow in tight oil reservoirs tends to involve minor hydraulic fracturing with no proppant.

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Effect of acidizing treatment on microstructures and mechanical properties of shale

Cited by 12 publications

References 3 publications

Discovery and significance of tempestites and storm deposits in the Qingshankou Formation of the Gulong Sag, northeastern China

Discovery and significance of tempestites and storm deposits in the Qingshankou Formation of the Gulong Sag, northeastern China

Novel method and case study of a deep shale fracability evaluation based on the brittleness index

Characterizing the Microscopic Anisotropic Permeabilities of Tight Oil Reservoirs Impacted by Heterogeneous Minerals

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