“…Marine shale samples were collected from the Lower Silurian Longmaxi Formation (S 1 l) in the Jiaoshiba area of Sichuan Basin in China. The shale gas field in Jiaoshiba area is the first and the largest commercially developed shale reservoir in China. − The target formations are the Upper Ordovician Wufeng–Lower Silurian Longmaxi (O 3 w-S 1 l) shales in Sichuan Basin. These shale systems, deposited in a deep-water shelf environment, are lithologically complex and mostly contain type I kerogen. − Generally, three kinds of main lithofacies were observed in these Longmaxi shales according to the mineralogy: siliceous shales, argillaceous shales, and their mixed lithofacies. , In this study, two set of cored samples were collected from two gas wells drilled through the Jiaoshiba shale systems.…”
Section: Materials
and Experimental Methodsmentioning
Understanding
the penetration and retention of fracturing water
in geological systems is important for hydrocarbon extraction and
fluid disposal during hydraulic fracturing. This paper explores the
imbibition of fracturing water and its penetration profiles on shales
from Sichuan Basin, China. Water imbibition experiments were performed
on the collected shales with a variety of mineralogical compositions
and pore structure characteristics. Sorptivity, quantitatively characterizing
water imbibition capacity, was evaluated and its dependence on rock
fabric and mineralogical compositions was examined. Then, a nonlinear
diffusion model is presented to simulate the capillary flow during
the water imbibition process according to the unsaturated flow theory.
The solution of this model offers quantitative information about water
penetration and distribution in shales. The water sorptivity of shales
ranges from 0.1 to 1.8 × 10–6 m/s0.5. Water imbibed by shales is mainly along the shale lamination and
bedding. The strong mineral alignment also contributes to sorptivity
because of the preferential transport pathways. Shales with developed
microfracture networks have higher sorptivity. Nevertheless, water
penetration into shales is commonly less than 5 cm during the typical
shut-in period after fracturing operations. The fracturing fluid loss
is related to the development of microfracture networks and the fracture
width. The complex fracture networks with a small fracture width result
in low water recovery.
“…Marine shale samples were collected from the Lower Silurian Longmaxi Formation (S 1 l) in the Jiaoshiba area of Sichuan Basin in China. The shale gas field in Jiaoshiba area is the first and the largest commercially developed shale reservoir in China. − The target formations are the Upper Ordovician Wufeng–Lower Silurian Longmaxi (O 3 w-S 1 l) shales in Sichuan Basin. These shale systems, deposited in a deep-water shelf environment, are lithologically complex and mostly contain type I kerogen. − Generally, three kinds of main lithofacies were observed in these Longmaxi shales according to the mineralogy: siliceous shales, argillaceous shales, and their mixed lithofacies. , In this study, two set of cored samples were collected from two gas wells drilled through the Jiaoshiba shale systems.…”
Section: Materials
and Experimental Methodsmentioning
Understanding
the penetration and retention of fracturing water
in geological systems is important for hydrocarbon extraction and
fluid disposal during hydraulic fracturing. This paper explores the
imbibition of fracturing water and its penetration profiles on shales
from Sichuan Basin, China. Water imbibition experiments were performed
on the collected shales with a variety of mineralogical compositions
and pore structure characteristics. Sorptivity, quantitatively characterizing
water imbibition capacity, was evaluated and its dependence on rock
fabric and mineralogical compositions was examined. Then, a nonlinear
diffusion model is presented to simulate the capillary flow during
the water imbibition process according to the unsaturated flow theory.
The solution of this model offers quantitative information about water
penetration and distribution in shales. The water sorptivity of shales
ranges from 0.1 to 1.8 × 10–6 m/s0.5. Water imbibed by shales is mainly along the shale lamination and
bedding. The strong mineral alignment also contributes to sorptivity
because of the preferential transport pathways. Shales with developed
microfracture networks have higher sorptivity. Nevertheless, water
penetration into shales is commonly less than 5 cm during the typical
shut-in period after fracturing operations. The fracturing fluid loss
is related to the development of microfracture networks and the fracture
width. The complex fracture networks with a small fracture width result
in low water recovery.
“…Exploration and drilling results suggest that the Longmaxi Formation in the Weirong block is generally subject to a high pressure, and the pore fluid pressure coefficient varies between ~ 1.94 and 2.05 28 , which provides suitable conditions for shale gas preservation but also causes great difficulties in fracturing development of shale gas. Figure 1 ( a ) Location of the Weirong area in the Sichuan Basin (modified after Nie et al 29 ); ( b ) Sampling well location in the Weirong block (modified after Xiong 30 ); ( c ) Stratigraphic information of the Longmaxi Formation (modified after Xu et al 31 ). …”
Section: Geological Settingmentioning
confidence: 99%
“… ( a ) Location of the Weirong area in the Sichuan Basin (modified after Nie et al 29 ); ( b ) Sampling well location in the Weirong block (modified after Xiong 30 ); ( c ) Stratigraphic information of the Longmaxi Formation (modified after Xu et al 31 ). …”
Gas-bearing property evaluation and main controlling factor analysis have remained a concern in shale gas research. The application of principal component analysis, an important mathematical statistical method, in gas-bearing property evaluation and main controlling factor analysis of the Longmaxi shale in the Weirong area, Sichuan Basin, was examined. The Longmaxi shale exhibits high heterogeneity, manifested in the organic matter abundance, mineral composition, and pore structure. Seven geological factors, including the temperature, pressure, TOC content, clay content, brittle mineral content, pore volume, and specific surface area (SSA), were selected in principal component analysis. Four principal components with geological significance, such as mineral composition, formation condition, pore structure, and organic matter abundance, were extracted through principal component analysis, and further constituted a comprehensive factor. Shale gas-bearing properties were evaluated according to the score of the comprehensive factor. The Longmaxi shale could be identified as exhibiting good, medium, and poor gas-bearing properties based on the comprehensive factor scores of these samples. According to each geological factor’s contribution to the comprehensive factor, combined with geological analysis, it could be considered that gas-bearing properties are primarily controlled by pore volume, SSA, and clay content, followed by TOC content, brittle mineral content, temperature and pressure.
“…The pore type and porosity of shale can also reflect structural preservation conditions and formation process of strata [20,64]. Parameters such as desorbed gas content, organic surface porosity, and organic pore diameter in the MS are all significantly higher than that at the periphery area (Table 3).…”
Section: Physical and Geochemical Characteristics Of The Fivementioning
confidence: 99%
“…Although the Sichuan Basin experienced multistage tectonic movements [18][19][20][21][22][23][24][25], the Indosinian-Yanshan tectonic deformation was the most important and critically affected shale gas enrichment [26][27][28][29]. For example, the wide and gentle structures formed during the tectonic movement generally present favorable preservation conditions for shale gas in the southern Sichuan Basin (Figure 1(c)), including anticlines (e.g., Jiaoshiba, Taiyang-Dazhai, and Dingshan) [14,16,30], synclines, or single slopes (e.g., Changning and Weiyuan) [31,32].…”
Shale gas resources in mainland China and its commercial exploitation has been widely focused on the Wufeng–Longmaxi Formation organic-matter-rich shale in the Sichuan Basin. However, whether southwestern margin of the Sichuan Basin can produce high-quality shale gas has not been well resolved, which might be related to the poor understanding of the relationship between Cenozoic tectonic deformation and shale gas preservation. To answer the aforementioned scientific question, we conducted a detailed work in the Mugan area to show geologic structures and gas contents in the area through seismic profiles and geochemistry analysis. Specifically, the stable Mugan syncline shows a high gas content (>2.6 m3/t measured at three boreholes D1, D2, and D3), whereas its periphery presents a poor gas content (about 0.6 m3/t measured at two boreholes X1 and Y1). Moreover, oblique fracture density and dissolved pores are much higher at boreholes X1 and Y1 than that at the other three boreholes. We propose an opposite-verging thrust fault model to explain the different gas contents and tectonic features in the Mugan area, which might indicate that regions in the southwestern Sichuan Basin with similar tectonic and stratigraphic characteristics as those in the Mugan syncline are likely to produce high-yield shale gas. This finding provides new insights into the exploration theory of shale gas in the Tibetan Plateau.
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