Petrophysical characteristics of shales with different lithofacies in Jiaoshiba area, Sichuan Basin, China: Implications for shale gas accumulation mechanism

Yang, Feng; Xu, Shang; Hao, Fang; Hu, Boyu; Zhang, Baiqiao; Shu, Zhiguo; Long, Shiyu

doi:10.1016/j.marpetgeo.2019.06.028

“…Researchers have concluded that the pore structure of organic-rich shale is generally governed by diagenesis, organic matter, mineral components, thermal maturity, kerogen type, etc., depending on specific geological conditions [14,23,[53][54][55][56][57]. Shale lithofacies have important controls on porosity and pore structure due to different sedimentary environments and mineralogical variations [19,51,[58][59][60][61]. The same scenario can also be observed in our study.…”

Section: Discussionsupporting

confidence: 77%

Paleoenvironment, Geochemistry, and Pore Characteristics of the Postmature to Overmature Organic-Rich Devonian Shales in Guizhong Depression, Southwestern China

Zhang

¹

,

Liu

²

,

Changxi

³

et al. 2021

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Investigating shale pore characteristics has deepened our understanding of shale reservoir, while that of postmature-overmature shales is yet to be revealed, which is especially critical for shale gas evaluation in southern China. Ten Middle-Upper Devonian organic-rich shale samples were collected from well GY-1 in the Guizhong Depression, and the paleoenvironment, geochemistry, and pore system were analyzed with a series of experiments, including trace element analysis, X-ray diffraction (XRD), field emission scanning electron microscopy (FESEM), low-pressure N2 adsorption, and source rock geochemistry. Results show that the Middle-Upper Devonian shales in the Guizhong Depression are organic-rich mudstones with TOC ranging from 0.14% to 6.21%, which is highest in the Nabiao Formation ( D 2 n ) and Lower Luofu Formation ( D 2 l ) that were deposited in the anoxic and weak hydrodynamic deep-water shelf. They are thermally postmature to overmature with equivalent vitrinite reflectance ( EqV R o ) of 3.40%~3.76% and type I kerogen. The lithofacies in D 2 n and D 2 l are primarily siliceous/argillaceous mixed shale as well as a few siliceous argillaceous shales and argillaceous siliceous shales as well. Organic matter- (OM-) hosted pores within bitumen are primary storage volume, rather than inorganic pores (interparticle and intraparticle) which are rare. The total helium porosity of samples varies between 1.20% and 4.49%, while total surface area and pore volume are 2.39-14.22 m2/g and 0.0036-0.0171 ml/g, respectively. Porosity, pore surface area, and pore volume are in accordance with increasing TOC, R o , and siliceous mineral contents. Considerable OM-macropores are found in shales with R o > 3.6 % in our study which demonstrates that the porosity at postmature to overmature stage ( R o = 3.5 − 4.0 % ) does not change fundamentally. The high level of maturity is not considered the main controlling factor that affects shale gas content, and more attention should be paid to preservation conditions in this area.

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“…On the contrary, although the siliceous shales have abundant OM-hosted pores, these OM-hosted pores are likely only locally connected. Our previous study about the petrophysical property of shales in this area has shown that the permeability coefficient of argillaceous shales parallel to the bedding is commonly larger than that of the organic-rich siliceous shales . Furthermore, some investigators have thought that the hydration between clay minerals and fracturing water provides an additional force for water imbibition. , Water uptake by the argillaceous shales may induce microfractures and additionally promote the imbibition rate .…”

Section: Resultsmentioning

confidence: 97%

“…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

confidence: 99%

Modeling Water Imbibition and Penetration in Shales: New Insights into the Retention of Fracturing Fluids

Yang

¹

,

Zheng

²

,

Guo

³

et al. 2021

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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.

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“… 4 , 9 , 18 − 23 The permeability of shale fractures is affected by the roughness and tortuosity of the fractures 24 and also by the gas slippage phenomenon. 25 − 30 As a result, the measured permeability is greater than the actual value. The lower the pore pressure, the more evident the slippage effect and the greater the error in the measured permeability.…”

Section: Introductionmentioning

confidence: 88%

Experimental Study on the Effects of Pore Pressure and Slippage on the Permeability of a Fracture Network during Depressurization of Shale Gas Reservoir Production

Zhao

¹

,

Li

²

,

Sun

³

et al. 2022

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Hydraulic fracturing technology is an important technical means to increase shale gas production. The seepage channels formed in the hydraulic fractures during hydraulic fracturing can help increase reservoir permeability. Therefore, it is of significance to study the seepage law of the fracture network after reservoir hydraulic fracturing. In this study, hydraulic fracturing is used to fracture full-diameter shale cores, and three typical forms of hydraulic fracture networks are obtained. The characteristics of the fracture networks are analyzed by X-ray CT scanning. The effects of pore pressure and slippage on the permeability of the fracture networks are simulated by conducting experiments. The experimental results show that in the direction of gas seepage, hydraulic fractures completely penetrate the sample, and the greater the diameter and volume of the fracture, the better the hydraulic fracture conductivity. When the confining pressure remains unchanged at 50 MPa, the apparent permeability values of the hydraulic fractures with the worst and best fracture morphologies increase by 44.4 times and 2.8 times, respectively, with the decrease in the pore pressure from 30 to 2 MPa. The apparent permeability of the shale samples has a power function relationship with the pore pressure. The test results also show that the absolute permeability is positively correlated with the number of effective seepage channels in the hydraulic fractures and the number of hydraulic fractures, whereas the Klinkenberg coefficient is negatively correlated. Our research results can provide a basis for shale gas production model research and for on-site production capacity improvement. The qualitative understanding and scientific explanation of the effects of pore pressure and slippage on fracture network permeability in the process of depressurization of reservoir production have been realized.

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Petrophysical characteristics of shales with different lithofacies in Jiaoshiba area, Sichuan Basin, China: Implications for shale gas accumulation mechanism

Cited by 54 publications

References 50 publications

Paleoenvironment, Geochemistry, and Pore Characteristics of the Postmature to Overmature Organic-Rich Devonian Shales in Guizhong Depression, Southwestern China

Paleoenvironment, Geochemistry, and Pore Characteristics of the Postmature to Overmature Organic-Rich Devonian Shales in Guizhong Depression, Southwestern China

Modeling Water Imbibition and Penetration in Shales: New Insights into the Retention of Fracturing Fluids

Experimental Study on the Effects of Pore Pressure and Slippage on the Permeability of a Fracture Network during Depressurization of Shale Gas Reservoir Production

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