Geochemical Characteristics and Genetic Types of Natural Gas in the Xinchang Gas Field, Sichuan Basin, SW China

Wu, Xiaoqi; Liu, Quanyou; Liu, Guangxiang; Wang, Ping; Hua-ji, LI; Meng, Qingqiang; Chen, Yingbin; Zeng, Huasheng

doi:10.1111/1755-6724.13458

Cited by 15 publications

(4 citation statements)

References 40 publications

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“…1. This basin is a prolific hydrocarbon region and is estimated to have 0.44×10 9 m³ of exploitable shale gas resources, offering the most potential for shale gas development of any area in China (Yu et al, 2016;Wu et al, 2017). Several different intervals of source rocks, from the Cambrian and the Silurian through the Permian and the Triassic to the Jurassic, contribute to the total quantity of gas in place (Chen et al, 2011).…”

Section: Geological Settingsmentioning

confidence: 99%

Radial Permeability Measurements for Shale Using Variable Pressure Gradients

Fan

Sun²,

Elsworth

et al. 2020

Acta Geologica Sinica (Eng)

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Shale gas is becoming an important component of the global energy supply, with permeability a critical controlling factor for long‐term gas production. Obvious deviation may exist between helium permeability determined using small pressure gradient (SPG) methods and methane permeability obtained under actual field production with variable pressure gradients (VPG). In order to more accurately evaluate the matrix permeability of shale, a VPG method using real gas (rather than He) is established to render permeability measurements that are more representative of reservoir conditions and hence response. Dynamic methane production experiments were performed to measure permeability using the annular space in the shale cores. For each production stage, boundary pressure is maintained at a constant and the gas production with time is measured on the basis of volume change history in the measuring pump. A mathematical model explicitly accommodating gas desorption uses pseudo‐pressure and pseudo‐time to accommodate the effects of variations in pressure‐dependent PVT parameters. Analytical and semi‐analytical solutions to the model are obtained and discussed. These provide a convenient approach to estimate radial permeability in the core by nonlinear fitting to match the semi‐analytical solution with the recorded gas production data. Results indicate that the radial permeability of the shale determined using methane is in the range of 1×10−6 – 1×10−5 mD and decreases with a decrease in average pore pressure. This is contrary to the observed change in permeability estimated using helium. Bedding geometry has a significant influence on shale permeability with permeability in parallel bedding orientation larger than that in perpendicular bedding orientation. The superiority of the VPG method is confirmed by comparing permeability test results obtained from both VPG and SPG methods. Although several assumptions are used, the results obtained from the VPG method with reservoir gas are much closer to reality and may be directly used for actual gas production evaluation and prediction, through accommodating realistic pressure dependent impacts.

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Section: Geological Settingsmentioning

confidence: 99%

Radial Permeability Measurements for Shale Using Variable Pressure Gradients

Fan

Sun²,

Elsworth

et al. 2020

Acta Geologica Sinica (Eng)

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“…The Cretaceous strata is composed of approximately 2000 m of conglomerates. This area was largely covered by ~70 m of unsolidated Cenozoic sediment (Ma et al, 2007;Hao et al, 2008;Jiang et al, 2014;Liu et al, 2016;Wu et al, 2017).…”

Section: Stratigraphymentioning

confidence: 99%

Characteristics and Natural Gas Origin of Middle–Late Triassic Marine Source Rocks of the Western Sichuan Depression, SW China

Sun

Luo

Qing

et al. 2020

Acta Geologica Sinica (Eng)

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A scientific exploration well (CK1) was drilled to expand the oil/gas production in the western Sichuan depression, SW, China. Seventy‐three core samples and four natural gas samples from the Middle–Late Triassic strata were analyzed to determine the paleo‐depositional setting and the abundance of organic matter (OM) and to evaluate the hydrocarbon‐generation process and potential. This information was then used to identify the origin of the natural gas. The OM is characterized by medium n‐alkanes (nC15–nC19), low pristane/phytane and terrigenous aquatic ratios (TAR), a carbon preference index (CPI) of ∼1, regular steranes with C29 > C27 > C28, gammacerane/C30hopane ratios of 0.15–0.32, and δDorg of −132‰ to −58‰, suggesting a marine algal/phytoplankton source with terrestrial input deposited in a reducing–transitional saline/marine sedimentary environment. Based on the TOC, HI index, and chloroform bitumen “A,” the algal‐rich dolomites of the Leikoupo Formation are fair–good source rocks; the grey limestones of the Maantang Formation are fair source rocks; and the shales of the Xiaotangzi Formation are moderately good source rocks. In addition, maceral and carbon isotopes indicate that the kerogen of the Leikoupo and Maantang formations is type II and that of the Xiaotangzi Formation is type II–III. The maturity parameters and the hopane and sterane isomerization suggest that the OM was advanced mature and produced wet–dry gases. One‐dimensional modeling of the thermal‐burial history suggests that hydrocarbon‐generation occurred at 220–60 Ma. The gas components and C–H–He–Ar–Ne isotopes indicate that the oil‐associated gases were generated in the Leikoupo and Maantang formations, and then, they mixed with gases from the Xiaotangzi Formation, which were probably contributed by the underlying Permian marine source rocks. Therefore, the deeply‐buried Middle–Late Triassic marine source rocks in the western Sichuan depression and in similar basins have a great significant hydrocarbon potential.

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“…The Western Sichuan Depression (WSD) is situated in the western Sichuan Basin, and the gas exploration has achieved successive breakthroughs in the Middle Triassic to Jurassic strata (Wu et al, 2017;Wu et al, 2020a;Wu et al, 2020b). The Member two of the Middle Triassic Xujiahe Formation (T 3 x 2 ) has attracted wide attention due to the favorable exploration potential.…”

Section: Introductionmentioning

confidence: 99%

“…The origin and source of tight gas in different strata of the Sichuan Basin have been extensively studied based on geochemical analysis, and the tight gas in the T 3 x and Jurassic strata is considered as typical coal-derived gas and sourced mainly from the T 3 x coal-measure source rocks (Dai et al, 2009;Dai et al, 2012b;Ni et al, 2014a;Ni et al, 2014b;Wu et al, 2017;Dai et al, 2018;Wu et al, 2019). The T 3 x 2 gas from WSD displays complex geochemical characteristics, which are significantly different from the typical coal-derived gas from other members of T 3 x.…”

Section: Introductionmentioning

confidence: 99%

Geochemical Characteristics and Origin of Tight Gas in Member Two of the Upper Triassic Xujiahe Formation in Western Sichuan Depression, Sichuan Basin, SW China

Liu

Chen

et al. 2022

Front. Earth Sci.

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Natural gas in the tight sandstone reservoirs in Member two of the Upper Triassic Xujiahe Formation in the Western Sichuan Depression of the Sichuan Basin has complex geochemical characteristics, and the origin and source of the tight gas are revealed based on the geochemical analysis and comparison in this study. The tight gas has the dryness coefficient of 0.950–0.994, which is positively correlated with the CH4 content. The gaseous alkanes display positive carbon isotopic series, with the δ13C1 and δ13C2 values ranging from −35.6‰ to −30.3‰ and from −29.1‰ to −21.0‰, respectively, and the δD1 values range from −176‰ to −155‰. Genetic identification based on the carbon and hydrogen isotopic compositions indicates that a small amount of tight gas is typically coal-derived gas, whereas most of the tight-gas samples have experienced mixing by oil-associated gas. Geochemical comparisons suggest that the tight gas displays distinct differences with the typical oil-associated gas in Member four of the Middle Triassic Leikoupo Formation in the Chuanxi gas field and the typical coal-derived gas in Member five of Xujiahe Formation in the Xinchang gas field. It is also apparently different from the typical coal-derived gas in Member two of Xujiahe Formation in both Zhongba and Qiongxi gas fields. Among the tight gas in Member two of the Xujiahe Formation from the Western Sichuan Depression, the coal-derived gas is generated mainly by the humic mudstone in the Upper Triassic Ma’antang and Xiaotangzi formations, with assistance of the humic mudstone in Member two of the Xujiahe Formation, whereas the oil-associated gas is derived from the sapropelic limestone in the Ma’antang Formation.

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Geochemical Characteristics and Genetic Types of Natural Gas in the Xinchang Gas Field, Sichuan Basin, SW China

Cited by 15 publications

References 40 publications

Radial Permeability Measurements for Shale Using Variable Pressure Gradients

Radial Permeability Measurements for Shale Using Variable Pressure Gradients

Characteristics and Natural Gas Origin of Middle–Late Triassic Marine Source Rocks of the Western Sichuan Depression, SW China

Geochemical Characteristics and Origin of Tight Gas in Member Two of the Upper Triassic Xujiahe Formation in Western Sichuan Depression, Sichuan Basin, SW China

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