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1
Jiang, Shu, Jinchuan Zhang, Zhiqiang Jiang, Zhengyu Xu, Dongsheng Cai, Lei Chen, Yue Wu, et al. "Geology, resource potentials, and properties of emerging and potential China shale gas and shale oil plays." Interpretation 3, no. 2 (May 1, 2015): SJ1—SJ13. http://dx.doi.org/10.1190/int-2014-0142.1.
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This paper describes the geology of organic-rich shales in China, their resource potentials, and properties of emerging and potential China shale gas and shale oil plays. Marine, lacustrine, and coastal swamp transitional shales were estimated to have the largest technically recoverable shale gas resource (25.08 trillion cubic meters or 886 trillion cubic feet) and 25 to 50 billion barrels of technically recoverable shale oil resource. The Precambrian Sinian Doushantuo Formation to Silurian Longmaxi black marine shales mainly accumulated in the intrashelf low to slope environments in the Yangtze Platform in South China and in the Tarim Platform in northwest China. The marine shales in the Yangtze Platform have high maturity (Ro of 1.3%–5%), high total organic carbon (mainly [Formula: see text]), high brittle-mineral content, and have been identified as emerging shale gas plays. The Lower Paleozoic marine shales in the Upper Yangtze area have the largest shale gas potential and currently top the list as exploration targets. The Carboniferous to Permian shales associated with coal and sandstones were mainly formed in transitional depositional settings in north China, northwest China, and the Yangtze Platform in south China. These transitional shales are generally rich in clay with a medium level of shale gas potential. The Middle Permian to Cenozoic organic-rich lacustrine shales interbedded with thin sandstone and carbonate beds are sporadically distributed in rifted basins across China. Their main potentials are as hybrid plays (tight and shale oil). China shales are heterogeneous across time and space, and high-quality shale reservoirs are usually positioned within transgressive systems tract to early highstand systems tract intervals that were deposited in an anoxic depositional setting. For China’s shale plays, tectonic movements have affected and disrupted the early oil and gas accumulation, making tectonically stable areas more favorable prospects for the exploration and development of shale plays.
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Li, Gang, Ping Gao, Xianming Xiao, Chengang Lu, and Yue Feng. "Lower Cambrian Organic-Rich Shales in Southern China: A Review of Gas-Bearing Property, Pore Structure, and Their Controlling Factors." Geofluids 2022 (June 25, 2022): 1–23. http://dx.doi.org/10.1155/2022/9745313.
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The Lower Cambrian shales are widely developed in southern China, with greater thicknesses and higher TOC contents. Although the shale gas resource potential has been suggested to be huge, the shale gas exploration and development is not satisfactory. At present, the gas-bearing property evaluation of the Lower Cambrian shale is still a hot spot of concern. According to previous works, this paper systematically summarizes the gas-bearing characteristics and controlling factors of the Lower Cambrian shales in southern China. The buried depth of Lower Cambrian shales mainly ranges from 3000 m to 6000 m, and the thickness of organic-rich shale intervals ( TOC > 2 % ) varies from 20 m to 300 m. The TOC content and EqVRo value are generally up to 2%-10% and 2.5%-6.0%, respectively. The gas content of the Lower Cambrian shales in the Weiyuan-Qianwei block of the Sichuan Basin and the western Hubei area generally exceeds 2 m3/t, and gas composition is dominated by CH4. In southeastern Chongqing, northwestern Hunan, and northern Guizhou areas, the gas content of the Lower Cambrian shales is generally <2 m3/t, and the N2 content is generally >60%. In the Lower Yangtze region, the Lower Cambrian shale reservoirs basically contain no gas. Higher maturity, lower porosity, and less-no organic pores are suggested to be responsible for low gas contents and/or the predominate of N2 in shale gas reservoirs. Strong tectonic deformation is an important factor leading to the massive gas loss from shale reservoirs, thus resulting in no gas or only a small amount of N2 in the Lower Cambrian shales. In a word, the Lower Cambrian shale gas plays with low maturity and relatively stable tectonic condition, especially deep-ultradeep zones, may be the favorable targets for shale gas exploration.
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Feng, Bing, Jiliang Yu, Feng Yang, Zhiyao Zhang, and Shang Xu. "Reservoir Characteristics of Normally Pressured Shales from the Periphery of Sichuan Basin: Insights into the Pore Development Mechanism." Energies 16, no. 5 (February 23, 2023): 2166. http://dx.doi.org/10.3390/en16052166.
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Reservoir characteristics and the occurrence mechanism of shale gas outside of the Sichuan Basin are the research hotspots of normally pressured shales in China. Taking shales on the Anchang syncline from the periphery of the Sichuan Basin as an example, X-ray diffraction, organic geochemistry, and rock physical experiments were carried out to analyze the reservoir characteristics and their main geological controls on the normally pressured shales. The mineralogical results show that the studied shales from the Anchang syncline are mainly siliceous shales with a high quartz content (average of 57%). The quartz content of these normally pressured shales is of biological origin, as shown by the positive correlation between the quartz and organic carbon (TOC) contents. The average porosity of the studied shales is about 2.9%, which is lower than shales inside the Sichuan Basin. Organic matter pores are likely the primary storage space of the normally pressured shale gas, as shown by the positive relationship between the TOC content and porosity. However, scanning electron microscopy observations on the studied shales show that the pores in these normally pressured shales are poorly preserved; many pores have been subjected to compression and deformation due to tectonic movements. Compared to shales inside the Sichuan Basin, the effective thickness of shales outside of the Sichuan Basin is thin and the stratum dip is large. Thus, shale gas outside of the Sichuan Basin is apt to escape laterally along the bedding of the strata. After losing a significant amount of shale gas, the gas pressure decreases to normal pressure, which makes it difficult for the pores to resist compaction from the overlying strata. This is probably why most shale gas reservoirs outside of the Sichuan Basin are normally pressured, while the shale strata inside the Sichuan Basin are commonly overpressured. This study provides insights to understand the pore development and hydrocarbon occurrence on normally pressured shales outside of the Sichuan Basin.
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Hill, Anthony, Sandra Menpes, Guillaume Backè, Hani Khair, and Arezoo Siasitorbaty. "Shale gas prospectivity in South Australia." APPEA Journal 51, no. 2 (2011): 718. http://dx.doi.org/10.1071/aj10098.
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Potential shale gas bearing basins in SA are primarily dominated by thermogenic play types and span the Neoproterozoic to Cretaceous. Whilst companies have only recently commenced exploring for shale gas in the Permian Cooper Basin, strong gas shows have been routinely observed and recorded since exploration commenced in the basin in 1959. The regionally extensive Roseneath and Murteree shales represent the primary exploration focus and reach maximum thicknesses of 103 m and 86 m respectively with TOC values up to 9%. These shales are in the gas window in large parts of the basin, particularly in the Patchawarra and Nappamerri troughs. Outside the Cooper Basin, thick shale sequences in the Crayfish Subgroup of the Otway Basin, in particular the Upper and Lower Sawpit shales and to a lesser extent the Laira Formation, have good shale gas potential in the deeper portions of the basin. TOC averages up to 3% are recorded in these shales in the Penola Trough; maturities in the range of 1.3–1.5% have been modelled. Thick Permian marine shales of the Arckaringa Basin have excellent source rock characteristics, with TOC’s ranging 4.1–7.4% and averaging 5.2% over an interval exceeding 150 m in the Phillipson Trough; however, these Type II source rocks are not sufficiently mature for gas generation anywhere in the Arckaringa Basin. Shale gas has the potential to rival CSM in eastern Australia; its potential is now being explored in SA.
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Jiang, Tao, Zhijun Jin, Hengyuan Qiu, Xuanhua Chen, Yuanhao Zhang, and Zhanfei Su. "Pore Structure and Gas Content Characteristics of Lower Jurassic Continental Shale Reservoirs in Northeast Sichuan, China." Nanomaterials 13, no. 4 (February 20, 2023): 779. http://dx.doi.org/10.3390/nano13040779.
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The Jurassic shale in the northeastern Sichuan Basin is one of the main target intervals for continental shale gas exploitation. Research on the pore structure and gas-bearing properties of shales is the key issue in target interval optimization. Through core observation, geochemistry, bulk minerals, scanning electron microscopy, nitrogen adsorption, and isothermal adsorption experiments, various lithofacies with different pore structure characteristics were clarified. In addition, the factors that control gas-bearing properties were discussed, and a continental shale gas enrichment model was finally established. The results show that the Jurassic continental shale in the northeastern Sichuan Basin can be classified into six lithofacies. Organic pores, intergranular pores, interlayer pores in clay minerals, intercrystalline pores in pyrite framboids, and dissolution pores can be observed in shale samples. Pore structures varied in different shale lithofacies. The contact angle of shales is commonly less than 45°, leading to complex wettability of pores in the shales. Free gas content is mainly controlled by the organic matter (OM) content and the brittleness in the Jurassic shale. The adsorbed gas content is mainly controlled by the OM content, clay mineral type, and water saturation of the shales. The enrichment mode of the Lower Jurassic continental shale gas in the northeastern Sichuan Basin is established. Paleoenvironments control the formation of organic-rich shales in the center part of lakes. The “baffle” layer helps the confinement and high pressure, and the complex syncline controls the preservation, forming the enrichment pattern of the complex syncline-central baffle layer.
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Faraj, Basim, and Daniel Jarvie. "Producibility and commerciality of shale resource systems: contrasting geochemical attributes of shale gas and shale oil systems." APPEA Journal 53, no. 2 (2013): 469. http://dx.doi.org/10.1071/aj12080.
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Increasing the producibility of petroleum from shale is a key challenge for this decade and beyond. While understanding of producing petroleum from shales has advanced rapidly during the past decade, many unknowns remain. In addition, fundamental differences remain between high-thermal maturity shale gas systems (gas-window shales) and oil-window shales. Although it is shown that oil is produced from the shale matrix similar to gas shales, it is not known what improvement to recovery factors should be expected due to the fundamental differences and uniqueness of shale oil systems. Some of the challenges in early exploration of shales in the oil window are related to the loss of oil from rock samples (cuttings, core), sample processing, storage conditions, sample preparation, oil type, API gravity, gas-oil ratio (GOR), rock lithofacies, and analytical conditions. It is shown that old cuttings may lose up to 300% of their free oil content simply due to evaporation, even in tight shale with black oil having a GOR of about 500 scf/bbl. When cuttings are compared with RSWC or core chips, the loss increases to almost 500%. Projection of oil content to match measured GOR values of oils or even extracts of organic-rich tight shales allows prediction of this oil loss—this impacts calculations of original oil in place (OOIP) and, hence, hydrocarbon recovery estimates from such systems.
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Jiao, Pengfei, Genshun Yao, Shangwen Zhou, Zhe Yu, and Shiluo Wang. "A Comparative Study of the Micropore Structure between the Transitional and Marine Shales in China." Geofluids 2021 (April 7, 2021): 1–14. http://dx.doi.org/10.1155/2021/5562532.
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To compare the micropore structure of marine-continental transitional shale with marine shale, organic geochemical, field emission scanning electron microscopy, and low-temperature nitrogen adsorption experiments were conducted on shale samples from the Shanxi Formation in the eastern Ordos Basin and the Longmaxi Formation in the southern Sichuan Basin. The results show that Shanxi Formation shale has a smaller specific surface area and pore volume than Longmaxi Formation shale; therefore, the transitional shales fail to provide sufficient pore spaces for the effective storage and preservation of natural gas. Both the transitional and marine shales are in an overmature stage with high total organic carbon content, but they differ considerably in pore types and development degrees. Inorganic pores and fractures are dominantly developed in transitional shales, such as intragranular pores and clay mineral interlayer fractures, while organic nanopores are rarely developed. In contrast, organic pores are the dominant pore type in the marine shales and inorganic pores are rarely observed. The fractal analysis also shows that pore structure complexity and heterogeneity are quite different. These differences were related to different organic types, i.e., type I of marine shale and type III of transitional shale. Marine Longmaxi shale has experienced liquid hydrocarbon cracking, gas generation, and pore-forming processes, providing good conditions for natural gas to be preserved. However, during the evolution of transitional Shanxi shale, gas cannot be effectively preserved due to the lack of the above evolution processes, leading to the poor gas-bearing property. The detailed comparison of the micropore structure between the transitional and marine shales is of great importance for the future exploitation of marine-continental transitional shale gas in China.
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Menpes, Sandra, and Tony Hill. "Emerging continuous gas plays in the Cooper Basin, South Australia." APPEA Journal 52, no. 2 (2012): 671. http://dx.doi.org/10.1071/aj11085.
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Recent off-structure drilling in the Nappamerri Trough has confirmed the presence of gas saturation through most of the Permian succession, including the Roseneath and Murteree shales. Basin-centred gas, shale gas and deep CSG plays in the Cooper Basin are now the focus of an escalating drilling and evaluation campaign. The Permian succession in the Nappamerri Trough is up to 1,000 m thick, comprising very thermally mature, gas-prone source rocks with interbedded sands—ideal for the creation of a basin-centred gas accumulation. Excluding the Murteree and Roseneath shales, the succession comprises up to 45% carbonaceous and silty shales and thin coals deposited in flood plain, lacustrine and coal swamp environments. The Early Permian Murteree and Roseneath shales are thick, generally flat lying, and laterally extensive, comprising siltstones and mudstones deposited in large and relatively deep freshwater lakes. Total organic carbon values average 3.9% in the Roseneath Shale and 2.4% in the Murteree Shale. The shales lie in the wet gas window (0.95–1.7% Ro) or dry gas window (>1.7% Ro) over much of the Cooper Basin. Thick Permian coals in the deepest parts of the Patchawarra Trough and over the Moomba high on the margin of the Nappamerri Trough are targets for deep CSG. Gas desorption analysis of a thick Patchawarra coal seam returned excellent total raw gas results averaging 21.2 scc/g (680 scf/ton) across 10 m. Scanning electron microscopy has shown that the coals contain significant microporosity.
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Zhang, Peng, Junwei Yang, Yuqi Huang, Jinchuan Zhang, Xuan Tang, and Chengwei Liu. "Shale Heterogeneity in Western Hunan and Hubei: A Case Study from the Lower Silurian Longmaxi Formation in Well Laidi 1 in the Laifeng-Xianfeng Block, Hubei Province." Geofluids 2022 (January 7, 2022): 1–15. http://dx.doi.org/10.1155/2022/8125317.
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Shale heterogeneity directly determines the alteration ability and gas content of shale reservoirs, and its study is a core research topic in shale gas exploitation and development. In this study, the shale from the Longmaxi Formation from well Ld1 located in western Hunan and Hubei is investigated. The shale’s heterogeneity is analyzed based on shale mineral rocks, microslices, geochemistry, and low-temperature N2 adsorption-desorption. It is found that the shales of the Longmaxi Formation from well Ld1 are mainly composed of siliceous shale, mixed shale, and clayey shale. The three types of shale facies exhibit strong heterogeneity in terms of the occurrence state of organic matter, organic content, mineral composition, microstructure and structure, brittleness, and micropore type. Sedimentation, late diagenesis, and terrigenous input are the main factors influencing the shale’s heterogeneity. With a total organic carbon (TOC) of 0.41%-4.18% and an organic matter maturity ( R o ) of 3.09%-3.42%, the shales of the Longmaxi Formation from well Ld1 are in an overmature stage, and their mineral composition is mainly quartz (5%-66%) and clay minerals (17.8%-73.8%). The main pore types are intergranular pores, intragranular pores, microfractures, and organic pores. The results of the low-temperature N2 adsorption-desorption experiment show that the shale pores are mainly composed of micropores and mesopores with narrow throats and complex structures, and their main morphology is of a thin-necked and wide-body ink-bottle pore. Based on the Frenkel-Halsey-Hill (FHH) model, the pore fractal dimension is studied to obtain the fractal dimension D 1 (2.73-2.76, mean 2.74) under low relative pressure ( P / P 0 ≤ 0.5 ) and D 2 (2.80-2.89, mean 2.85) under high relative pressure ( P / P 0 > 0.5 ). The shales of the Longmaxi Formation in the study area have a strong adsorption and gas storage capacity; however, the pore structure is complex and the connectivity is poor, which, in turn, imposes high requirements on reservoir reformation measures during exploitation. Moreover, the fractal dimension has a positive correlation with organic matter abundance, TOC, clay mineral content, and pyrite content and a negative correlation with quartz content. Since the organic matter contained in the shales of the Longmaxi Formation in the study area is in the overmature stage, the adsorption capacity of the shales is reduced, and the controlling effect of organic matter abundance on the same is not apparent.
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Gao, Ping, Xianming Xiao, Dongfeng Hu, Ruobing Liu, Yidong Cai, Tao Yuan, and Guangming Meng. "Water Distribution in the Ultra-Deep Shale of the Wufeng–Longmaxi Formations from the Sichuan Basin." Energies 15, no. 6 (March 17, 2022): 2215. http://dx.doi.org/10.3390/en15062215.
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Recently, deep and ultra-deep shales (depth >3500 m) of the Lower Paleozoic Wufeng–Longmaxi formations (WF–LMX) have become attractive targets for shale gas exploration and development in China, and their gas contents may be influenced by the occurrence of water to some extent. However, the water content and its distribution in the different nanopores of the deep and ultra-deep shales have rarely been reported. In this study, a suite of the WF–LMX ultra-deep shale samples (5910–5965 m depth) from the Well PS1 was collected for water content measurements, and low-pressure CO2 and N2 adsorption experiments of both as-received and experimentally dried shale samples were carried out to investigate the distribution of water in the different nanopores. Since the studied ultra-deep shales are characterized by higher thermal maturity (equivalent vitrinite reflectance (EqVRo) > 2.5 %) and ultra-low water saturation, the pore water is generally dominated by irreducible water. The content of irreducible water of the studied shales varies from 1.57 to 13.66 mg/g, averaging 6.74 mg/g. Irreducible water may mainly occur in the clay-hosted pores, while it could also be hosted in parts of organic pores of organic-rich shales. Irreducible water is primarily distributed in non-micropores rather than in micropores of the studied shales, which mainly occurs in micopores with a diameter of 0.4–0.6 nm and mesopores with a diameter of 2–10 nm. Very low contents of irreducible water could reduce the specific surface area and volume of non-micropores of the shales to some extent, but the effect of irreducible water on the specific surface area of non-micropores was more significant than the volume of non-micropores, especially for organic-rich shale samples. The ultra-deep shale gas may be predominately composed of free gas, so low contents of irreducible water may play a limited role in its total gas contents. Overall, our findings can be helpful for a better understanding of water distribution in the highly-matured shales, and provide a scientific basis for ultra-deep shale gas exploration.
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Gao, Hai-Tao, Yan-Ming Zhu, Fu-Hua Shang, and Chong-Yu Chen. "Study on the Shale Gas Reservoir-Forming Characteristics of the Taiyuan Formation in the Eastern Qinshui Basin, China." Journal of Nanoscience and Nanotechnology 21, no. 1 (January 1, 2021): 72–84. http://dx.doi.org/10.1166/jnn.2021.18465.
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Shales are widely developed in the strata of the Carboniferous-Permian coal measures in the Qinshui Basin, and these shales have great potential for shale gas exploration. In this paper, the shales of the Taiyuan Formation in the eastern Qinshui Basin are studied. The shales of the Taiyuan Formation in the study area are investigated through field investigation, organic geochemical testing, X-ray diffraction, scanning electron microscopy, high pressure mercury injection, low temperature liquid nitrogen adsorption and PetroMod simulation and through other tests to study the reservoir characteristics, such as organic geochemistry, mineralogy, petrology, pore permeability, and gas burial history. The results show that the shales of the Taiyuan Formation are well developed over the whole area with a thickness of more than 60 m. The average organic matter content is 2.95%, and the kerogen type is type III. The shale maturity (average value is 2.45%) corresponds to the stage of high maturity evolution, indicating that a large amount of shale gas has been generated in this area. A high content of quartz and clay minerals indicates a high fracturability. The nanopores in the shale reservoir are well developed at pore sizes between 2˜10 nm and greater than 1000 nm; however, the pores at the other pore sizes are poorly developed, resulting in weak pore connectivity in the reservoir. According to the results of the PetroMod simulation, the shale of the Taiyuan Formation has undergone two subsidence and two uplift processes. The Yanshanian magmatic intrusion is the key factor for the rapid increase in gas production. In addition, the geological structure of the area is relatively simple, and the burial history and caprock thickness are also the main controlling factors of gas generation and preservation. The shale-sandstone-shale combination and shale-coal-shale combination are the main models of shale gas preservation. This comprehensive study suggests that the shale gas of the Taiyuan Formation in the eastern Qinshui Bain has good potential for exploration and development.
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Renwick, Edward. "California Oil and Gas Update." Texas Wesleyan Law Review 19, no. 2 (March 2013): 293–97. http://dx.doi.org/10.37419/twlr.v19.i2.5.
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The last year has been a busy one in the upstream California oil and gas business. The 2011 Preliminary Report of California Oil and Gas Production Statistics, which was issued in April 2012 by the California Department of Conservation, Division of Oil, Gas, and Geothermal Resources, reports that 4,033 notices of intention to drill were filed with the Division as contrasted with 2,081 in 2010. Although the Preliminary Report for 2012 is not yet issued, anecdotal evidence suggests 2012 will be at least as active as 2011. Much of the excitement involves California's Monterey and Santos Shales. The Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays, published in July 2011 by the United States Energy Information Administration estimates that those shales hold 64% of the undeveloped technically recoverable shale oil resources remaining in discovered shale plays in the United States as of January 1, 2009.
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Jiang, Sheng Ling, Chun Lin Zeng, Sheng Xiu Wang, and Mei Li. "Accumulation Conditions of Paleozoic Shale Gas and its Resources in Northeast Chongqing Areas." Advanced Materials Research 868 (December 2013): 186–91. http://dx.doi.org/10.4028/www.scientific.net/amr.868.186.
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In order to carry out a more comprehensive discussion on shale gas accumulation conditions of Lower Cambrian Shuijingtuo Formation and Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation, the distribution, source rock conditions and reservoir conditions of these two shales are comprehensively analyzed, these two shales are both have the characteristics of high organic carbon content, high maturity, appropriate thickness and mainly typeⅠkerogen as source rocks, and interbedded with siltstone and/or fine sandstone, rich in quartz and other detrital components, easy to break and form the cracks, micro cracks as reservoirs, these characteristics provide a favorable material basis and reservoir space for shale gas accumulating. On this basis, the effective distribution areas of these two shales are further determined and shale gas resources are preliminary evaluated, eventually come to the results of shale gas resources of Lower Cambrian Shuijingtuo Formation and Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation respectively are 0.409×1012m3and 0.389×1012m3.
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Xu, Hongjie, Shuxun Sang, Jingfen Yang, Jun Jin, Huihu Liu, Xiaozhi Zhou, and Wei Gao. "Evaluation of coal and shale reservoir in Permian coal-bearing strata for development potential: A case study from well LC-1# in the northern Guizhou, China." Energy Exploration & Exploitation 37, no. 1 (October 28, 2018): 194–218. http://dx.doi.org/10.1177/0144598718807553.
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Indentifying reservoir characteristics of coals and their associated shales is very important in understanding the co-exploration and co-production potential of unconventional gases in Guizhou, China. Accordingly, comprehensive experimental results of 12 core samples from well LC-1# in the northern Guizhou were used and analyzed in this paper to better understand their vertical reservoir study. Coal and coal measured shale, in Longtan Formation, are rich in organic matter, with postmature stage of approximately 3.5% and shales of type III kerogen with dry gas generation. All-scale pore size analysis indicates that the pore size distribution of coal and shale pores is mainly less than 20 nm and 100 nm, respectively. Pore volume and area of coal samples influenced total gas content as well as desorbed gas and lost gas content. Obvious relationships were observed between residual gas and BET specific surface area and BJH total pore volume (determined by nitrogen adsorption). For shale, it is especially clear that the desorbed gas content is negatively correlated with BET specific surface area, BJH total pore volume and clay minerals. However, the relationships between desorbed gas and TOC (total organic carbon) as well as siderite are all well positive. The coals and shales were shown to have similar anoxic conditions with terrestrial organic input, which is beneficial to development of potential source rocks for gas. However, it may be better to use a low gas potential assessment for shales in coal-bearing formation because of their low S1+S2 values and high thermal evolution. Nevertheless, the coalbed methane content is at least 10 times greater than the shale gas content with low desorbed gases, indicating that the main development unconventional natural gas should be coalbed methane, or mainly coalbed methane with supplemented shale gas.
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Xie, Qilai, Hao Xu, and Shuang Yu. "Characterization of the Lower Cretaceous Shale in Lishu Fault Depression, Southeastern Songliao Basin: Implications for Shale Gas Resources Potential." Energies 15, no. 14 (July 15, 2022): 5156. http://dx.doi.org/10.3390/en15145156.
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Large thickness of shales over 180.0 m was developed in the source rocks of the Shahezi and Yingcheng formations in the Lishu Fault Depression. Moreover, the high amount of gas content and the total hydrocarbon value of gas logging in several boreholes illustrate that there is a great potential of shale gas resources in this region. Therefore, an integrated characterization of shales from the lower Cretaceous Shahezi and Yingcheng formations was provided to evaluate shale gas resources potential. The measurement results illustrated that the organic-rich shale samples with kerogen type Ⅱ during high to over thermal maturity had a higher content of brittle minerals (>50%) and clay mineral dominated by illite. The shales had a total porosity of 3.11–4.70%, a permeability of 1.24 × 10−3–1.52 × 10−3 μm2, and possessed pore types including dissolution pores, inter-layer pores of clay minerals, micro-fractures, intra-granular pores, and organic pores, which were dominated by micropores and mesopores (0.5–1.7 nm, 2.2–34.3 nm) with a significant contribution from OM and clay minerals. According to the N2 adsorption isotherms, the pore volume was comprised primarily of mesopores with mean widths of 4.314–6.989 nm, while the surface area was comprised primarily of micropores with widths in ranges of 0.5–0.8 nm and 1.0–1.7 nm. Thus, the shales have a suitable porosity and permeability, indicating that fine storage capacity and favorable gas flow capacity occur in the Shahezi and Yingcheng formations, which exhibit a good reservoir quality and excellent exploration potential since the considerable thickness of shales could form a closed reservoir and served as cap rocks for in situ gas generation and accumulation. Especially, according to the measured CH4 excess adsorption amount and the calculated maximum absolute adsorption capacities of CH4 based on the Langmuir adsorption model, the estimated GIP values (1.388–3.307 m3/t) of the shales happened to be in a sampling depth under geological hydrostatic pressure and temperature conditions. This means that the shale storage capacity and high gas content from well site desorption completely met the standard of industrial exploitation when synthetically considering the GIP model. As a consequence, shales in the Shahezi and Yingcheng formations in the Lishu Fault Depression could be potential targets for shale gas exploration.
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Owusu, Esther B., and Haylay Tsegab Gebretsadik. "The potential of shale gas resources in Peninsular Malaysia." IOP Conference Series: Earth and Environmental Science 1003, no. 1 (April 1, 2022): 012024. http://dx.doi.org/10.1088/1755-1315/1003/1/012024.
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Abstract Even though the black shales in Peninsular Malaysia covered a quarter of the total surface area and have been overlooked for their economic potential except few workers have evaluated their thermal maturity using rock-eval pyrolysis, vitrinite reflectance analysis and illite crystallinity. According to these research works, the shales have been categorized into immature, mature and overmatured successions, which in turn dictated the exploration activities of commercially viable shale gas in the onshore Peninsular Malaysia. In this work, published and unpublished data on the scattered black shales of Peninsular Malaysia were examined to assess exploration potential of shales from various stratigraphic windows. Thus, using comparative evaluation of all the thermal history plots of the black shales from Peninsular Malaysia; areas of thermally matured source rocks are identified. According to the thermal maturation assessment; the Palaeozoic black shales in the Peninsular Malaysia have minimal generative potential for economically viable source rock for hydrocarbon, whereas the younger successions of Oligocene to Miocene have considerable potential to serve as source rocks of feasible prospect, provided permissible geological settings are met.
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Yin, Shitao, Zhifeng Zhang, and Yongjian Huang. "Geochemical Characteristics and Chemostratigraphic Analysis of Wufeng and Lower Longmaxi Shales, Southwest China." Minerals 12, no. 9 (September 3, 2022): 1124. http://dx.doi.org/10.3390/min12091124.
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The demand for shale gas has propelled researchers to focus on precise and high-resolution stratigraphic divisions for homogeneous shales, of which the late-Ordovician Wufeng (O3w) and the early-Silurian Longmaxi (S1l) formations in southwest China are two of the best candidates for shale gas exploration in China. However, systematic chemostratigraphic work for these strata is still sparse, and the existing chemostratigraphic work either lack representativeness in terms of the proxies used or are subjective during their division procedures. Thus, automatic division process based on multi proxies and an objective statistical technique was applied to establish a quantitative, high-resolution, and robust chemostratigraphic scheme for the Wufeng and lower Longmaxi shales. The geochemical analysis unveils that the Wufeng and Lower Longmaxi shales show prominent heterogeneities in terrigenous inputs, redox conditions, and paleoproductivity, enabling the potential application of chemostratigraphy to these strata. Based on these heterogeneities, the chemostratigraphic scheme for the Wufeng and Lower Longmaxi shales has been established, and the whole strata could be divided into 13 chemozones using constrained clustering analysis. The chemostratigraphic scheme could not only be comparable to the regional sequence stratigraphic scheme but also more objective and higher-resolution. The high TOC content and brittle minerals within chemozone C1 makes it the most preferable layer for shale gas exploration and development. This research gives a systematic chemostratigraphic analysis on Wufeng and Lower Longmaxi shales, which testifies the feasibility and potential of usage of chemostratigraphy for Chinese shale gas exploration and development.
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Fatah, Ahmed, Ziad Bennour, Hisham Ben Mahmud, Raoof Gholami, and Md Mofazzal Hossain. "A Review on the Influence of CO2/Shale Interaction on Shale Properties: Implications of CCS in Shales." Energies 13, no. 12 (June 19, 2020): 3200. http://dx.doi.org/10.3390/en13123200.
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Carbon capture and storage (CCS) is a developed technology to minimize CO2 emissions and reduce global climate change. Currently, shale gas formations are considered as a suitable target for CO2 sequestration projects predominantly due to their wide availability. Compared to conventional geological formations including saline aquifers and coal seams, depleted shale formations provide larger storage potential due to the high adsorption capacity of CO2 compared to methane in the shale formation. However, the injected CO2 causes possible geochemical interactions with the shale formation during storage applications and CO2 enhanced shale gas recovery (ESGR) processes. The CO2/shale interaction is a key factor for the efficiency of CO2 storage in shale formations, as it can significantly alter the shale properties. The formation of carbonic acid from CO2 dissolution is the main cause for the alterations in the physical, chemical and mechanical properties of the shale, which in return affects the storage capacity, pore properties, and fluid transport. Therefore, in this paper, the effect of CO2 exposure on shale properties is comprehensively reviewed, to gain an in-depth understanding of the impact of CO2/shale interaction on shale properties. This paper reviews the current knowledge of the CO2/shale interactions and describes the results achieved to date. The pore structure is one of the most affected properties by CO2/shale interactions; several scholars indicated that the differences in mineral composition for shales would result in wide variations in pore structure system. A noticeable reduction in specific surface area of shales was observed after CO2 treatment, which in the long-term could decrease CO2 adsorption capacity, affecting the CO2 storage efficiency. Other factors including shale sedimentary, pressure and temperature can also alter the pore system and decrease the shale “caprock” seal efficiency. Similarly, the alteration in shales’ surface chemistry and functional species after CO2 treatment may increase the adsorption capacity of CO2, impacting the overall storage potential in shales. Furthermore, the injection of CO2 into shales may also influence the wetting behavior. Surface wettability is mainly affected by the presented minerals in shale, and less affected by brine salinity, temperature, organic content, and thermal maturity. Mainly, shales have strong water-wetting behavior in the presence of hydrocarbons, however, the alteration in shale’s wettability towards CO2-wet will significantly minimize CO2 storage capacities, and affect the sealing efficiency of caprock. The CO2/shale interactions were also found to cause noticeable degradation in shales’ mechanical properties. CO2 injection can weaken shale, decrease its brittleness and increases its plasticity and toughness. Various reductions in tri-axial compressive strength, tensile strength, and the elastic modulus of shales were observed after CO2 injection, due to the dissolution effect and adsorption strain within the pores. Based on this review, we conclude that CO2/shale interaction is a significant factor for the efficiency of CCS. However, due to the heterogeneity of shales, further studies are needed to include various shale formations and identify how different shales’ mineralogy could affect the CO2 storage capacity in the long-term.
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Zhu, Dongya, Quanyou Liu, Bing Zhou, Zhijun Jin, and Tianyi Li. "Sulfur isotope of pyrite response to redox chemistry in organic matter-enriched shales and implications for components of shale gas." Interpretation 6, no. 4 (November 1, 2018): SN71—SN83. http://dx.doi.org/10.1190/int-2018-0023.1.
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The Sichuan Basin has achieved breakthroughs in shale gas production from the Upper Ordovician Wufeng and Lower Silurian Longmaxi Formation black shales. Large amounts of pyrite commonly occur in the organic matter (OM)-enriched black shales, but [Formula: see text] has not been detected in the shale gas. The genetic mechanism of pyrite, its implications for redox chemistry, and the main controlling factors for the absence of [Formula: see text] are unclear. The [Formula: see text] values of the pyrite are extremely high. In particular, the nodular pyrite has [Formula: see text] values as high as 38.6‰. The high sulfur isotopic values indicate that the Wufeng-Longmaxi Formation shales were deposited in an anaerobic sulfide euxinic environment where the limited [Formula: see text] in the stagnant bottom water was completely reduced to pyrite by bacterial sulfate reduction (BSR). The heavy sulfur isotope composition of the pyrite is indicative of organic-rich intervals, which are also the high-yielding intervals for shale gas. Shale gas from the Wufeng-Longmaxi Formation is dominated by alkanes, with an average [Formula: see text] content of 97.91%. The shale gas contains a small amount of [Formula: see text], with an average of 0.34%. However, no [Formula: see text] was detected. The [Formula: see text] values have a range of 4.7‰–11.5‰, with an average of 7.8‰, which is significantly different from the [Formula: see text] related to thermochemical sulfate reduction (TSR) but similar to the [Formula: see text] from the decomposition of carbonate minerals. The black shales experienced high burial temperatures and were rich in OM, which met part of the necessary conditions for the occurrence of TSR. However, TSR did not occur. The reason for the lack of TSR process is that no sulfate mineral was available in the shales because the [Formula: see text] in the seawater was fully consumed by BSR. As a result, [Formula: see text] associated with TSR was not detectable in the shale gas.
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Cao, Chunhui, Liwu Li, Yuhu Liu, Li Du, Zhongping Li, and Jian He. "Factors Affecting Shale Gas Chemistry and Stable Isotope and Noble Gas Isotope Composition and Distribution: A Case Study of Lower Silurian Longmaxi Shale Gas, Sichuan Basin." Energies 13, no. 22 (November 16, 2020): 5981. http://dx.doi.org/10.3390/en13225981.
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The Weiyuan (WY) and Changning (CN) fields are the largest shale gas fields in the Sichuan Basin. Though the shale gases in both fields are sourced from the Longmaxi Formation, this study found notable differences between them in molecular composition, carbon isotopic composition, and noble gas abundance and isotopic composition. CO2 (av. 0.52%) and N2 (av. 0.94%) were higher in Weiyuan than in Changning by an average of 0.45% and 0.70%, respectively. The δ13C1 (−26.9% to −29.7%) and δ13C2 (−32.0% to −34.9%) ratios in the Changning shale gases were about 8% and 6% heavier than those in Weiyuan, respectively. Both shale gases had similar 3He/4He ratios but different 40Ar/36Ar ratios. These geochemical differences indicated complex geological conditions and shed light on the evolution of the Lonmaxi shale gas in the Sichuan Basin. In this study, we highlight the possible impacts on the geochemical characteristics of gas due to tectonic activity, thermal evolution, and migration. By combining previous gas geochemical data and the geological background of these natural gas fields, we concluded that four factors account for the differences in the Longmaxi Formation shale gas in the Sichuan Basin: a) A different ratio of oil cracking gas and kerogen cracking gas mixed in the closed system at the high over-mature stage. b) The Longmaxi shales in WY and CN have had differential geothermal histories, especially in terms of the effects from the Emeishan Large Igneous Province (LIP), which have led to the discrepancy in evolution of the shales in the two areas. c) The heterogeneity of the Lower Silurian Longmaxi shales is another important factor, according to the noble gas data. d) Although shale gas is generated in closed systems, natural gas loss throughout geological history cannot be avoided, which also accounts for gas geochemical differences. This research offers some useful information regarding the theory of shale gas generation and evolution.
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Wei, Lin, Shasha Sun, Dazhong Dong, Zhensheng Shi, Jia Yin, Shudi Zhang, Maria Mastalerz, and Xiong Cheng. "Petrographic Characterization and Maceral Controls on Porosity in Overmature Marine Shales: Examples from Ordovician-Silurian Shales in China and the U.S." Geofluids 2021 (May 31, 2021): 1–31. http://dx.doi.org/10.1155/2021/5582262.
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The pore structure characterization and its controlling factors in overmature shales are keys to understand the shale gas accumulation mechanism. Organic matter in source rocks is a mixture of various macerals that have their own specific evolutionary pathways during thermal maturation. Pores within macerals also evolve following their own path. This study focused on petrographic characterization and maceral controls on porosity in overmature marine shales in China and the United States. Shale from Ordos Basin in China was also selected as an example of overmature transitional shale for maceral comparison. Organic petrology techniques were used to identify maceral types and describe morphological features in detail; scanning electron microscopy techniques were then used to document the abundance and development of pores within macerals. Helium measurement, mercury intrusion capillary pressure, and CO2 adsorption were especially applied to quantify the pore structure of Wufeng-Longmaxi shale from Sichuan Basin in China. The vitrinite reflectance equivalent of the studied overmature samples is ~2.4%. The macerals within the studied marine shales are composed mainly of pyrobitumen and zooclasts. At this maturity, pyrobitumen develops abundant gas-related pores, and their volume positively correlates to gas content. Three types of pyrobitumen and its related pore structure are characterized in Wufeng-Longmaxi shales. Zooclasts contribute to total organic carbon (TOC) content but little to porosity. When the TOC content is above 1.51% in Wufeng-Longmaxi samples, the TOC content positively correlates to quartz content. Organic matter strongly controls micropore development. Pores of diameter ~ 0.5 nm provide a significant amount of micropore volume. Clay mineral and quartz contents control micro- and macropore increments in organic-lean shales. MICP results indicate that pores within 3-12 nm and 900-2500 nm account for a major contribution to pore volume obtained. Determining the proportions of pyrobitumen to zooclasts within the total organic matter in pre-Devonian organic-rich marine shales is important in predicting porosity and gas storage capacity in high-maturity shales.
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Abe, Kazunori, Nouman Zobby, and Hikari Fujii. "Petrophysical Characterizations of Shale Gas Reservoirs of the Ranikot Formation in the Lower Indus Basin, Pakistan." EPI International Journal of Engineering 3, no. 2 (January 22, 2021): 103–7. http://dx.doi.org/10.25042/epi-ije.082020.02.
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The complex pore structure with nano-pores of shale gas reservoirs has an impact on the hydrocarbon storage and transport systems. We examined the pore structure of the shales of the Ranikot Formation in the Lower Indus Basin, Pakistan to investigate the full scaled pore size distributions by using a combination of techniques, mercury injection capillary pressure analysis and low pressure gas adsorption methods using N2 and CO2. Isotherm curves obtained N2 and CO2 adsorptions were interpreted using density functional theory analysis for describing the nano-scaled pore size distributions. The pore geometry of the shales was estimated to be slit-type from the isotherm hysteresis loop shape. The pore size distributions determined the density functional theory showed the dominant pore size of below around 10 nm. The Micro-scale effects such as slippage and adsorption/desorption also significantly influence the gas flow in nano-pore structure. The gas flow regimes in shales are classified into four types Darcy flow, slip flow, transition flow, Knudsen flow based on the value of the Knudsen number. Applying the specific reservoir conditions in Ranikot shale and pore size distribution to the Knudsen number, the gas flow regimes of the Ranikot shales were estimated mostly within the transition and slip flow.
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Pan, Lei, Ling Chen, Peng Cheng, and Haifeng Gai. "Methane Storage Capacity of Permian Shales with Type III Kerogen in the Lower Yangtze Area, Eastern China." Energies 15, no. 5 (March 3, 2022): 1875. http://dx.doi.org/10.3390/en15051875.
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Marine–terrestrial transitional Permian shales occur throughout South China and have suitable geological and geochemical conditions for shale gas accumulation. However, the Permian shales have not made commercial exploitation, which causes uncertainly for future exploration. In this study, high-pressure methane (CH4) adsorption experiments were carried out on the Permian shales in the Lower Yangtze area, and the influences of total organic carbon (TOC) content and temperature on adsorption parameters were investigated. The characteristics and main controlling factors of methane storage capacity (MSC) of the Permian shales are discussed. The results show that the maximum adsorption and the adsorbed phase density of these Permian samples are positively correlated with TOC contents but negatively correlated with temperatures. The pores of organic matter in shale, especially a large number of micropores and mesopores, can provide important sites for methane storage. Due to underdeveloped pore structure and poor connectivity, the methane adsorption capacities of the Permian shales are significantly lower than those of marine shales. Compared with the Longmaxi shales, the lower porosity and lower methane adsorption of the Permian shales are reasonable explanations for their lower gas-in-place (GIP) contents. It is not suitable to apply the index system of marine shales to the evaluation of marine–terrestrial transitional shales. The further exploration of Permian shales in the study area should be extended to overpressure stable reservoirs with high TOC contents (e.g., >5%), high porosity (e.g., >3%), and deep burial (e.g., >2000 m).
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Peyaud, Jean-Baptiste, Melissa Vallee, Jim Benson, and Dave Taylor. "Evaluating the gas potential of Cooper Basin Permian lacustrine mudrocks: a comparison with North American marine shale gas reservoir." APPEA Journal 52, no. 2 (2012): 663. http://dx.doi.org/10.1071/aj11077.
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The methods to evaluate the potential of marine shale as gas producers have been refined during the past five years with the development of new logging tools and increased experience gained from activity in the US. While most shale plays in the US were deposited in a marine environment, in Australia, however, extensive shales were deposited in continental basins. The question is: are continental and marine shales similar enough for the same methodology to be applied—if not, how should it be adapted or changed? The type of organic matter, its abundance and the type of hydrocarbons it can generate may differ significantly between continental shale and marine shale. Long-range lateral continuity can be expected from marine deposits as water bodies are commonly wide and deposition processes are well known. Conversely, in continental environments water body sizes are more variable and usually smaller. In a marine environment, the formations containing organic matter are relatively easy to identify because accommodation depends on global events (eustatic variations, global tectonic events). In continental formations it is more difficult, as accommodation is strongly dependent on regional tectonics. In this extended abstract, a case from the Woodford shale (US) is compared to a case from the Cooper Basin (Australia).Differences in mineralogy, type, abundance and maturity of the organic matter are analysed and their impact on the log response is discussed. Finally, recommendations are made to adapt the methodology to continental shales.
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Xiang, Kui, Liangjun Yan, Gongxian Tan, Yuanyuan Luo, and Gang Yu. "Complex Resistivity Anisotropy Response Characteristics of Wufeng-Longmaxi Formation Shale in Southern Sichuan." Minerals 12, no. 11 (October 31, 2022): 1395. http://dx.doi.org/10.3390/min12111395.
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Electrical exploration has become an important means of shale gas reservoir exploration and evaluation, and is expected to play a key role in the later stages of reservoir fracturing and development. At present, the research on the electrical response characteristics of shale gas reservoirs and their relationship with reservoir parameters is extensive and in-depth, but there is little research on their complex resistivity anisotropy characteristics and influencing factors, which restricts petrophysical modeling and reservoir parameter prediction, and reduces the reliability of shale gas exploration and reservoir evaluation by electromagnetic methods. In this paper, shale samples from the Longmaxi Formation and the Wufeng Formation of shale gas wells in southern Sichuan were collected, the complex resistivity of 34 shales in bedding direction and vertical bedding direction were measured, and the induced polarization (IP) parameters of shales were extracted by inversion. The electrical anisotropy response characteristics under different temperature and pressure conditions were analyzed, and the influencing factors and laws of complex resistivity anisotropy of shales were revealed. Combined with the test results of shale porosity and permeability, the evaluation model of resistivity, polarizability and porosity and permeability parameters was established. The research results have formed a set of testing methods and analysis techniques for electrical anisotropy of shale reservoirs, which are mainly based on complex resistivity parameter testing. It is helpful to understand the electrical anisotropy characteristics of shale gas reservoirs in southern Sichuan; this will provide the theoretical and physical basis for shale gas reservoir evaluation and fracturing monitoring by electrical exploration.
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Hassan Zadeh, Ebrahim, Reza Rezaee, and Michel Kemper. "Quantitative analysis of seismic response to total organic content and thermal maturity in shale gas plays." APPEA Journal 51, no. 2 (2011): 704. http://dx.doi.org/10.1071/aj10084.
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Although shales constitute about 75% of most sedimentary basins, the studies dealing with their seismic response are relatively few, particularly for the organic rich shale gas. Mapping distribution of shale gas and identifying their maturation level and organic carbon richness is critically important for unconventional gas field exploration and development. This study analyses the sensitivity of acoustic and elastic parameters of shales to variations in pore fluid content. Based on the effective medium theory a rock physics model has been made by inversion of the shale stiffness tensor from sonic, density, porosity and clay content logs. Due to the lack of a generally agreed upon fluid substitution model for shale, a statistical approach to Gassmann’s Model using effective porosity in the near boundary conditions, has been developed to account for shale. Fluid substituted logs—for a variety of maturation levels—and gas saturations were generated and used to make the layered earth models. AVO and seismic forward modelling were performed using the rock physics modelled and the fluid substituted logs on layered models. As part of seismic forward modelling, simultaneous inversion is performed for each model to generate P-impedance, S-impedance and density volumes. The sensitivity of the models were analysed by histogram, cross plotting, cross section highlighting, and body checking techniques. This study showed a dramatic hydrocarbon content effect—specifically gas—in the seismic response of shales.
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Zhou, Qi. "Reservoir Forming Conditions of Paleogene Shale Gas and Oil in Liaohe Depression." Advanced Materials Research 926-930 (May 2014): 4344–47. http://dx.doi.org/10.4028/www.scientific.net/amr.926-930.4344.
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According to the data on the geology, geochemistry, experimental analysis and production test of Liaohe Depression, the reservoir forming conditions of shale gas and oil were analyzed in this study. It is found that the Paleogene shale in the sedimentary basin has an extensive distribution, large thickness, high organic carbon content and wide variation scope of maturity of organic matter. It provides the material conditions for the formation of shale gas and oil. The shales have developed micropores and fractures, which provide favorable reservoir space for the free hydrocarbons. Due to the strong adsorption ability of shale, the gas logging abnormal of total hydrocarbons is usually present in the shale. A huge reserve of shale gas and oil resources is indicated. The shale reservoir usually has a high content of brittle minerals, so the fracturing technique can be applied for development. Therefore, the Paleogene strata in Liaohe Depression contain abundant shale gas and oil and the associated tight gas and oil resources. The shale gas and oil in the hydrocarbon generation sag and the surrounding shales and the interbed are the new deposits under the deep exploitation of Liaohe Depression. The shale gas and oil in the West Sag has the highest potential.
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Shu, Yi, Shang Xu, Feng Yang, Zhiguo Shu, Pan Peng, Senxin Huang, and He Zhen. "The Role of Microfabric and Laminae on Pore Structure and Gas Transport Pathways of Marine Shales from Sichuan Basin, China." Geofluids 2020 (July 21, 2020): 1–19. http://dx.doi.org/10.1155/2020/8844229.
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This study investigated the effects of microfabric and laminae on the pore structure and gas transport pathways of the Silurian Longmaxi shales from Sichuan Basin. 23 shale samples with varied lithofacies were comprehensively investigated by mineralogy, organic geochemistry, pycnometry, and low-pressure nitrogen adsorption analysis. The fabric and laminae of these samples were identified using petrographic microscope and scanning electron microscopy. Permeabilities were measured using the nonsteady-state method on both perpendicular and parallel to bedding shales. The effective pore diameter controlling gas transport was estimated from gas slippage factors obtained in permeability measurements. These values were also compared to those calculated using the Winland equation. Siliceous shales studied are faintly laminated to nonlaminated and have larger porosity and specific surface area. Argillaceous/siliceous mixed shales are well laminated, whereas argillaceous shales contain many oriented clay flakes along the lamination. Both porosity and surface area are positively correlated with TOC content. Unlike most conventional reservoirs, there is a negative correlation between porosity and permeability values of the samples studied. Permeabilities parallel to bedding, ranging from 0.4 to 76.6 μD, are in control of the oriented clay flakes and silty microlaminae. Permeability anisotropy values of the shales vary between 1.3 and 49.8. Samples rich in oriented clay flakes and microlaminated fabric have relatively larger permeability and permeability anisotropy values. The effective transport pore diameters derived from gas slippage measurements are slightly lower than those calculated from the Winland equation. However, both methods have shown that the effective transport pore diameters of argillaceous shales (averaging 552 nm) are significantly higher than siliceous shales (averaging 198 nm), which underlines the control of microfabric, rather than porosity, on gas transport pathways of the shales studied.
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Mishra, Subhashree, Vinod A. Mendhe, Alka D. Kamble, Mollika Bannerjee, Atul K. Varma, Bhagwan D. Singh, and Jai K. Pandey. "Prospects of shale gas exploitation in Lower Gondwana of Raniganj Coalfield (West Bengal), India." Journal of Palaeosciences 65, no. (1-2) (December 31, 2016): 31–46. http://dx.doi.org/10.54991/jop.2016.297.
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Geochemical analyses such as proximate, pyrolysis, TOC and FTIR, and other analyses like surface area, pore size, pore volume (using low–pressure N2 physisorption measurements) and SEM were performed on the shale samples derived from Early Permian Barakar and Late Permian Barren Measures formations of the Raniganj Coalfield, West Bengal. Rock–Eval pyrolysis and TOC data indicated that the heterogeneity of Barren Measures and Barakar shales is laterally varying, but in general, factors which support the occurrence of shale gas accumulations include a moderate to high TOC content (3.38–7.87 wt.%) with sufficient thermal maturity and type III–IV organic matters (kerogens). FTIR spectra indicate the presence of quartz and kaolinite with absorbance bandwidth between 1200–800 cm−1 and 3750–3400 cm−1, respectively. Abundance of quartz, as compared to clay, points towards the brittle characteristics of shales favourable for good fracability. Besides, mesopores and macropores are well–developed and the capacity of gas generation and adsorption are significant.
On the basis of SEM, the pores are classified into four types– (i) inter–granular pores, (ii) dissolve pores, (iii) composite inter–granular pores, and (iv) hair line micro–fractures. The BET multipoint surface area varies from 8.104 to 16.937 m2/g and 17.376 to 29.675 m2/g for Barakar and Barren Measures shales, respectively. Size of the pores varies from 3.072 to 3.728 nm for the Barakar shales and 2.984 to 3.521 nm for the Barren Measures shales, as measured by BJH method. Overall, it is observed that mesopores, macropores, micro–fractures and micropores are adequate in the samples and the studied shales are having interconnected networks of natural cracks and pores system, which may control the storage and migration of shale gas in the reservoir.
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Liu, Weiwei, Kun Zhang, Zhenxue Jiang, Shu Jiang, Yan Song, Chengzao Jia, Yizhou Huang, et al. "Effect of the hydrothermal activity in the Lower Yangtze region on marine shale gas enrichment: A case study of Lower Cambrian and Upper Ordovician-Lower Silurian shales in Jiangye-1 well." Open Geosciences 10, no. 1 (October 25, 2018): 582–92. http://dx.doi.org/10.1515/geo-2018-0046.
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Abstract Finding favorable sites for the exploration of shale gas, is still one of the important areas of research that needs immediate attention. The content of organic matter in shale plays a crucial role in the hydrocarbon generation potential, reservoir space and gas-bearing capacity of shales. Therefore, studying the sedimentary environment of organic shale can provide a scientific basis for locating favorable exploration areas for shale gas. The article takes the Lower Cambrian and the Upper Ordovician-Lower Silurian shales in the Yangtze region as the research object and selects representative wells to quantitatively calculate the existence of excess silicon in shale siliceous minerals and the content of excess silicon. Then, the origin of excess silicon can be clarified by the Al, Fe and Mn elemental analysis. Finally, the sedimentary organic matter enrichment mechanism is analyzed from water oxidation-reduction environments and biological productivity. The results of the study show that the excess silicon in the Lower Cambrian and Upper Ordovician-Lower Silurian shales in the Lower Yangtze region is of hydrothermal origin. The hydrothermal activity improves biological fertility on the one hand; whereas on the other hand, it can enhance the reducing capacity of the bottom water conducive for the preservation of organic matter thereby enriching the sedimentary organic matter. The place near the junction of Yangtze plate and Cathaysian plate, where hydrothermal activities were more intense, provided favorable loci for shale gas exploration in the Lower Yangtze region. It was observed that, since the hydrothermal activity was stronger in the Early Cambrian than in the Late Ordovician-Early Silurian times, the total organic carbon (TOC) content of the Lower Cambrian shale was higher than that of the Upper Ordovician-Lower Silurian shales.
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Testa, bridget Mintz. "Homes on the Shales." Mechanical Engineering 135, no. 12 (December 1, 2013): 30–35. http://dx.doi.org/10.1115/1.2013-dec-2.
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This article focuses on different opportunities and challenges posed by shale oil and gas reserves in Texas. Texas has about as many drilling rigs as the rest of the country combined. There are places in which the shale boom feels more like a stampede. Texans have long accommodated themselves to the oil industry and sought its upside. Over the years, the combination of high oil prices and the new application of hydraulic fracturing techniques to unlock shale gas and oil have led to resurgence. Fort Worth’s ordinance, regulating gas drilling inside the city, is widely seen as a success. Oil and gas operators evidently see the ordinance as a cooperative effort, since they generally abide by it and keep working with the city and residents to update it. As per expert’s view, the State has not put adequate emphasis on the rights of landowners.
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Uzoegbu, M. U., and C. U. Ugwueze. "Comparative Assessment of Hydrocarbon Generation Potential of Organic Matter from Shale Sediments along Isugwuato – Okigwe Axis, Anambra Basin, SE Nigeria." Journal of Applied Sciences and Environmental Management 25, no. 3 (April 27, 2021): 353–62. http://dx.doi.org/10.4314/jasem.v25i3.8.
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TRACT: The Cretaceous sediments in the Anambra Basin (SE Nigeria) consist of a cyclic succession of coals, carbonaceous shales, silty shales and siltstones interpreted as deltaic deposits. The objective of this study is to compare the hydrocarbon generation potential of organic matter from shale sediments along Isugwuato-Okigwe axis in the Anambra Basin, Nigeria. Data obtained indicates the presence of Type III kerogen with Tmax values are between 424 and 441ºC indicating that the shales are thermally immature to marginally mature with respect to petroleum generation. Hydrogen Index (HI) values range from 14 to 388.9mgHC/gTOC while S1 + S2 yields values ranging from 0.2 to 1.0mgHC/g rock, suggesting that the shale have gas generating potential. The TOC values rangesfrom 1.3 to 3.0%, an indication of a good source rock of terrestrially derived organic matter. The high oxygen index (OI) (16.3 mgCO2g-1TOC), TS (1.35) and TOC/TS (1.5) suggest deposition in a shallow marine environment. Based on the kerogen type, shales from the studied area will equally generate oil and gas if its organic matter attained sufficient thermal temperature.
Keywords: Shale, kerogen type, maturity, oil generation.
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Greenstreet, Carl. "From play to production: the Cooper unconventional story—20 years in the making." APPEA Journal 55, no. 2 (2015): 407. http://dx.doi.org/10.1071/aj14042.
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The Cooper Basin is Australia’s leading onshore producing hydrocarbon province, having produced more than 6 Tcf of natural gas since 1969. The basin is undergoing renewal 45 years later, driven by the emerging growth of east coast LNG export-driven demand. Following North America’s shale gas revolution, the Cooper Basin’s unconventional potential is now widely appreciated and it is believed to hold more than 100 Tcf of recoverable gas. This resource potential is held in four stacked target unconventional lithotypes, each having demonstrated gas flows: tight sands—heterogeneous stacked fluvial sands; deep coal—porous dry coals, oversaturated with gas; shales—thick, regionally extensive lacustrine shales; and, hybrid shales—mixed lithotype containing interbedded tight sandstones, shales and coals. Industry activity initially focused on the Nappamerri Trough, where more than 25 contemporary exploration wells have been drilled, proving up an extensive basin-centred gas play with >1,000 m of continuous overpressured gas saturated section outside of structural closure. Santos has had a team focused on unconventional resources for nearly 20 years and successful results have been quickly tied into the producing infrastructure. This has been demonstrated with the Moomba–191 REM shale success, Moomba–194 and the recent Moomba–193H connection, one of the basin’s first fracture-stimulated horizontal wells. Prospective geology, existing infrastructure and market access makes the Cooper Basin well positioned for unconventional success. Each resource play is unique and commercial success requires considered adaptation of established technologies and workflows, based on a understanding of local geological and reservoir conditions. Commercialisation activity now seeks to define play fairways, characterise and prioritise reservoir targets and determine appropriate drilling and completion approaches.
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Ahmed, Waquar, G. M. Bhat, J. Mclennan, H. N. Sinha, S. Kanungo, S. K. Pandita, Y. Singh, et al. "Kerogen typing using palynofacies analysis in Permian Barren Measures Formation in Raniganj sub–basin, East India." Journal of Palaeosciences 67, no. (1-2) (December 31, 2018): 113–22. http://dx.doi.org/10.54991/jop.2018.52.
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The objective of the study is the simple assessment of kerogen type in Barren Measures Formation shale using palynofacies. The Barren Measures Formation sandwiched between the coal–rich formations consist of organic–rich black carbonaceous shales. These ̴ 1000 m thick, black shales are in the productive gas window having kerogen types III with excellent gas generation potential as proven in recent pyrolysis studies. In this study, the palynological analysis of the four core samples of the Barren Measures Formation shale was done. The analysis has revealed three types of kerogen assemblages, viz. palynomorphs, phytoclasts and amorphous organic matter. The palynomorph assemblage consists of spores and pollen; phytoclasts consist of secondary xylem wood macrophyte plant debris and amorphous organic matter is a higher plant decomposed product. Based on the application of published kerogen classification and correlation of Tyson (1995), the pure kerogen type in these shales is categorized as mixed type; type II (oil prone) and type III (gas prone). However, the gas–prone kerogen assemblage gets relatively dominant in the samples from greater depth in the studied borehole. Our results are analogous to the previously published outcomes of kerogen typing evaluated using Rock–Eval pyrolysis experiments.
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Ibad, Syed Muhammad, and E. Padmanabhan. "Major, trace, and rare earth element geochemistry of black shales from Devonian Sanai Formation in Northwestern Peninsula Malaysia: implications for the depositional environment, provenance, and tectonic setting." IOP Conference Series: Earth and Environmental Science 1003, no. 1 (April 1, 2022): 012023. http://dx.doi.org/10.1088/1755-1315/1003/1/012023.
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Abstract In this study major, trace, and rare earth elements (REEs) content of Sanai (SA) shales were determined by XRF-ICP-OES and ICP-MS. These results were used to probe tectonic setting, depositional environment, and provenance and of the SA Formation black shale. These black shales contain an average total organic carbon (TOC) content of 2.68 wt. %. Black shales from SA formation were deposited in the active continental margin based on ternary diagrams of La–Th–Sc and Th–Sc–Zr/10. SiO2 is rich in SA shales with avg. 59.5% while Al2O3 is the second most dominant major oxides with avg. 15.8%. Major oxides of the Western Peninsula (WP) Malaysia shale and hot shale gas reservoirs from China are also compared for the assessment. Redox element ratios infer deposition of the black shale most likely occurred in oxic to the anoxic environment. SA Formation black shales show a low Sr/Ba (< 0.5) value, indicating low salinity during the deposition. Geochemistry results indicate that the SA black shales seem to have been originated principally from the felsic source rock which might be granite in this case.
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Huang, Yuqi, Peng Zhang, Jinchuan Zhang, Xuan Tang, Chengwei Liu, and Junwei Yang. "Fractal Characteristics of Pores in the Longtan Shales of Guizhou, Southwest China." Geofluids 2020 (November 21, 2020): 1–16. http://dx.doi.org/10.1155/2020/8834758.
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The pore structure of marine-continental transitional shales from the Longtan Formation in Guizhou, China, was investigated using fractal dimensions calculated by the FHH (Frenkel-Halsey-Hill) model based on low-temperature N2 adsorption data. Results show that the overall D 1 (fractal dimension under low relative pressure, P / P 0 ≤ 0.5 ) and D 2 (fractal dimension under high relative pressure, P / P 0 > 0.5 ) values of Longtan shales were relatively large, with average values of 2.7426 and 2.7838, respectively, indicating a strong adsorption and storage capacity and complex pore structure. The correlation analysis of fractal dimensions with specific surface area, average pore size, and maximum gas absorption volume indicates that D 1 can comprehensively characterize the adsorption and storage capacity of shales, while D 2 can effectively characterize the pore structure complexity. Further correlation among pore fractal dimension, shale organic geochemical parameters, and mineral composition parameters shows that there is a significant positive correlation between fractal dimensions and organic matter abundance as well as a complex correlation between fractal dimension and organic matter maturity. Fractal dimensions increase with an increase in clay mineral content and pyrite content but decrease with an increase in quartz content. Considering the actual geological evaluation and shale gas exploitation characteristics, a lower limit for D 1 and upper limit for D 2 should be set as evaluation criteria for favorable reservoirs. Combined with the shale gas-bearing property test results of Longtan shales in Guizhou, the favorable reservoir evaluation criteria are set as D 1 ≥ 2.60 and D 2 ≤ 2.85 . When D 1 is less than 2.60, the storage capacity of the shales is insufficient. When D 2 is greater than 2.85, the shale pore structure is too complicated, resulting in poor permeability and difficult exploitation.
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Qu, Yiqian, Wei Sun, Song Guo, Shuai Shao, and Xiuxiang Lv. "A gas-content calculation model for terrestrial shales in the Kuqa Depression, the Tarim Basin, Western China." Interpretation 7, no. 2 (May 1, 2019): T513—T524. http://dx.doi.org/10.1190/int-2018-0127.1.
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Because shale gas content plays a very important role in the evaluation of gas shale potential, its calculation and prediction become obligatory. We used two predictive models, namely, the Langmuir and Ambrose models, to calculate the shale gas content. The parameters involved in these two models are calculated by various experiments and analytic methods, including indirect prediction, the isothermal adsorption test, X-ray diffraction analysis, total organic carbon (TOC) measurement, pyrolysis, and porosity measurement. Then, a new calculation model that is applicable to shales in the Kuqa Depression, Tarim Basin, is established. Further research on influential factors of gas content in well YN2 is implemented. The result indicates that the gas content of terrestrial shales is more influenced by TOC abundance than by the content of clay minerals and quartz. The main parameters in the new calculation model are the TOC, depth, porosity, and gas saturation. The Jurassic shale gas in well YN2 is speculated to be mainly adsorption gas, with a dominant proportion of 75%–90% in the total gas content. As the formation depth increases, the free-gas content rises continuously, whereas the adsorption gas content first increases and then approaches the equilibrium value or even tends to decrease slightly. Based on the foregoing results, the target layer, the Yengisar Formation, is predicted to possess an enormous amount of shale gas potential, with an average total gas content of [Formula: see text].
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Han, Tongcheng, Hongyan Yu, and Li-Yun Fu. "Correlations between the static and anisotropic dynamic elastic properties of lacustrine shales under triaxial stress: Examples from the Ordos Basin, China." GEOPHYSICS 86, no. 4 (June 15, 2021): MR191—MR202. http://dx.doi.org/10.1190/geo2020-0761.1.
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Shales are abundant and are increasingly important for the hydrocarbon industry as source rocks and unconventional reservoirs. The anisotropic dynamic elastic properties of shales are important in the exploration stage of shale reservoirs whereas their static elastic properties are key for the hydraulic fracturing for the more efficient development of shale gas and oil. However, the correlations between the static and anisotropic dynamic elastic properties that could provide a basis for the seismic methods to potentially evaluate the fracturing ability of shales without the need of cored samples from the borehole are still poorly understood. We have demonstrated, through dedicated simultaneous laboratory measurements of the anisotropic velocities and the strains of samples under triaxial stress, how the static and anisotropic dynamic elastic properties are correlated in seven lacustrine shales from the Ordos Basin, one of the major shale gas plays in China. The results show that the static and anisotropic dynamic elastic properties are stress-dependent. More importantly, the anisotropic velocities are found to be approximately linearly correlated with the axial strains of the samples at differential stress (the difference between axial stress and confining stress) greater than 30 MPa, with the slopes of the linear correlations in excellent linear relationship with Young’s moduli determined from the static elastic measurements. The results not only reveal the internal link between the static and anisotropic dynamic elastic properties of lacustrine shales, but they also pave a potential way for the anisotropic seismic explorations to remotely evaluate the fracturing ability of shales.
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Cao, Yuanhao, Wei Chen, Yinnan Yuan, Tengxi Wang, and Jiafeng Sun. "Gas Generation and Its Carbon Isotopic Composition during Pyrite-Catalyzed Pyrolysis of Shale with Different Maturities." Processes 10, no. 11 (November 4, 2022): 2296. http://dx.doi.org/10.3390/pr10112296.
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In this study, two shale samples with different maturities, from Geniai, Lithuania (Ro = 0.7%), and Wenjiaba, China (Ro = 2.7%), were selected for open-system pyrolysis experiments at 400 °C and 500 °C, respectively. The generation of isotopic gases from the shales with different maturities was investigated, and the effects of pyrite catalysis on the carbon isotopic compositions were also studied. It was found that CO2, CH4 and their isotopic gases were the main gaseous products of the pyrolysis of both shales, and more hydrocarbon gases were generated from the low-maturity Geniai shale. The δ13C1 values fluctuated from −40‰ to −38‰, and δ13C2 showed higher values (−38‰~−34‰) for the Geniai shale. In addition, its δ13CCO2 values ranged from −28‰ to −26‰. Compared with the Geniai shale, lower δ13C1 values (−43‰~−42‰) and higher δ13CCO2 values (−19‰~−14‰) were detected for the Wenjiaba shale. As temperature increased, CH4 became isotopically lighter and C2H6 became isotopically heavier, which changes were due to the mass-induced different reaction rates of 12C and 13C radicals. Furthermore, the pyrite made the kinetic isotope effect stronger and thus made the CH4 isotopically lighter for both shales, especially at the lower temperature of 400 °C.
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Wang, Xiangzeng, Lixia Zhang, Chengfu Jiang, and Bojiang Fan. "Hydrocarbon storage space within lacustrine gas shale of the Triassic Yanchang Formation, Ordos Basin, China." Interpretation 3, no. 2 (May 1, 2015): SJ15—SJ23. http://dx.doi.org/10.1190/int-2014-0125.1.
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The Triassic Yanchang Formation lacustrine shale is a source of conventional oil accumulation in the Ordos Basin, China. The Yanchang Formation, a hybrid system of organic-rich shale, interbedded silty shale, and siltstone, is believed to be a potential unconventional oil and gas play. Our crossdisciplinary investigation of the storage space included the outcrop description, core observation, thin sections, and scanning electron microscope pore imaging. We evaluated the results from these techniques to reveal that the storage space within the Yanchang Formation shales included primary intergranular pores, secondary generated pores, tectonic fractures, and bedding-parallel fractures. We conducted adsorption experiments, combined with burial and thermal history, in which the primary migration process can be divided into three stages. In the Early Jurassic, organic matter did not reach the oil generation threshold. From the Late Jurassic to the Early Cretaceous, organic matter entered the oil generation window, and gas was generated and stored as adsorbed gas, dissolved gas, and free gas. From the Middle to Late Cretaceous, the storage of shale gas was dynamically transformed by tectonic uplift. Variations in chemical and carbon isotopic compositions from canister-core desorption were directly related to the gas supply in shales. An abrupt decrease in gas dryness and positive [Formula: see text] values indicated the depletion of gas supply drainage. Our ultimate recovery factor reached 70%.
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Schettler, P. D., and C. R. Parmely. "Gas Composition Shifts in Devonian Shales." SPE Reservoir Engineering 4, no. 03 (August 1, 1989): 283–87. http://dx.doi.org/10.2118/17033-pa.
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Fan, Kun Kun, Ren Yuan Sun, Zi Chao Ma, Yun Fei Zhang, Yan Wei, and Zhao Zhao Zhang. "Effect of Fracture Parameters on Desorption Properties of Shales." Applied Mechanics and Materials 397-400 (September 2013): 252–56. http://dx.doi.org/10.4028/www.scientific.net/amm.397-400.252.
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Horizontal well and hydraulic fracturing are the main technologies for shale gas development. The desorption properties of shales are very important data for shale gas development. In order to simulate the desorption process in shales with horizontal well and fractures, a new method for shale sample preparation and a new experimental system for the evaluation were developed. The effect of the number and half-length of fractures on the desorption rate and the desorption equilibrium time were measured when the system pressure drops from 9.2MPa to 7MPa. Experiments show that the initial desorption rate increases and the equilibrium time decreases with the increase of the number and half-length of fractures. Within the scope of the experiments, the number of fractures is more important than the half-length of fractures for the desorption rate.
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Liu, Zengqin, Shaobin Guo, Yiming Huang, Zhe Cao, Talihaer· Yeerhazi, and Weifu Cao. "The Tight Sand Reservoir Characteristics and Gas Source in Coal Measures: A Case Study of Typical Areas in China." Geofluids 2022 (September 10, 2022): 1–17. http://dx.doi.org/10.1155/2022/4983334.
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Interbedded sandstones, shales, and coal seams were formed in marine-continental transitional environments of coal measures, and the gas source of its tight sand gas has been uncertain, which hinders the progress of natural gas exploration. This article uses the Longtan tight sand gas in west Guizhou as an example to investigate the reservoir features, gas charging history, and main source rock of tight sand gas by examining thin sections, scanning electron microscopy images, X-ray diffraction results, and the fluid inclusions with burial and thermal histories and noble gas analysis. The Longtan sandstones in this study are classified as litharenites which are characterized by low compositional and textural maturities, and high clay contents, and are distinguished petrographically from conventional sandstones by the extensive existence of micropores and microfractures. The results of the homogenization temperatures of the fluid inclusions show that the Longtan tight sand gas is a single-stage accumulation which occurred during the Late Triassic. Furthermore, through the analysis of the helium and argon isotopes of noble gases, a calculation model was established for determining the shale and coal contributions to the tight sand gas. The research results show that the Longtan tight sand gas mainly belongs to the crust-derived gas, mostly from the Longtan shale-derived contribution and to a lesser extent from the Longtan coal-derived contribution. The measured 40Ar/36Ar values of the Longtan shales and coals are consistent with the forecasted 40Ar/36Ar values from the calculation model, demonstrating that the model is viable to calculate the source rock contribution to the tight sand gas. Therefore, the Longtan shales as main source rocks can generate hydrocarbons to charge neighboring tight sandstones to form tight gas accumulation in the Longtan Formation, which provides an opportunity for tight gas development in west Guizhou.
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Zheng, Aiwei, Hanyong Bao, Li Liu, Mingkai Tu, Changpeng Hu, and Lei Yang. "Investigation of Multiscaled Pore Structure of Gas Shales using Nitrogen Adsorption and FE-SEM Imaging Experiments." Geofluids 2022 (June 7, 2022): 1–13. http://dx.doi.org/10.1155/2022/1057653.
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Nanopore in shales is the place for hydrocarbon accumulation and migration. However, there is a lack of understanding of the nanopore structure with regard to their ultratight and multiscaled nature. Here, the porous morphology of gas shales from the Sichuan Basin of China was investigated using field emission-scanning electronic microscopy (FE-SEM) with high resolution. Low-pressure nitrogen adsorption experiments at 77 K were conducted to obtain the adsorption-desorption isotherms, BET-specific surface area, pore size distribution, pore volume, and average pore diameter values. Research results show that pores of the studied shales are at the nanometer scale, and the average pore diameter is between 3 and 5 nm. The pore structure of these shales is complicated, which is not only predominately mesopores (pore diameter at 2–50 nm) but also some micropores ( pore diameter < 2 nm ) and macropores ( pore diameter > 50 nm ). The specific surface area of shales ranges from 13 to 30 m2/g. The micropore volume and mesopore volume occupy the total pore volume highly up to 77%–92%, which indicates that micropores and mesopores are the main storage place for shale gas. Through the analysis of adsorption isotherms and hysteretic loops, there are mainly two kinds of pores in shales, including ink-bottle-like pores and slit pores. Micropores of these shales are mainly related to organic matter, while macropores are mainly related to clay minerals. The estimation about porosity using the combined physical model shows that organic matter and clay minerals contribute about 50% and 33% to the porosity of these shales, respectively.
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Guo, Wei, Weijun Shen, Shangwen Zhou, Huaqing Xue, Dexun Liu, and Nan Wang. "Shale favorable area optimization in coal-bearing series: A case study from the Shanxi Formation in Northern Ordos Basin, China." Energy Exploration & Exploitation 36, no. 5 (December 19, 2017): 1295–309. http://dx.doi.org/10.1177/0144598717748951.
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Shales in the Well district of Yu 106 of the Shanxi Formation in the Eastern Ordos Basin is deposited in the swamp between delta plains, distributary river channels, natural levee, the far end of crevasse splay, and depression environments. According to organic geochemistry, reservoir physical property, gas bearing capacity, lithology experimental analysis, combined with the data of drilling, logging, testing and sedimentary facies, the reservoir conditions of shale gas and the distribution of an advantageous area in Shanxi Formation have been conducted. The results show that the total organic carbon content of the Shanxi Formation is relatively high, with an average content value of 5.28% in the segment 2 and 3.02% in segment 1, and the organic matter is mainly kerogen type II2 and III. The maturity of organic matter is high with 1.89% as the average value of Ro which indicates the superior condition for gas generation of this reservoir. The porosity of shales is 1.7% on average, and the average permeability is 0.0415 × 10−3 µm2. The cumulative thickness is relatively large, with an average of 75 m. Brittle mineral and clay content in shales are 49.9% and 50.1%, respectively, but the burial depth of shale is less than 3000 m. The testing gas content is relatively high (0.64 × 104 m3/d), which shows a great potential in commercial development. The total organic carbon of the segment 2 is higher than that of the segment 1, and it is also better than segment 1 in terms of gas content. Based on the thickness of shale and the distribution of sedimentary facies, it is predicted that the advantageous area of shale gas in the segment 2 is distributed in a striped zone along the northeast and the northsouth direction, which is controlled by the swamp microfacies between distributary river channels.
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Cao, Taotao, Hu Liu, Anyang Pan, Mo Deng, Qinggu Cao, Ye Yu, Yanran Huang, and Zhenghui Xiao. "Marine Shale Gas Occurrence and Its Influencing Factors: A Case Study from the Wufeng-Longmaxi Formation, Northwestern Guizhou, China." Geofluids 2022 (March 23, 2022): 1–27. http://dx.doi.org/10.1155/2022/2036451.
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Organic-rich shales were found in the Ordovician to Silurian Wufeng-Longmaxi Formation in northwestern Guizhou province, China, which has high shale gas content revealed by field measurement. Shale gas occurrence, free gas/sorbed gas ratio, and their influencing factors are crucial for shale gas exploitation strategy. Results indicated that the Wufeng-Longmaxi shales are dominated by type I kerogen, with total organic carbon (TOC) and equivalent vitrinite reflectance (eqvRo) of 0.77%–6.98% and 2.37%–2.53%, respectively. The total porosity and permeability are in the range of 1.23%–8.43% and 3 × 10 − 4 – 2.23 × 10 − 1 mD, respectively. FE-SEM observation and correlation analysis show shale porosity is dominated by organic matter (OM) pores, followed by interparticle (interP) pores related to brittle minerals. CH4, derived from oil cracking, is the main component of shale gas, but its proportion is lower than that in Fuling and Weiyuan areas, probably due to the weak preservation condition. Desorption gas and lost gas determined by in situ desorption test are 0.42–1.54 cm3/g and 1.9–7.14 cm3/g, respectively, and Langmuir volume ( V L ) from isothermal adsorption experiment is 1.63–4.78 cm3/g. Shale gas content is positively correlated with micropore volume, mesopore volume and TOC content but negatively correlated with macropore volume and clay mineral content, indicating that methane is preferentially stored in micropores (<2 nm) and mesopores (2–50 nm) related to OMs. By comparing actual total gas content with theoretical gas content, shale gas is considered to exist primarily in sorbed state, and the free gas proportion can increase with increased TOC content, due to that OM pores with larger sizes are also main space for free gas. Combined with the two methods, it can result in accurate calculations of shale gas reserves and free/sorbed gas ratio. Based on this understanding, a model of shale gas occurrence was proposed, which can provide a reference for shale gas exploitation in normal pressure areas.
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Pu, Hui, Yuhe Wang, and Yinghui Li. "How CO2-Storage Mechanisms Are Different in Organic Shale: Characterization and Simulation Studies." SPE Journal 23, no. 03 (October 4, 2017): 661–71. http://dx.doi.org/10.2118/180080-pa.
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Summary Widely distributed organic-rich shales are being considered as one of the important carbon-storage targets, owing to three differentiators compared with conventional reservoirs and saline aquifers: (1) trapping of a significant amount of carbon dioxide (CO2) permanently; (2) kerogen-rich shale's higher affinity of CO2; and (3) existing well and pipeline infrastructure, especially that in the vicinity of existing power or chemical plants. The incapability to model capillarity with the consideration of imperative pore-size-distribution (PSD) characteristics by use of commercial software may lead to inaccurate modeling of CO2 injection in organic shale. We develop a novel approach to examine how PSD would alter phase and flow behavior under nanopore confinements. We incorporate adsorption behavior with a local density-optimization algorithm designed for multicomponent interactions to adsorption sites for a full spectrum of reservoir pressures of interests. This feature elevates the limitation of the Langmuir isotherm model, allowing us to understand the storage and sieving capabilities for a CO2/N2 flue-gas system with remaining reservoir fluids. Taking PSD data of Bakken shale, we perform a core-scale simulation study of CO2/N2 flue-gas injection and reveal the differences between CO2 injection/storage in organic shales and conventional rocks on the basis of numerical modeling.
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Jing, Tie Ya, Fu Feng, Guang Yang, and Jian Zhang. "The Geological Characteristics for Pre-Cambrian Shale Gas Accumulation in China." Applied Mechanics and Materials 707 (December 2014): 303–6. http://dx.doi.org/10.4028/www.scientific.net/amm.707.303.
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China has huge shale gas resources potential. The exploitation of shale gas can effectively reduce atmosphere pollution and relieve the energy shortage in China. Organic rich shale in pre-Cambrian period mainly lies to North China and Yangtze areas. The shales were developed in continental shelf and restricted marine basin. The distribution is stable with the thickness ranging from 10m-150m. The geochemistry characteristics are favored for shale gas accumulation for pre-Cambrian shale. The shale mineral is mainly quartz and feldspar. The pre-Cambrian formations have favored geological condition for shale gas accumulation. The favored intervals and regions for development of shale gas are Doushantuo shale in Upper Yangtze areas and Hongshuizhuang shale in northern Hebei Province or Jianchang Basin in western Liaoning Province.
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Zheng, Yijun, Yuhong Liao, Yunpeng Wang, Yongqiang Xiong, and Ping’an Peng. "Effects of Regional Differences in Shale Floor Interval on the Petrophysical Properties and Shale Gas Prospects of the Overmature Niutitang Shale, Middle-Upper Yangtz Block." Minerals 12, no. 5 (April 26, 2022): 539. http://dx.doi.org/10.3390/min12050539.
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The lower Cambrian Niutitang/Qiongzhusi shale gas in the Middle-Upper Yangtz Block had been regarded as a very promising unconventional natural gas resource due to its high total organic carbon, great thickness, and large areal distribution. However, no commercial shale gas fields have yet been reported. From the northwest to the southeast there are considerable differences in the sedimentary environments, lithology, and erosive nature of the underlying interval (the floor interval) of the Niutitang shale. However, systematic research on whether and how these regional differences influence shale petrophysical properties and shale gas preservation in the Niutitang shale is lacking. A comparison of Niutitang shale reservoirs as influenced by different sedimentary and tectonic backgrounds is necessary. Samples were selected from both the overmature Niutitang shales and the floor interval. These samples cover the late Ediacaran and early Cambrian, with sedimentary environments varying from carbonate platform and carbonate platform marginal zone facies to continental shelf/slope. Previously published data on the lower Cambrian samples from Kaiyang (carbonate platform), Youyang (carbonate platform marginal zone) and Cen’gong (continental shelf/slope) sections were integrated and compared. The results indicate that the petrophysical properties of the floor interval can affect not only the preservation conditions (sealing capacity) of the shale gas, but also the petrophysical properties (pore volume, porosity, specific surface area and permeability) and methane content of the Niutitang shale. From the carbonate platform face to the continental shelf/slope the sealing capacity of the floor interval gradually improves because the latter gradually passes from high permeability dolostone (the Dengying Formation) to low permeability dense chert (the Liuchapo Formation). In addition, in contrast with several unconformities that occur in the carbonate platform face in the northern Guizhou depression, no unconformity contact occurs between the Niutitang shale and the floor interval on the continental shelf/slope developed in eastern Chongqing Province and northwestern Hunan Province. Such regional differences in floor interval could lead to significant differences in hydrocarbon expulsion behaviour and the development of organic pores within the Niutitang shale. Therefore, shale gas prospects in the Niutitang shales deposited on the continental shelf/slope should be significantly better than those of shales deposited on the carbonate platform face.
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Tang, Xianglu, Wei Wu, Guanghai Zhong, Zhenxue Jiang, Shijie He, Xiaoxue Liu, Deyu Zhu, Zixin Xue, Yuru Zhou, and Jiajing Yang. "Characteristics and Origin of Methane Adsorption Capacity of Marine, Transitional, and Lacustrine Shales in Sichuan Basin, China." Geofluids 2021 (April 21, 2021): 1–12. http://dx.doi.org/10.1155/2021/6674815.
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Adsorbed gas is an important component of shale gas. The methane adsorption capacity of shale determines the composition of shale gas. In this study, the methane adsorption capacity of marine, transitional, and lacustrine shales in the Sichuan Basin was analyzed through its isothermal adsorption, mineral composition, water content, etc. The results show that the methane adsorption capacity of marine (Qiongzhusi Formation and Longmaxi Formation), transitional (Longtan Formation), and lacustrine (Xujiahe Formation and Ziliujing Formation) shales is significantly different. The Longtan Formation has the strongest methane adsorption capacity. This is primarily related to its high organic matter and organic matter type III content. The methane adsorption capacity of the lacustrine shale was the weakest. This is primarily related to the low thermal evolution degree and the high content of water-bearing clay minerals. Smectite has the highest methane adsorption capacity of the clay minerals, due to its crystal structure. The water content has a significant effect on methane adsorption largely because water molecules occupy the adsorption site. Additionally, the temperature and pressure in a specific range significantly affect methane adsorption capacity.