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Great progress has been made in marine shale gas of Wufeng–Longmaxi formations in the Sichuan Basin. However, shale gas exploration in the complex structural belt around the Sichuan Basin still faces great challenges. In this study, shales of Wufeng–Longmaxi formations collected from the northern Guizhou were taken as the studied target, organic matter (OM) characteristics, mineral composition, pore structure, methane adsorption capacity and in situ desorption gas content were measured, and the controlling factors of shale gas content were further discussed. The results indicated that the sedimentary facies of Wufeng–Longmaxi formations in north Guizhou varies from shallow‐water shelf facies to deep‐water shelf facies from south to north, and organic‐rich shales are primarily distributed in Daozhen‐Xishui areas, with a maximum thickness of about 80–100 m. Organic‐rich shales are characterized by high total organic carbon (TOC) content, high thermal maturation and type I–II1 kerogens, which can be comparable with those in commercially produced shale gas field in Sichuan Basin. High‐quality shale gas reservoirs generally have a high content of brittle minerals, making them easier to be fractured. OM pores are the dominanted pore type in the studied shales, followed by intergranular pores associated with brittle minerals, dissolution pores within carbonate grains and microcracks, while clay mineral‐related pores are poorly developed. The Wufeng–Longmaxi Formation shales generally have strong methane adsorption capacities, but these vary greatly across different areas. Shale gas adsorption capacity is primarily controlled by TOC content and thermal maturation level. Similarly, total gas content, including desorption gas and lost gas, varies greatly in different areas, and it is obviously lower than that in Fuling and Luzhou shale gas field, due to the loss of shale gas and low‐pressure coefficient in the complex structural zone. It is worth explaining that shale gas is not always low in northern Guizhou, which is determined by burial depth and the distance of great fractures. Shale gas content is relatively high in LY1 well and DY1 well in Xishui‐Daozhen area, and it is extremely low in TY1 well and AY1 well in Tongzi‐Zheng'an area. Shale gas content in the same structural unit is primarily influenced by TOC content, OM pore development degree and water saturation. However, different structural units have different shale gas contents, due to the differences in preservation conditions. Shale reservoirs with good preservation conditions, that is, wide and gentle structure, far from a large fault and great burial depth, generally have high shale gas contents. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

The heterogeneity of pore structure greatly affects gas sorption and flow in shales. The pore structure of shales from the Upper Permian Dalong Formation and Lower Silurian Longmaxi Formation in northeastern Sichuan Basin were investigated using low-pressure N 2 adsorption and field emission scanning electron microscopy (FE-SEM) techniques. The effect of the material compositions on fractal feature, using the Frenkel-Halsey-Hill (FHH) method from low-pressure N 2 adsorption data, was also discussed. The results show that organic pores, intraparticle pores, and microfractures are well developed in Longmaxi shales, but only a certain amount of intraparticle pores within pyrite framboids or calcite grains formed by partial dissolution exist in Dalong shales. The specific surface area and pore volume of Dalong shales vary from 2.20 to 3.52 m 2 /g and 1.11–1.77 cm 3 /100 g, respectively, caused by low maturity, whereas those of Longmaxi shales are in the range of 17.83–29.49 m 2 /g and 2.53–5.18 cm 3 /100 g, respectively, which mainly constitute high-maturity kerogen. The fractal dimensions range from 2.474 to 2.534 for Dalong shales, and from 2.694 to 2.76 for Longmaxi shales. The differences in fractal dimensions of the two sets of shales seem to be related to the maturity of kerogen, which controls the development of organic pores. TOC is also a controlling factor of fractal dimension, exhibited by negative correlation between TOC content and fractal dimension, for both Dalong and Longmaxi shales. The fractal dimension increases with increasing soluble hydrocarbon (S 1 ) for Longmaxi shales, but decreases for Dalong shales, due to S 1 which may fill in the shale pores and affects the uniformity of pore distribution. Weak positive correlations between the fractal dimension and the content of calcite and feldspar suggest that the increase in carbonate and feldspar could slightly increase the heterogeneity of shale pores. There are negative relationships between the fractal dimension and the specific surface area and pore volume for Longmaxi shales, but no relationships for Dalong shales, illustrating that more micropores and mesopores in Longmaxi shales could decrease the heterogeneity of the pore system. [ABSTRACT FROM AUTHOR]

The pore structures and controlling factors of several different Paleozoic shales from Southern China and their kerogens were studied using nitrogen adsorption and scanning electron microscopy methods. The results indicate that: 1) The specific surface area is 2.22-3.52 m/g and has no correlation with the TOC content of the Permian Dalong Formation shales, nanopores are extremely undeveloped in the Dalong Formation kerogens, which have specific surface areas of 20.35-27.49 m/g; 2) the specific surface area of the Silurian Longmaxi Formation shales is in the range of 17.83-29.49 m/g and is positively correlated with TOC content, the kerogens from the Longmaxi Formation have well-developed nanopores, with round or elliptical shapes, and the specific surface areas of these kerogens are as high as 279.84-300.3 m/g; 3) for the Niutitang Formation shales, the specific surface area is 20.12-29.49 m/g and increases significantly with increasing TOC and smectite content. The Niutitang Formation kerogens develop a certain amount of nanopores with a specific surface area of 161.2 m/g. Oil shale was also examined for comparison, and was found to have a specific surface area of 19.99 m/g. Nanopores are rare in the Youganwo Formation kerogen, which has a specific surface area of only 5.54 m/g, suggesting that the specific surface area of oil shale is due mainly to the presence of smectite and other clay minerals. The specific surface area and the number of pores present in shales are closely related to TOC, kerogen type and maturity, smectite content, and other factors. Low-maturity kerogen has very few nanopores and therefore has a very low specific surface area, whereas nanopores are abundant in mature to over-mature kerogen, leading to high specific surface areas. The Longmaxi Formation kerogen has more developed nanopores and a higher specific surface area than the Niutitang Formation kerogen, which may be due to differences in the kerogen type and maceral components. A high content of smectite may also contribute to shale surface area. The pore volume and specific surface area of low-maturity kerogens are mainly attributable to pores with diameters above 10 nm. By contrast, the pore volume of mature kerogens consists predominantly of pores with diameters above 10 nm with some contribution from about 4 nm diameter pores, while the specific surface area is due mainly to pores with diameters of less than 4 nm. Through a comparative study of the specific surface area and pore structure characteristics of different shales and their kerogens, we conclude that the Longmaxi Formation shales and Niutitang Formation shales have greater sorption capacities than the Dalong Formation shales. [ABSTRACT FROM AUTHOR]

The Upper Permian siliceous shale reservoir, which was less studied before, is considered to be a successor target of marine Wufeng-Longmaxi shale gas in Sichuan Basin. To deeply explore pore characteristics, evolution process, formation mechanism and their influences on shale gas capacity, we performed a comprehensive multiscale characterization on siliceous shales with different maturities from Dalong and Wujiaping Formations using low-pressure N 2 adsorption (N 2 GA), mercury injection pressure (MIP), field emission scanning electron microscopy (FE-SEM), and methane sorption capacity. Results indicate that shale pore development, especially OM pore development, and physical property are strictly controlled by thermal maturation levels. OM pores are seldom in low-mature shales but are well-developed in high-to over-mature shales. Pore structures in shales with different maturities are determined by different factors. The high TOC content is conducive to developing OM micropores for high-to over-mature shales. High content of brittle minerals is conducive to developing interparticle (interP) pores and dissolved mesopores at high-mature stage. In terms of the data and published articles, we established a general pore evolution model in siliceous shales to illustrate shale pore development process and formation mechanism. Similar to OM pore development, methane sorption capacity is controlled firstly by thermal maturation and secondly by TOC content. It's pointed out that over-mature shales have smaller-sized OM pores compared with high-mature shales, and therefore they have higher specific surface areas and methane sorption capacities normalized to TOC. This indicates that siliceous shales with extremely high maturity still have good shale gas potential, which further expand shale gas exploration in over-mature shale gas reservoir, as well as provide exploration suggestion for the siliceous shale gas reservoirs in south China. • Pore development discrepancies siliceous shales with different maturities were investigated. • Maturity determines whether OM pore development, and TOC content controls OM pore amount. • Siliceous shales with type II kerogens have slightly lower sorption capacity than typical marine shales. • Siliceous shales with extremely high maturity still have better OM pores and higher methane sorption capacities. [ABSTRACT FROM AUTHOR]

Shale pore type and variation have significant influences on natural gas storage and are of vital importance for shale gas resource evaluation. To better understand the formation and evolution of shale pores during hydrocarbon generation process, organic geochemistry, X-ray diffraction, field emission scanning electron microscopy (FE-SEM), and low-pressure nitrogen gas adsorption (N 2 GA) were applied to samples created by thermal simulation and to naturally evolved samples of the Upper Permian Dalong Formation in the northwestern Sichuan Basin. The results show that the development of organic matter (OM) pores is controlled by kerogen type and thermal maturation level and begins at equivalent vitrinite reflectance (eqvRo) value of 0.91%. Two types of OM pores are developed during OM evolution stage, as bubble pores that are formed at the oil window stage and spongy pores which occcur at the dry gas stage. Maximum pore volume, particularly mesopore volume, occurs within two opportune development periods with the corresponding eqvRo values of 1.11–1.53% and 2.5–2.9%, respectively. The periods are known to be the two peak stages of shale pore development. The first peak corresponds to the late oil generation stage, and the second corresponds to the cracking peak of extractable OM to gas, during which numerous OM micropores and mesopores are generated. OM pore generation is generally resulted from OM decomposition, and pore structure parameters exhibit significant positive correlations with OM reduction for simulated samples. For naturally matured samples, TOC content is positively correlated with pore structures. Extractable OM generated from primary kerogen fills OM pores and mineral-related pores and further reduces shale pore volume. In terms of analysis on naturally matured samples with similar maturities, OM pores in type II 1 kerogen are inferior to those in type I kerogen but more developed than those in type III kerogen. Shale pore evolution is also controlled by diagenesis. Compaction and cementation have adverse effects on shale pore preservation during early and late diagenesis stages, which leads to a significant decrease in shale pore volume, particularly that of mesopores. It should be noted that OM pores are better developed and preserved even when the eqvRo value exceeds 3.25%, which is of vital importance for extending the field of shale gas exploration of over-mature shale reservoirs. • Shale pore development and evolution during hydrocarbon generation process were investigated. • Two types of OM pores, as bubble pores and spongy pores, are developed during maturation. • Extractable OM fills mainly in micropores and mesopores but not macropores. • A generalized model for siliceous shale pore evolution was proposed and interpreted for shale gas exploration. [ABSTRACT FROM AUTHOR]

Thickness marine shale of Paleozoic Wufeng-Longmaxi Formations is deposited in the northwestern Guizhou province, which borders on the shale gas production area in southeast Sichuan Basin. However, few studies have been performed to characterize shale gas reservoir of the Wufeng-Longmaxi Formations in this area. In this study, 80 shale samples collected from the LY1 well were designed to conduct a series of analyses, aiming to obtain microstructure features and reveal their controlling factors. Shales within the Upper Longmaxi Formation characterized by low total organic carbon (TOC) content, high clay mineral content and low porosity are considered to be unfavorable interval for shale gas exploration. Whereas, a high-quantity shale (TOC>2%, clay<40%) interval with thickness of about 27 m exists within Lower Longmaxi Formation and Wufeng Formation. Pores in the studied shales are dominated by organic matter (OM) pores, followed intraparticle (intraP) within carbonates and intercrystalline pores within pyrite framboids. OM pores could be divided into three types, as OM pores within solid bitumen, in-situ amorphous kerogen and graptolite. OM pores are extremely developed in solid bitumen and in-situ amorphous kerogen, and the former have larger diameter than the latter. Rare pores are developed in graptolite. The total porosity and specific surface area of the shales within the Lower Longmaxi Formation and Wufeng Formation are twice more than those within the Upper Longmaxi Formation. Samples with higher TOC values commonly have higher porosities and specific surface areas, suggesting TOC content determines shale physical property. Clay mineral content exhibits a negative influence on microstructure and porosity but determines water saturation. Water saturation has significant negative relationships with micro-to mesopore volumes, porosity and TOC content, illustrating water molecular stores mainly in hydrophilic pores associated with clay minerals rather than OM-hosted nanopores. The gas generation, reservoir quantity and gas content of the Longmaxi-Wufeng shales in northwestern Guizhou are also compared with those of the famous Fuling and Weiyuan districts in eastern Sichuan Basin, and we considered that the shale gas prospect in northwestern Guizhou is excellent. • The microstructure and porosity of the studied shales were investigated by various means. • OM pores, divided into three subtypes: OM pores in solid bitumen, amorphous kerogens and graptolites. • Brittle minerals could enhance shale porosity due to strong compaction resistance. • Clay minerals have a negative influence on porosity but determine water saturation. [ABSTRACT FROM AUTHOR]

Abstract: The methane sorption capacities of Paleozoic shales from the Sichuan Basin were investigated. The primary results show they have sorption capacities ranging between 0.94 and 4.29 cm3/gRock at STP, comparable to the sorption capacity (1.27–2.41 cm3/gRock at STP) of Barnett shale. However, the sorption isotherms indicate that most of the Sichuan Basin shales would reach their approximate sorption equilibrium at 3–4 MPa, in contrast to the continuously upward trend of North American shales. A general positive relationship between TOC content and methane sorption capacity indicates that TOC content is the major controlling factor for the methane sorption of the Sichuan shales. A negative relationship between the clay mineral content and the sorption capacity of these shales may suggest that clay minerals play an insignificant role in the methane sorption of these Paleozoic shales. Sorption capacities and variation ranges are generally ordered as to geological age, viz Cambrian < Silurian < Permian. [Copyright &y& Elsevier]