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Evaluating reservoir storage and percolation capacities, which are closely associated with pore morphology and connectivity, is significant for the exploration and exploitation of oil and gas fields. However, ultradeep carbonate gas reservoirs have extremely high heterogeneity and complexity compared to other relatively shallow reservoirs. Therefore, investigations into all aspects of ultradeep carbonate face enormous challenges. To the best of our knowledge, no systematic study on the pore structure characteristics of ultradeep carbonate gas reservoirs has been conducted to date. In this paper, the pore structure characteristics and their effects on the gas storage and percolation capacities of the Deng IV Member gas reservoir were investigated using conventional petrophysical measurements, casting thin section analysis, scanning electron microscopy (SEM), high pressure mercury intrusion (HPMI) tests, and multiscale CT scanning analysis. The results show that the lithology of the Deng IV Member reservoir is dominated by algal clotted dolomite, algal stromatolite dolomite and algal doloarenite. The conventional petrophysical measurements indicate that the average porosity and permeability are 3.91% and 1.02 mD, respectively. However, the high porosity (8-4%) and high permeability (10–10,000 mD) intervals are developed locally. The casting thin sections, SEM and two-dimensional CT analyses identify six main types of reservoir spaces in the Deng IV Member: interparticle dissolution pores, intercrystal dissolution pores, fenestriform cavities, dissolution cavities, structural fractures and dissolution fractures. Furthermore, three types of throats, that is, necking, tubular and lamellar, were also detected. Four types of reservoirs, namely, matrix type, pore type, cavity type and fracture-cavity type, were classified according to the comprehensive analysis of HPMI data and curves. Three-dimensional pore throat network topologies were reconstructed for four types of representative core samples based on the multiscale CT scanning data and "maximum-ball" method. The distribution characteristics of pore throat radii, volumes and coordination numbers reveal the following: the reservoir space of fracture-cavity type is dominated by cavities and multiscale pore throats with the best pore-throat connectivity; the reservoir space of cavity type is primarily controlled by cavities and large-scale pore throats with moderate connectivity; the reservoir space of pore type comprises multiscale pore throats with moderate connectivity; and most areas of matrix type reservoir are occupied by rock matrix, and the pore-throat connectivity is the worst. In conclusion, the development of fractures and bedding cavities considerably improves the reservoir percolation capacity, and the development of cavities is an important supplement to the reservoir storage capacity. The reasonable combination of cavities and fractures is the basis for the efficient development of ultradeep carbonate gas reservoirs. • A variety of techniques and methods were used to characterize pore structures of a ultradeep carbonate gas reservoir. • Storage and percolation capacities of a ultradeep carbonate gas reservoir were comprehensively analyzed. • Four types of reservoirs were classified and evaluated according to the results of HPMI and multiscale CT scanning. • Reasonable combination of cavities and fractures is the key to the efficient development of ultradeep carbonate reservoirs. [ABSTRACT FROM AUTHOR]

The sealing capacities of shale, roof, and floor strata are essential for the preservation of shale gas. Sealing capacity development and its influence on shale gas composition and organic matter pore development are important but have not been addressed by existing studies. In this paper, the Upper Ordovician Wufeng-the first member of the Lower Silurian Longmaxi Fm. in the Yangtze region is selected as the study object. We dissected the J1 well in the Jiaoshiba block inside the Sichuan Basin and the Y6 well in the Youyang block outside the Sichuan Basin to analyze the gas components and carbon isotopes in recovered shale gas. In this study, two microscope techniques (i.e., FIB-SEM and FIB-HIM), porosity measurement, TOC content analysis, permeability tests, isothermal adsorption measurements, are utilized. The analytical results show that both the roof and floor strata have vertical sealing effects on the organic-rich shale due to their different physical properties compared to the shale. The shale overburden pressure increases with burial depth, and the adsorbed gas increases with increasing TOC content and thickness: all of these can lead to a decrease in permeability and an increase in self-sealing capacity. This paper determined the formation mechanism of the sealing capacity for shale, roof and floor strata. Furthermore, the control patterns of "sealing capacity strength" on the shale gas source and organic matter pore development are clarified. The main findings are as follows: when the shale, roof, and floor strata have a strong sealing capacity, only a small amount of liquid hydrocarbons can be discharged from the shale, but the natural gas formed due to liquid hydrocarbon cracking is abundant. Under such circumstances, shale gas has a mixed origin of liquid hydrocarbon cracked gas and kerogen cracked gas; the carbon isotopes are inverted; abundant pyrobitumen pores with high porosity and good connectivity are developed. When the sealing capacities are weak, the amount of liquid hydrocarbons discharged from the shale are high, and the amount of natural gas is low. The shale gas is mainly derived from kerogen cracking with weak or no carbon isotope inversion, and kerogen pores are small with poor connectivity. These findings will advance the study of shale gas formation mechanisms and provide a scientific basis for selecting shale gas exploration area. • Due to different physical properties, the roof and floor strata provide a seal for the organic-rich shale. • As the burial depth, TOC content, and the shale thickness increase, the shale has a stronger sealing capacity. • Sealing capacity plays an important role in the characteristics of shale gas and organic matter pore development. [ABSTRACT FROM AUTHOR]

Abstract Multiphase (adsorbed and free) liquid water that is accumulated in shale matrix pores (i.e., pore water) substantially affects the storage and transport of gas in shale. Traditionally used macroscopic parameters (e.g., initial, irreducible, mobile and clay bound water saturations) are not sufficient to describe the microdistribution characteristics and mobility of pore water in the complex porous shale matrix. In this paper, a new classification was proposed in which the pore water is composed of adsorbed and free parts, of which the latter is subdivided into capillary bound and mobile water. The components of pore water have the following features: during the centrifugation process, (a) adsorbed water is essentially immobile, while free water is potentially mobile; (b) capillary bound water is gradually transformed into mobile water with increased centrifugal pressure difference; and (c) the maximum mobile water amount is numerically equal to the free water amount. Based on the classification, an effective technique, which integrates centrifugation, water imbibition and low temperature nitrogen adsorption methods with the modified Li's adsorption ratio equation (2018), was established to quantitatively evaluate the microdistribution characteristics (adsorbed and free amounts and their ratios) and the mobility (mobile amount, potential and capacity) of pore water in marine shales from the southern Sichuan basin in China. Furthermore, the mechanism of controlling the microdistribution and mobility of pore water is analyzed with respect to the microscopic pore structure characteristics and material compositions of shales. The primary results demonstrate that (1) adsorbed and free water amounts obtained by centrifugation tests range from 5.145 to 31.282 mg/g (adsorbed) and from 7.880 to 49.751 mg/g (free); the weight ratio of adsorbed water is 0.268–0.629. (2) The mobile potential and mobile capacity of pore water are represented by the free water amount and mid-value pressure difference, respectively. A positive relationship between these two parameters occurs in the studied shales. (3) Pore microstructure characteristics of shale mainly impact the microdistribution and mobility of pore water in the shale matrix. The adsorbed water amount is closely associated with the specific surface area of pores, while the free and mobile water amounts are controlled by the pore volume. The ratios of adsorbed and free water depend on the size and morphology of pores for certain state parameters. The mobile ratio is impacted by pore complexity, which indicates that as the complexity increases, the mobile ratio decreases. The study provides significant insight into the microdistribution and mobility of pore water in gas shale matrix. Highlights • A new classification was proposed for the components of pore water. • A technique was established to evaluate the microdistribution characteristics and the mobility of pore water in shales. • Mechanism of controlling the microdistribution and mobility of pore water was analyzed. [ABSTRACT FROM AUTHOR]

In shale plays, the in-situ effective stress is continuously being perturbed because of the production which impacts field operations. Therefore, mechanical properties of the formation and its response to stress field changes, with respect to mineral variations, is of great significance for the proper design of horizontal drilling and hydraulic fracturing. In this paper, clay-rich, calcareous and siliceous black shales are classified based on their XRD analysis, from the Wufeng and Longmaxi Formations in the Sichuan Basin of the Upper Yangtze Plate. Uniaxial quasi-static and cyclic loading tests, acoustic emissions, and CT scanning are combined to study mechanical behavior and fracturing mechanisms of the shale layer samples that own different mineral components. The results show that the strength and deformation response of the samples is a function of their mineral composition. The damage from cyclic loading is gradually accumulated in the samples which ultimately leads to fatigue and sample failure. The compressive strength of the samples under cyclic loading is lower than in the uniaxial quasi-static conditions. Furthermore, the fracturing of rock under uniaxial quasi-static loading mainly occurs after the peak strength is achieved while in cyclic loading, when a certain stress level is reached, fracturing begins, the damage accumulates up to the peak stress and the rock suddenly fails. Based on CT images from the samples after rupture, failure modes of the clay-rich, calcareous and siliceous black shales mainly constitute extensional and shear fractures, with some conjugate shearing. In comparison with uniaxial quasi-static loading, the fracture volume of the clay-rich, calcareous and siliceous black shales after cyclic loading increases by 12.2%, 25.9% and 32.9%, respectively. Overall, this study explains how cyclic loading that can be applied in the field via changing the injection pressure and other stimulation parameters, can effectively improve the complexity of the shale fracture network and lead to higher productivity of the formation. • Quasi static loading and cyclic loading are employed in the mechanical test. • The compressive strength of the cyclic loading is lower than that of uniaxial quasi-static loading. • The fracture volume of the cyclic loading is higher than that of uniaxial quasi-static loading. [ABSTRACT FROM AUTHOR]

Pores and throats are the key parameters for determining the pore structure and fluid flow behavior in tight sandstone reservoirs. In this paper, pores and throats of the tight sandstone reservoir of the Upper Triassic Xujiahe Formation in the northern Sichuan Basin were investigated using classical petrography, scanning electron microscopy, and confocal laser scanning microscopy. In addition, a method of pore as well as throat identification and quantitatification using high-pressure mercury injection (HPMI) measurements was worked out. The results show that clay mineral-related pores are well developed in lithic sandstone and feldspathic lithic sandstone in addition to pores produced by dissolution of calcite cement and clastic grains. Intergranular pores are connected by lamellar, curved lamellar, and narrow pore throats. The pores and throats associated with intragranular dissolution and clay minerals are mostly tube shaped. The rapid-increasing and slow-increasing profiles of the mercury injection curves represent the dominance of pores and throats, respectively, allowing to differentiate pores and throats. Calculations show, in addition to fractured lithic sandstone, that has micron-sized pore–throat systems, the other lithic sandstones possess dominatly nano-sized pore–throat systems. In case of feldspathic lithic sandstones, micron-sized and nano-sized pore throat systems are equally important. In micron-sized pore throat dominated reservoirs, the pore volume is slightly larger than the throat volume, whereas for the nano-sized pore throat system, the pore volume is considerably larger than the throat volume. The key factors that are favorable for the formation of lithic sandstone pore throat systems are early calcite dissolution, lithic fragments dissolution, and early chlorite cementation. In contrast the key factors that are favorable for the formation of feldspathic lithic sandstone pore throat systems are dissolution of feldspars and lithic fragments. • A new method to distinguish pores and throats within tight sandstone reservoirs is proposed. • Lithic and feldspathic lithic sandstone reservoirs host different pore and throat types. • Pore volume is slightly larger than throat volume in the micron-size pore network. • Pore volume is considerably larger than throat volume in the nano-size pore network. • Compaction, cementation, and dissolution directly affected the development of pore throat systems. [ABSTRACT FROM AUTHOR]

The Emeishan mantle plume is supposed to play an important role in the Permian thermal regime and source rock hydrocarbon generation evolution in the Sichuan Basin, Southwest China. In this paper, we provide new valuable insights into the spatial thermal effect of the Emeishan mantle plume to the Sichuan basin and maturity evolution of the Paleozoic source rocks. Cambrian core samples from four wells were selected for zircon fission track and zircon (U–Th)/He analysis in order to determine their thermal histories. Then the thermal histories of typical wells throughout the basin were obtained based on the above result and previous studies. According to the peak heat flow value (q), four Permian geothermal units were classified: a stratospheric heat flow unit (q ≥ 90 mW/m2), a high heat flow unit (80 ≤ q < 90 mW/m2), a medium heat flow unit (70 ≤ q < 80 mW/m2), and a normal heat flow unit (q < 70 mW/m2). The interpretation of the abnormal Permian heat flow indicates that the enormous heat flow anomalies with values of >20 mW/m2 occurred in the stratospheric and high heat flow units was mainly caused by the mantle plume, while the weak Permian thermal perturbation with heat flow anomalies of <15 mW/m2 in other two units was more likely associated with crustal thinning. The thermal effect of the Emeishan mantle plume may be contained within the stratospheric and high heat flow units. By comparing the maturation histories of the Paleozoic source rock, we identified the thermal effect on the maturity evolution. The thermal perturbation had no obvious impact on the maturity evolution of the Lower Permian and Lower Silurian Longmaxi Formation. Only the Lower Cambrian Qiongzhusi Formation within high geothermal unit suffered significant thermal effect of the mantle plume and matured rapidly during the end of the Early Permian. • Four Permian geothermal units in the Sichuan basin were first classified. • New insight for the spatial thermal effect of Emeishan mantle plume. • Formation mechanism of Permian heat flow anomalies was identified. • The effect of mantle plume on the maturity evolution of source rocks was characterized. [ABSTRACT FROM AUTHOR]

Details of the Lower Cambrian succession of the newly-discovered intraplatfrom basin of the Yangtze Platform (South China), source rocks of the giant Ediacaran-Cambrian gasfields of the Sichuan Basin, including its stratigraphic framework, redox and organic matter accumulation histories, remain unresolved. This paper describes results of a petrological and geochemical investigation of Lower Cambrian strata near the center of the Sichuan Basin with the goal of elucidating those processes that controlled the sedimentary history of the succession. We recognize two intervals of organic-rich source rocks deposited in the intraplatfrom basin, including the Maidiping Formation and overlying Qiongzhusi Formation. The Maidiping accumulated in a carbonate platform setting during Fortunian-Early Stage 2 time (~541–526.5 Ma) and comprises a variety of rock types, including carbonate, chert, phosphorite, shale, and Mn-ore layers. Total organic carbon (TOC) value ranges from 0.47 to 5.06 wt.%; the highest quality source rocks are found in its lower member. The Qiongzhusi Formation was deposited as part of a clastic shelf during Middle Stage 2-Middle Stage 3 (~526.5–515 Ma) time. This unit is dominated by shale and argillaceous siltstone and displays TOC values varying from 0.30 to 4.28 wt.%. The most organic-rich deposits are found in its lower and upper members. Redox and hydrographic proxies suggest that the intraplatfrom basin was dominated by a strongly restricted environment and anoxic bottom water conditions that experienced intermittent episodes of euxinic or dysoxic-oxic conditions during the Fortunian-Middle Stage 3 time. However, bottom water conditions appear to have been oxic during Late Stage 2 time. Accumulation of Lower Cambrian source rocks across the Yangtze Platform appears to have been closely linked to depositional setting. Our findings suggest that organic matter accumulation in the intraplatfrom basin was fundamentally redox-controlled whereas productivity exerted the greatest control on deposition of organic matter near the slope-deep basin of the Yangtze Platform. In summary, Early Cambrian high-quality source rocks preferentially accumulated in topographic lows, including the intraplatfrom basin and slope-deep basin, an association useful to targeting conventional and unconventional hydrocarbons in the Sichuan Basin. • Stratigraphic framework of the Lower Cambrian deposits in an intraplatfrom basin on the Yangtze Platform were established. • The intraplatfrom basin was dominated by anoxic bottom water with intermittent episodes of euxinic/dysoxic-oxic conditions. • A model depicting controls on OM accumulation across the Yangtze Block during the Early Cambrian was proposed. [ABSTRACT FROM AUTHOR]

The Lower Cambrian Qiongzhusi Formation source rock is one of the main sources of oil and gas in the Sichuan Basin. Owing to the controversial thermal history and the complex structural pattern in the Sichuan Basin, it is difficult to characterize the differences in maturity evolution and the timing of hydrocarbon generation periods of Qiongzhusi hydrocarbon source rocks in different tectonic zones. Based on the comprehensive analysis of the previous thermal history and denudation studies from the tectonic units of the basin, the thermal histories and denudation amount in main period of tectonic movement of a five-part tectonic development are obtained in this paper. Although the thermal history of different tectonic units varies, generally, the heat flow increased slowly in the early Paleozoic, and it experienced a peak heat flow at the end of the Middle Permian and decreased subsequently. Based on new thermal history and denudation data, the maturation of the Lower Cambrian Qiongzhusi Formation source rocks in the Sichuan Basin were modeled and their evolution can be classified into three patterns, which are: (1) continuous heating pattern in southern Sichuan, (2) Silurian-Permian heating cessation pattern in western Sichuan and northwest central Sichuan, and (3) Silurian-Permian and Triassic heating cessation pattern in the central uplift, northern structural zone and western part of the eastern structural zone. In addition, the key hydrocarbon generation periods of different tectonic units were determined in this study. Tectonic and sedimentary burial, together with high heat flow values during the Late Permian, were the main factors controlling levels of thermal maturity and thermal evolution models of the Qiongzhusi Formation. The present-day thermal maturity of the Qiongzhusi Formation depends on the thermal history and maximum burial depth before uplift in Late Cretaceous. However, the maturity evolution pattern affecting the key hydrocarbon generation stage was mainly related to the burial histories of source rocks in the Paleozoic. The thermal modelling of this study provides new evidence for the source rock evolution and new insight into Lower Paleozoic shale gas. • Thermal history, denudation amount and process of different tectonic units are summarized. • Maturity evolution and key HC generation periods of the Qiongzhusi Formation are obtained. • Three thermal evolution patterns of source rocks are classified. [ABSTRACT FROM AUTHOR]

Based on low-temperature thermochronological data (i.e., apatite fission-track (AFT) and (U–Th)/He (AHe)), structural evolution, burial and thermal history, this paper examines the relationship of multi-stage evolution between the upper Ordovician Wufeng and lower Silurian Longmaxi formations (i.e., the WL formation) and rapid exhumation at the Changning shale gas field in the southern Sichuan basin. AFT ages are generally young from southeast to northwest, decreasing from ca. 40 to 15 Ma while AHe single-grain ages range from ~35 to ~5 Ma. Inverse thermal histories show that a multi-stage cooling history with initial cooling began in the Late Cretaceous to early Cenozoic (middle Eocene), followed by accelerated rapid cooling in the late Cenozoic, with cooling rates of 2–4 °C/Myr across the Changning shale gas field. In particular, thermal models of samples in the western Changning area show a substantial increase in the cooling rates, i.e., from less than 1 °C/Myr to 3–5 °C/Myr in the Miocene. Integrated with inverse T-t models of low-temperature thermochronological data, the burial history indicates a four-stage thermal evolution of the WL Formation in the Changning shale-gas field: Early Mature from the middle Silurian to middle Permian, Middle Mature from the late Permian to Late Triassic, Late Mature from the Early Jurassic to Early Cretaceous, and Over mature since the middle Cretaceous, reaching a maximum burial depth of ~6000 m and maximum temperature of 190–200 °C at ca. 70–80 Ma. This evolution further suggests that a normal hydrostatic pressure index dominated the WL Formations in the Paleozoic. The gas generation and pressure index, however, have substantially increased since the Late Jurassic, particularly from the Early to middle Cretaceous, with a maximum pressure index of 2.1, which is indicative of the main shale gas accumulation and enrichment period in the WL Formation. Post-gas-generation structural deformation, uplift, and exhumation had a significant impact on shale gas enrichment, mainly through their influence on shale gas preservation. This suggests some relationships among the higher pressure coefficient of the WL Formation, the higher productivity and total gas content of the WL Formation, a weaker post-gas-generation structural deformation, and a weaker uplift, as indicated by the erosion and burial depth across the Changning shale gas field. Due to a significantly stronger cooling and uplift that occurred the in Late Cenozoic across the western Changning area, the pressure index decreased rapidly from ~2.0 to 1.0 with a normal pressure condition, indicating the destruction of the reservation condition in the WL Formation. • New low-temperature thermochronological data was from the SE Sichuan basin. • An accelerated cooling in the late Cenozoic was found. • Post-gas-generation deformation and exhumation controlled the shale gas enrichment. [ABSTRACT FROM AUTHOR]

The Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation marine shale are the major shale gas exploration and development target in the Middle-Upper Yangtze region. Although three national shale gas demonstration areas have been built and several high-yield shale gas wells have been discovered in the Wufeng Formation and Longmaxi Formation, shale gas in these areas has not been fully commercialized because the enrichment degree of shale gas varies greatly in different tectonic settings. By analyzing the formation processes and distribution characteristics of the organic-rich shale, reconstructing the burial history and hydrocarbon generation history, and comparing the shale gas enrichment and preservation conditions in different tectonic settings in South China, this paper points out that (1) The craton depression and foreland basin on the cratonic margin are favorable zones for the development of organic-rich shale. Because the Yangtze plate is small, the foreland basin is greatly affected by the input of terrigenous clastic and the thickness and area of organic-rich shale in the craton basin is larger than that in the foreland basin. The organic-rich shale is mainly distributed in south Sichuan deep-water shelf and west Hubei-east Chongqing deep-water shelf, and the enrichment interval is the Dillcellograptus complexus-Cystograptus Vesicolus graptolite zone from the Wufeng Formation to the bottom of Longmaxi Formation are favorable intervals for shale gas enrichment. (2) Since the Late Jurassic, significant differential intracontinental tectonic deformation, uplift and denudation occurred in the Middle-Upper Yangtze region. Moderate compression and uplift were beneficial to the development of micro-fractures and bedding fractures in shale, resulting in good preservation conditions of shale gas reservoirs with a high-pressure coefficient. In contrast, strongly deformed areas, where faults and high-angle large fractures were developed, are not conducive to the preservation of shale gas reservoirs. (3) The craton depression of the Middle-Upper Yangtze region, where organic-rich shale was deposited, is favorable to shale gas enrichment because it provides a good material basis, and also a relatively stable and compression-resistant tectonic environment for later tectonic deformation and uplift-derived destruction. Based on the analysis and evaluation of tectonic construction–transformation conditions under the macro-control of plate tectonics, it can well explain the existing commercial shale gas discoveries and failure cases and can guide the optimization of future exploration targets. • ►Deep water in the craton depression controlled the distribution of organic-rich shale. • Stable tectonic settings are favorable for shale gas enrichments. • Two depressions in Yangtze Craton are the most favorable areas for shale gas accumulation. [ABSTRACT FROM AUTHOR]

Numerous studies have been conducted on the isotopic geochemical characteristics of shale gas. However, a systematic study of the relationship between the isotopic geochemical characteristics and gas content has not been addressed to date. In this study, we investigated the geochemical and isotopic compositions of shale gas samples, and the gas content of the Lower Silurian Longmaxi marine shale in the Huangjinba area, southern Sichuan Basin, China. In addition, we analyzed the quantitative relationship between the geochemical parameters and the gas content. The Longmaxi shale gas is a dry gas with a low wetness (0.12%–0.67%), dominated by methane (89.49%–99.00%) with a small amount of ethane (0.11%–0.61%). The average values of δ13C methane , δ13C ethane and δ13C propane are −29.8‰, −35.0‰, and −33.2‰, characterized by a partial isotopic reversal (δ13C methane > δ13C propane > δ13C ethane) with a maturity level (Ro ≈ 2.30%–2.51%). The total gas content of the Longmaxi shale varies widely from 0.42 m3/t to 3.88 m3/t. Correlation analyses revealed that the ethane isotope (δ13C ethane) and the magnitude of isotopic reversal (δ13C methane - δ13C ethane) exhibit strong correlations with the total gas content and the free gas content. This study demonstrates that carbon isotopic reversal of shale gas largely depends on the secondary cracking, and thermal maturity and residual liquid hydrocarbons content are important factors affecting the magnitude of carbon isotopic reversal. Based on the quantitative study conducted in this paper, we provide a new proxy for predicting the gas content of high maturity shale using an isotopic method. • Carbon isotopic reversal of shale gas largely depends on the secondary cracking. • Sufficient residual liquid hydrocarbon is necessary for the carbon isotopic reversal. • Wetness of 1.4% in high maturity shale gas indicates the peak of secondary cracking. • δ13C methane –δ13C ethane can be used to predict the gas content of high maturity shale. [ABSTRACT FROM AUTHOR]