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Shale in the Jurassic Lianggaoshan Formation in central Sichuan exhibits strong heterogeneity. The study of the pore structure characteristics of different lithologies is crucial to the selection of the target interval. Shale samples of the Lianggaoshan Formation from well YS5 in the central part of the Sichuan Basin were analyzed using scanning electron microscopy, low-temperature nitrogen adsorption, high-pressure mercury injection (HPMI), and large -field splicing method -based scanning electron microscopy (LFS-SEM) to elucidate the pore structure characteristics of shale and their influencing factors. The mineral composition of the reservoir in the study area was diverse, primarily consisting of clay minerals, followed by quartz and calcite. The reservoir space comprised intergranular, granular, and organic matter pores, and oil was observed to fill the reservoir space. Reservoir characteristics varied with the lithological properties. In clayey shale, intergranular pores located in clay mineral particles and pores between pyrite and natural fractures were mainly observed, with a bimodal distribution of pore size and peak distribution of 10–50 nm and >100 nm. The storage space of ash-bearing shale mainly consisted of intragranular pores and intergranular (crystalline) micropores, with pore sizes primarily concentrated in the 10–50 nm range. The storage space in silty shale mainly developed in clastic mineral particles such as quartz, followed by clay mineral intergranular pores with a relatively wide distribution of sizes. Pores were mainly inkbottle-shaped and slit-type/plate-type pores, with an average specific surface area of approximately 6.9046 m2·g−1 and an average pore volume of approximately 0.0150 cm3·g−1. The full-pore capillary pressure curve was established using a combination of gas adsorption–desorption tests and HPMI. The fractal dimension of the sample pore structure was calculated, and a significant linear correlation was found between clay mineral content and the fractal dimension. Thus, the pore structure characteristics were mainly controlled by the content and distribution of clay minerals. [ABSTRACT FROM AUTHOR]

The assessment of gas storage capacity is crucial to furthering shale gas exploration and development in the eastern Sichuan Basin, China. Eleven organic-rich shale samples were selected to carry out the high pressure methane sorption, low-pressure N2/CO2 gas adsorption, and bulk and skeletal density measurements to investigate the methane storage capacity (MSC). Based on the relative content of clay, carbonates, quartz + feldspar, we grouped the 11 samples into three lithofacies: silica-rich argillaceous shale (CM-1), argillaceous/siliceous mixed shale (M-2), and clay-rich siliceous shale (S-3). The total porosity of the shale samples varies from 3.4% to 5.6%, and gas saturation ranges from 47% to 89%. The measured total gas amount ranges from 1.84 mg/g to 4.22 mg/g with the ratio of free gas to total gas amount ranging from 52.7% to 70.8%. Free gas with high content in the eastern Sichuan Basin may be the key factor controlling amount of shale gas production. The TOC content critically controls the MSC of shales, because micropore, mesopore volumes and the specific surface areas associated with organic matter provide the storage sites for the free and adsorbed gas. The methane sorption capacities of samples from different lithofacies are also affected by clay minerals and moisture content. Clay minerals can provide additional surface areas for methane sorption, and water can cause a 7.1%–42.8% loss of methane sorption capacity. The total porosity, gas-bearing porosity, water saturation, free gas and adsorbed gas number of samples from different lithofacies show subtle differences if the shale samples had similar TOC contents. Our results suggest that, in the eastern Sichuan Basin, clay-rich shale lithofacies is also prospecting targets for shale gas production. [ABSTRACT FROM AUTHOR]

Time-dependent behaviors of rocks can be attributed to long-term applied stress, which occurs in most underground engineering projects. The creep behavior of granite from the Shuangjiangkou underground powerhouse in western Sichuan Province, China, was investigated via creep tests. It is shown that granite has an obvious creep behavior under different confining pressures and deviatoric stresses. The new dimensionless parameter DPR, which is defined as the ratio of the deviatoric stress to the peak strength, is proposed for experimental analysis. The relationships between the instantaneous strain and final visco-elastic creep strain of granite with DPR are established under different confining pressures. It is shown that when DPR is equal to 0.63, the final visco-elastic creep strain of rocks will reach a minimum value. Based on DPR and the secondary creep strain rate, a unified method for defining the long-term strength of rocks is proposed, and the granite will enter in secondary creep with a nonzero strain rate when DPR > 0.9501. The Nishihara model is improved, and the relationships between the parameters of the improved model with confining pressures and DPR are obtained. The improved creep model can satisfactorily represent the primary creep strain of granite and secondary creep strain of granite with time under a given confining pressure and deviatoric stress. [ABSTRACT FROM AUTHOR]

Nanoscale organic matter‐hosted pores (OM pores) are the dominant pore type in the marine, organic‐rich shales of the Upper Ordovician Wufeng Formation and the Lower Silurian Longmaxi Formation's first member in the Jiaoshiba Block, which provide important reservoir space for shale gas accumulation. In this study, field emission scanning electron microscopy (FE‐SEM), statistical analysis using ImageJ software, and gas adsorption tests were conducted to investigate the characteristics of OM pores, including pore shape, pore size distribution, pore quantity, and organic porosity. FE‐SEM images show that the OM pore sizes range between 2 and 900 nm. The predominant shape of the OM pores in the Wufeng shale is an irregular polygon, while elliptical and subrounded OM pores were observed in the Longmaxi Formation's first member shale. Average cross‐section area ratios of the OM pores to corresponding single‐particle organic matter (ØOMP/OM) for shale samples obtained via statistical analysis of FE‐SEM images range between 10% and 30%. We propose a new combination approach for the estimation of organic porosity, which gives organic porosities for the Wufeng shale and Longmaxi Formation's first member shale of 0.56%‐4.47% and 4.06%‐4.21%, respectively. To calculate the organic porosity for the OM pores with diameters of 10‐900 nm, the formula derived from the mass‐volume‐density‐organic matter relationships and ØOMP/OM of shale was used, while the organic porosity for pores with diameters of 0.3‐10 nm was estimated using carbon dioxide and nitrogen adsorption data. In addition, the reasons for the differences in the OM pore structures in the Wufeng shale and Longmaxi Formation's first member shale were examined for the study area and found to be the result of variations in total organic carbon (TOC) content and tectonic compression of the Wufeng shale. [ABSTRACT FROM AUTHOR]

• Three main kinds of shales lithofacies are identified. • Clay-rich siliceous shales have the highest TOC content and the largest porosity. • OM related pores contribute 62.6% to the porosity of clay-rich siliceous shales. • Clay-rich siliceous shales are preferable for shale gas exploitation. Shales from Ordovician Wufeng and Silurian Longmaxi groups in the Sichuan Basin were analyzed by using the field emission-scanning electron microscopy, helium pycnometry, and low-pressure gas adsorption experiments. There are mainly three lithofacies in the studied shale reservoirs: clay-rich siliceous shale (S-3), argillaceous/siliceous mixed shale (M-2), and silica-rich argillaceous shale lithofacies (CM-1). The organic-rich S-3 shales have the highest porosity (averaging 5.4%), the largest pore volume (averaging 0.024 mL/g), and the highest specific surface area (averaging 21.6 m2/g). Organic matter (OM) pores contribute 62.6% to the porosity of S-3 shales. M-2 shales have the moderate pore structure with porosity averaging 4.3%, pore volume averaging 0.019 mL/g, and specific surface area averaging 16.7 m2/g. Organic matter and clay minerals contribute 49.5% and 36.8% to the porosity of M-2 shales, respectively. The CM-1 shales have the lowest porosity (averaging 4.1%), the smallest pore volume (averaging 0.017 mL/g), and the lowest specific surface area (averaging 15.6 m2/g). The organic-lean CM-1 shales are dominated by clay mineral pores. Clay minerals contribute 56% to the porosity of CM-1 shales. OM pores are well developed in the S-3 shale lithofacies, while most of OM pores are destroyed or compacted in CM-1 shale lithofacies. The effect of compaction on porosity of CM-1 shales is stronger than that of M-2 and S-3 shales because of the highest clay minerals content and the lowest siliceous minerals content. Considering the pore spaces and hydraulic fracturing operation, the S-3 shales is more suitable to shale gas exploration than M-2 and CM-1 shales. Certainly, the M-2 and CM-1 shales also have certain amounts of hydrocarbon storage capacity, and could be considered as the candidate targets for shale gas exploitation. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Ten Longmaxi shale samples were collected from the Jiaoshiba area, China, where 5 billion cm3/year of shale gas is produced. The samples were evaluated to characterize the pores of various shale lithofacies. Three shale lithofacies were determined in the Jiaoshiba area, Sichuan Basin, China, based on the shale mineral components, namely, siliceous lithofacies (SL), argillaceous lithofacies (AL), and mixed lithofacies (ML). Field emission scanning electron microscopy (FE-SEM), which was performed under high and low voltages, GRI porosity, and carbon dioxide and nitrogen adsorptions were used to investigate the bulk-shale porosity, pore type, pore size, pore morphology, and pore volume among the lithofacies. Lithofacies affects the shale total organic carbon (TOC), bulk-shale porosity, pore size, shape, and volume. SL and ML contain high porosity, high TOC, abundant organic-matter (OM)-hosted pores, and high OM porosity, whereas AL contains few OM pores and has low TOC and low porosity. In the same lithofacies, samples with various TOC values exhibit different pore morphologies. For SL, the low-TOC sample has a round and elliptical OM pore forms, whereas the high-TOC samples show linear and narrow pore shapes that are probably associated with gas expulsion. In ML, the higher TOC is related to spherical or near-spherical OM pores, whereas the OM pore shape collapses in the low-TOC shale. Therefore, lithofacies affect the shale reservoir, and the characteristic and evolution of OM pores should be considered as constraints in shale lithofacies. In SL, sections with a higher TOC value are prime targets despite the high expulsion efficiency, which does not affect the enrichment and high yield of the shale gas. Sections of ML and low-TOC SL should be considered as potential targets because of higher OM porosity and low expulsion efficiency, whereas sections of AL engender risk in exploration and development of shale gas. • Lithofacies controlling porosity, mineral and OM pore diameters, OM porosity were researched. • OM pore types in different lithofacies were determined. • Pore preservation of rigid minerals calcite, dolomite, quartz were investigated. • Expulsion efficiency implication for shale gas enrichment was clarified. • An available method was introduced to determine the high production sections. [ABSTRACT FROM AUTHOR]

Widely developed in shale strata, laminae are the most typical shale sedimentary structure. To investigate their influence on shale gas reservoir quality, we conducted complementary studies by integrating microscopic observations, geochemical analyses, field-emission scanning electron microscopy (FE-SEM) imaging, and mercury intrusion capillary pressure (MICP) techniques. The microscopic observation of thin sections enabled us to detect the laminae characteristics, including the density and maximum thickness of individual lamina, and three types and stages of lamina development were identified. The total organic carbon (TOC) content, mineral composition, natural fracture, pore type, pore size distribution, porosity, permeability, and tortuosity were investigated in these different laminae types using FE-SEM, MICP and geochemical analysis. Combining the laminae characteristics and pore structure, we concluded that the organic pores and total pore area are mainly affected by the TOC content, whereas the development of the laminae controls the inorganic macropore scale and affects the pore size distribution. In addition, we found that the excessive development of shale laminae is not conducive to organic matter accumulation because of the change in redox condition, and because it has an adverse impact on the formation of complex artificial fractures during hydraulic fracturing. • Three laminae types were identified based on quantitative analysis. • Different laminae types show different pore structure characteristics. • Shale laminae influence the formation of natural fractures and artificial fractures. [ABSTRACT FROM AUTHOR]

The petrophysical characteristics of unconventional reservoirs have significant impacts on hydrocarbon storage and transport. In this study, 26 shale samples with various lithofacies from Lower Silurian Longmaxi shales in the Jiaoshiba area of Sichuan Basin are investigated. The pore network (morphology, porosity, and pore structure parameters) is comprehensively characterized using scanning electron microscopy, helium pycnometry, and low-pressure gas adsorption techniques. Permeability coefficients are derived from pulse-decay measurements on parallel to bedding samples. Geological controls on the pore shape, porosity, pore size, pore size distribution, and permeability of the shales are analyzed, and quantitative relationships with which to estimate the permeabilities and pore-throat apertures controlling gas flow are developed. Three general lithofacies are summarized in view of their mineralogy: siliceous, argillaceous/siliceous mixed, and argillaceous shales. Pore structure parameters (porosity, specific surface area, and pore volume) show positive correlations with total organic carbon (TOC) content. Organic matter-hosted pores contribute to approximate 67% of the porosity of siliceous shales, while inorganic matter contributes to 55% of the porosity of argillaceous shales. Klinkenberg-corrected permeabilities range between 0.01 and 46.4 μD, and are controlled by the alignment of clay flakes. Negative relationships exist between TOC content, porosity, and permeability values. Siliceous shales generally have the lowest permeabilities, whereas the argillaceous shales with developed oriented clay flakes have relatively high permeabilities. The seepage-pore apertures, estimated using the Winland correlation, range from 9 to 476 nm. These values are much higher than those obtained from nitrogen adsorption analysis (adsorption-pore apertures). A power correlation exists between seepage-pore apertures and total clay minerals content of shales studied. A fracture model (sheet) is used to predict absolute permeability based on seepage-pore apertures. The predictions are reasonable, and justify the application of the sheet model and seepage-pore apertures. The siliceous shales are featured by a high TOC content, large porosity and specific surface area, and low permeability, which are favorable to gas preservation. • Petrophysical characteristics of Longmaxi shales are documented. • Geological controls on pore structure and permeability of shales are investigated. • Seepage-pore aperture controlling gas flow is calculated. • A new method for estimating permeability using seepage-pore aperture is proposed. [ABSTRACT FROM AUTHOR]

The in-situ stress state of the eastern margin of the Sichuan Basin, where there is a complicated fault zone, is poorly understood. This study offers vital insights into the in-situ stress state based on information from 17 wellbores in the Wufeng-Longmaxi Shale near the eastern boundary fault (i.e., the Qiyueshan Fault) of the Sichuan Basin, China. Drilling-induced tensile fractures and borehole breakouts revealed a decrease in the angle between the S Hmax (maximum horizontal stress) orientation and fault strike when the wellbores are close to the damage zone of the Qiyueshan Fault. This stress rotation may be caused by the lateral contrast in the Poisson's ratio between the country rock and damage zone of the Qiyueshan Fault. A high angle between the S Hmax orientation and fault strike also appeared in the individual fault blocks of the Qiyueshan Fault as a result of local stress concentration. The higher magnitudes of horizontal stresses indicate stronger lateral compression in the Qiyueshan Fault Zone. Owing to the lateral compression of a "sandwich" consisting of a high-E (Young's modulus) roof and low-E shale intervals, natural fractures mainly appeared in the low-E shale intervals when the wellbore was close to the fault damage zone. The low fracture intensity in the low-E shale intervals of the wellbores located at the boundaries of the stress concentration blocks may be associated with an extensional stepover process. • Spatial variations in stress orientation and magnitude around the fault zone. • Lateral mechanical contrast decreases the angle between S Hmax and fault strike. • Stress concentration complicates S Hmax orientations in certain fault blocks. • Vertical mechanical contrast affects the natural fracture intensity of shale. [ABSTRACT FROM AUTHOR]

The lamellation fractures in marine shales are important to the accumulation and preservation of shale gas, whose characteristics and controlling factors are still unclear. This paper focus on the characteristics descriptions and controlling factor analyses based on core observations, thin sections, and scanning electron microscope (SEM) experiments. The marine shales of Paleozoic Wufeng Formation and Longmaxi Formation in the Fuling Area of Eastern Sichuan Basin are taken as an instance. The lamellation fractures are occurring along the direction of the lamellations, partially of them curved, bifurcated, and converged. The apertures of fractures typically range from 1 to 500 μm. Only a few (<1%) lamellation fractures are filled with quartz, calcite, pyrite, and bitumen. After a series of analyses, developments of lamellation fractures are controlled by total organic carbon (TOC), brittle minerals, laminae, and pyrite. (1) The organic matters control the formation and evolution of lamellation fractures by generating gas and resulting in overpressure. An increase in the TOC content of 1% can increase the lamellation fracture density by 0.26 cm-1. (2) Brittle minerals, especially authigenic quartz, is also an important controlling factor to the development of lamellation fractures. When BI increases by 10%, the lamellation fracture density increases by 19%. (3) Besides, siliceous and carbonate laminae in the shale are more suitable for lamellation fractures to develop. When the laminae density is smaller than 4 cm−1, it is easier to develop lamellation fractures with higher laminae density. However, too densely-distributed laminae will suppress the formation of lamellation fractures. (4) Higher pyrite content is good for the development of lamellation fractures. Lamellation fracture density will increase by 9%, with pyrite content increased by 1%. For the shale at the bottom of the Wufeng Formation - Longmaxi Formation, lamellation fractures develop extensively due to the high TOC and pyrite content, great brittleness, and moderate laminae density. The density of lamellation fractures decreases from the bottom to the top. • Quantitative characterize about development characteristics of the lamellation fractures. • The lamellation fractures is controlled by brittle mineral, TOC, laminae and pyrite. • TOC is the main one that affects the development of lamellation fractures. • Clarify vertical distribution characteristic of lamellation fractures in the Wufeng-longmaxi Fm. [ABSTRACT FROM AUTHOR]

Tectonism significantly affects the pore characteristics of organic-rich shales. Here, two sets of shales with similar mineral compositions and total organic carbon (TOC) content were used to evaluate the response of pore structure to tectonic deformation through gas adsorption, FE-SEM, and Nano-CT. The stable region shales have superior porosity, pore volume, pore diameter, surface porosity of organic matter (OM), and pore connectivity. However, the deformed region shales show obviously low storage space, pore size, and connectivity. The OM pores of the stable region shales were well preserved due to the support of residual overpressure in the closed shale system. The larger pore size and better pore connectivity enable gas molecule to be much easier to diffusion and flow, thus leading to high yield after hydraulic fracturing. Conversely, the OM pores of the deformed region shales are commonly compressed and even closed, because of the absence of overpressure-associated supporting mechanism in a relatively opened shale system. Shale gas is difficult to transport in this kind of shale reservoir with poor pore structure parameters, resulting in limited yield. Furthermore, our work also provides 3D pore deformation information of shale reservoirs under complex tectonic episodes. • Shale pores were quantitatively evaluated in 2D and 3D under different tectonic preservation condition. • Tectonic deformation influences the shale pore structure and connectivity. • Great preservation condition is beneficial to gas accumulation and engineering renovation. [ABSTRACT FROM AUTHOR]

The distribution and development of faults and fractures in organic-rich shales are important factors for the accumulation or loss of shale gas. In this work, merged three-dimensional seismic data, automated fault extraction, imaging logging, rock core examination, micro-CT scans, and field emission scanning electron microscopy were used to precisely characterize the distribution of faults and fractures of the Wufeng-Longmaxi shales from the Zilichang Block, Jiaoshiba area. The effects of faults and fractures on the accumulation and loss of shale gas were analyzed. The results show that the microfractures of shale samples from the JYA well of the Zilichang Block mainly consisted of intergranular, intragranular, and contraction fractures, and the fracture porosity of the samples is approximately 1.24%. These fractures help to increase the storage space of the shale reservoirs and are conducive for shale gas accumulation. In micro-CT scans, the microfractures were linked in a network-like structure and generally had excellent connectivity. Therefore, the microfractures could enhance the seepage capacity of the shale reservoirs and help the shale gas to migrate to hydraulically induced fractures. As a result, the productivity of the shale reservoirs could be dramatically improved. Macroscopic fractures were found to play a key role in the storage of shale gas. Many natural fractures, mainly are faults and open fractures, have developed in the caprock strata that directly overly the main production layers shales. The shale gas direct seal conditions are poor, which is not conducive to shale gas accumulation. Therefore, the Wufeng-Longmaxi shales in the JYA well is a relatively open shale system, with a formation pressure coefficient and gas saturation value of 0.96 and 37%, respectively. The single-well hydraulic fracturing productivity of the JYA well is low, with an absolute open flow value less than 0.5 × 104 m3/d. • Multiscale faults and fractures were identified. • Faults and macrofractures cause the loss of shale gas. • Microfractures enhance the seepage capacity of shale gas. [ABSTRACT FROM AUTHOR]

Both the characteristics of lithofacies and tectonic movements are important factors in controlling the development, destruction, and preservation of pores in shale reservoirs. However, the main factors that control the structure of shale pores are complex and highly disputed, restricting the understanding of the mechanisms that lead to the accumulation of shale gas. In this study, mineral composition and geochemical analyses, high resolution field emission scanning electron microscopy (FE-SEM), and low-pressure gas adsorption (N 2 and CO 2) were conducted to evaluate the pore systems of different types shale in the Jiaoshiba area, Sichuan Basin. A total of three shale groups, including silica-rich high production shales, clay-rich low production shales, and silica-rich low production shales were identified on the basis of lithofacies and gas-bearing characteristics. The highest values of TOC, pore volume, and specific surface area are found in the silica-rich high production shales, with an average of 4.182%, 33.04 × 10−3 cm3/g, and 38.71 m2/g, respectively. The total pore volume and specific surface area in the clay-rich low production shales are 19.85% and 28.62% lower than that of silica-rich high production shales. This suggests that the types of lithofacies have a more prominent influence on the specific surface area of the shales, while the pore volume plays a smaller role. However, the pressure in silica-rich low production shales is often released due to strong tectonic deformation. The OM pores in the silica-rich low production shales therefore tend to be both compressed and closed, with low surface porosity and of round shape. The total pore volume and specific surface area of silica-rich low production shales are 34.63% and 22.0% lower than that of the silica-rich high production shales. This indicates that tectonic movement has a significant influence on the shale pore volume, while specific surface area has a smaller influence. • Effects of lithofacies and preservation conditions on shale pores structure are analyzed. • Lithofacies mainly controls specific surface area and adsorbed gas. • Preservation conditions mainly controls shale pore volume and free gas. [ABSTRACT FROM AUTHOR]