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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]

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]

The processes of shale gas transport and enrichment are closely related to the micro-fractures structure. Here, porosity, permeability test, gas adsorption, scanning electron microscopy (SEM), fluid spontaneous imbibition, Nano-CT, Micro-CT, and core observations were used to determine the types and characteristics of micro-fractures in the Longmaxi shales, Jiaoshiba area. The effects of micro-fractures on shale reservoir properties and shale gas accumulation were also analyzed. Diverse sizes of intra-particle (intraP), particle-edge, and transparticle micro-fractures were widely developed in shales. The difference of micro-fracture characteristics was mainly controlled by the mineral composition. The well-developed micro-fractures in the Longmaxi shales can act as a "bridge" to link nano-pores and macro-fractures. In such cases, a large-scale "escape network" composed of "nano-pores, micro-fractures, and macro-fractures" was formed. The escape of hydrocarbons along this network results in lower pore pressure. Most pores were dramatically compressed due to the compaction of overlying strata. As a result, the pore space and seepage capacity of organic-rich shales were disappointed, which is not benefit to the enrichment and production of shale gas. However, the limited development of micro-fractures will reduce the probability of forming "escape network". Thus, some of the pores could be remained and act as storage space along with micro-fractures for shale gas even within the tectonically deformed area. • Shale micro-fractures were systematically identified and quantitatively evaluated. • The micro-fractures have great influence on shale reservoir properties. • The micro-fractures can act as a "bridge" to link nano-pores and macro-fractures, thus forming a large-scale "escape network". [ABSTRACT FROM AUTHOR]

To accurately evaluate pore structure and gas content characteristics of shale reservoir, a series of tests, including XRD, TOC, porosity, FE-SEM, N 2 and CO 2 adsorption, and high-pressure methane sorption, were conducted on the Wufeng-Longmaxi shale in the Fuling area. The principal objective of this work is to reveal the development mechanisms of shale pores, and quantitatively calculated both free gas and absorbed gas contents in different lithofacies. A total of three main lithofacies, i.e., clay-rich siliceous shale lithofacies (S-3), argillaceous/siliceous mixed shale lithofacies (M-2) and silica-rich argillaceous shale lithofacies (CM-1) were identified in the study area. The highest values of TOC, helium porosity, pore volume, and specific surface area are recognized in the S-3 shales, with a mean of 3.94%, 5.12%, 22.13 × 10−3 cm3/g, and 35.23 m2/g, respectively. The pore volume and specific surface area of S-3 shales are primarily contributed by OM pores, with an average proportion of 66.99% and 66.38%. However, the pore volume and specific surface area of clay-related pores, a significant component of CM-1 shales, occupied an average of 64.30% and 52.72%, respectively. Owing to the change of lithofacies from S-3 to M-2 and CM-1 shales, the pore volume is reduced by 28.74% and 22.37%, while the specific surface area is reduced by 30.28% and 32.89%, respectively. The total shale gas contents of S-3 shales are calculated to be 5.54–7.72 m3/t, with an average of 6.64 m3/t, and that of M-2 shales and CM-1 shales are ranging from 4.28 m3/t to 5.03 m3/t and 2.43 m3/t to 4.33 m3/t, with a mean of 4.61 m3/t and 3.51 m3/t, respectively. However, due to the difference of pore types, the CM-1 shales are characterized by the highest proportion of free gas (average 59.08%), whereas that of M-2 shales and S-3 shales are recognized with 54.96% and 50.93%, respectively. • Pore volume and specific surface area were quantitatively evaluated in different shale reservoirs. • Adsorbed gas and free gas contents were quantitatively calculated based on modified Langmuir volume model. • Lithofacies has a strong influence on pore structure, specific surface area, and absorbed gas and free gas contents. [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]

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 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]