Clay Mineral Pores Research Articles

Pore Fractal Characteristics between Marine and Marine–Continental Transitional Black Shales: A Case Study of Niutitang Formation and Longtan Formation

Marine shales from the Niutitang Formation and marine–continental transitional shales from the Longtan Formation are two sets of extremely important hydrocarbon source rocks in South China. In order to quantitatively compare the pore complexity characteristics between marine and marine–continental transitional shales, the shale and kerogen of the Niutitang Formation and the Longtan Formation are taken as our research subjects. Based on organic petrology, geochemistry, and low-temperature gas adsorption analyses, the fractal dimension of their pores is calculated by the Frenkel–Halsey–Hill (FHH) and Sierpinski models, and the influences of total organic carbon (TOC), vitrinite reflectance (Ro), and mineral composition on the pore fractals of the shale and kerogen are discussed. Our results show the following: (1) Marine shale predominantly has wedge-shaped and slit pores, while marine–continental transitional shale has inkpot-shaped and slit pores. (2) Cylindrical pores are common in organic matter of both shale types, with marine shale having a greater gas storage space (CRV) from organic matter pores, while marine–continental transitional shale relies more on inorganic pores, especially interlayer clay mineral pores, for gas storage due to their large specific surface area and high adsorption capacity (CRA). (3) The fractal characteristics of marine and marine–continental transitional shale pores are influenced differently. In marine shale, TOC positively correlates with fractal dimensions, while in marine–continental shale, Ro and clay minerals have a stronger influence. Ro is the primary factor affecting organic matter pore complexity. (4) Our two pore fractal models show that the complexity of the shale in the Longtan Formation surpasses that of the shale in the Niutitang Formation, and type I kerogen has more complex organic matter pores than type III, aiding in evaluating pore connectivity and flow effectiveness in shale reservoirs.

Controls of carbon isotope fractionation during gas desorption in overmature marine shales

Carbon isotope fractionation serves as a crucial tool for assessing gas-in-place content and the gas-adsorbed ratio of shale gas during production. However, a significant gap exists in the understanding of the mechanism and impacts of diverse composition and organic matter on carbon isotope fractionation. To address this gap, this study conducted adsorption and desorption experiments on ten shale samples from the Longmaxi Formation. Various integrated analytical techniques were employed, encompassing X-ray diffraction, bitumen reflectance measurement, total organic carbon (TOC) content analysis, stable carbon isotope analysis, low-pressure gas adsorption tests, and field emission scanning electron microscopic observations. The results reveal that methane dominates the shale gas, with the carbon isotopes exhibiting a distinctive full reversal, attributed to the redox reaction between the ethane and water or transition metals. Differential adsorption capacities of shale led to varied carbon isotope distribution during desorption experiments. Increased micropore quantity in shale is anticipated to augment its adsorption capacity, while elevated feldspar content constrains adsorption due to the absence of intraparticle pores. Consequently, a negative correlation is observed between feldspar content and shale gas fractionation. Although intraparticle pores exist in carbon minerals, their connectivity and low carbonate content limit adsorption capacity in clay-rich shale. Deep burial depletes slit pores in clay minerals, resulting in a low adsorption capacity in clay-rich shale. Notably, the over-mature stage exhibits a substantial increase in micropores within organic matter, positively correlating with carbon isotope fractionation. The positive correlation between quartz content and TOC content is attributed to the positive relationship between the quartz content and carbon isotope fractionation. Additionally, the isotopic values of desorbed gas exhibit significant variability when TOC content exceeds 2.0%, remaining stable when TOC content is less than 2.0%.

Enrichment characteristics and exploration potential of the Permian marine shale gas in the Wujiaping Formation, Sichuan Basin, SW China

Shale gas exploration has achieved global success in marine shales. This study analysed geochemical, mineralogical, porosity, permeability and gas‐bearing parameters of organic‐rich shales in the Permian Wujiaping Formation in the Sichuan Basin. A comprehensive comparison was conducted with the Longtan Formation transitional shales and typical commercially developed marine shales. The results showed that: (1) siliceous shale within the Wujiaping Formation exhibits total organic carbon content ranging from 0.60% to 9.53% (average 4.45%) and vitrinite reflectance (Ro) ranging from 1.83% to 2.14% (average 1.98%), indicating an overmature stage of hydrocarbon generation. Porosity varies from 0.48% to 11.8% (average 4.94%), with an average content of 51.4% brittle minerals (quartz+calcite+dolomite) and calculating gas content exceeding 3 m3/t based on logging data. Effective sealing is achieved by the overlying carbonate of the Changxing Formation and the underlying carbonate of the Maokou Formation. (2) The primary storage space of the siliceous shale in the Wujiaping Formation encompasses diverse organic matter pores, clay mineral pores and microfractures. The porosity and permeability of the Wujiaping Formation marine shale ranges from 0.48% to 11.8% and 0.0053 to 0.8450 mD. Total gas content was estimated between 3 to 12 m3/t averaging 6 m3/t. (3) By comparing Permian Wujiaping Formation shales with Longtan Formation transitional shales, Wufeng Formation‐Longmaxi Formation shales and the typical North American marine gas shales (such as Barnett, Ohio, Antrim, New Albany, etc.), we conclude that marine siliceous shales within the Wujiaping Formation exhibit enrichment conditions comparable to established marine shales and superior to Permian transitional shales. The favourable upper and lower seals of the Wujiaping Formation resemble those of the Barnett shale gas reservoirs. In conclusion, the marine shale in Wujiaping Formation holds potential for substantial shale gas reservoirs and is poised for strategic exploration and development breakthroughs in the northeast and east Sichuan Basin.

Pore Characteristics, Oil Contents and Factors Influencing Laminated Shale in the First Member of the Qingshankou Formation in the Gulong Sag, Northern Songliao Basin

To clarify the reservoir characteristics of laminated shale, the occurrence mechanism of shale oil and its influencing factors in the Gulong Sag, northern Songliao Basin, are studied to better guide the exploration and development of shale oil there. First, X-ray diffraction (XRD) and field-emission scanning electron microscopy (FE-SEM) are used to characterize the pore types, pore geneses and factors influencing the pore volume in the study area. Second, the organic matter of the samples is extracted with a mixture of dichloromethane and methanol. Total organic carbon (TOC), nitrogen adsorption and Rock-Eval tests are performed on the samples before and after extraction to reveal the pore size distribution after extraction. The factors influencing free and adsorbed shale oil and the lower limit of pore size are discussed in detail. The results show that interparticle pores (interP pores), intraparticle pores (intraP pores), organic matter pores (OM pores) and microfractures can be found in the laminated shale (Q1) in the Gulong Sag, Songliao Basin, and that the interP pores and intercrystalline pores in clay minerals are the main pores. The FE-SEM results show that the diameters of interP pores vary from several hundred nanometers to several microns, and their morphologies are mainly triangular, strip-shaped or irregular. The morphology of the intercrystalline pores in the clay minerals is generally irregular, depending on the crystal type and arrangement of clay minerals. According to the characteristics of the nitrogen adsorption and desorption curves, the pore morphologies are mainly slit-shaped pores, parallel-plate-shaped pores and ink-bottle-shaped pores. The pore size distribution is mostly bimodal, and the pore volume contribution is the greatest in the pore size range of 10~20 nm. Before and after extraction, the overall characteristics of the pore size distribution change only slightly, but the number of micropores increases significantly. Different minerals have different degrees of influence on the proportions of micropores, mesopores and macropores. Quartz mainly inhibits the formation of micropores, while the overall effect on mesopores and macropores is positive depending on the diagenetic period. Feldspar has a strong positive correlation with the micropore and mesopore proportions but is not highly correlated with the macropore proportions. The influence of the carbonate mineral content on the pore volume is not obvious because of its complex composition. The TOC content and vitrinite reflectance (Ro) are the two most important factors controlling free oil and adsorbed oil, and the contents of mineral components, such as felsic minerals, carbonate minerals and clay minerals, have no obvious correlation with shale oil content. With increasing pore volume, the contents of free oil and adsorbed oil increase, but the proportion of adsorbed oil decreases gradually. The correlation between the specific surface area and adsorbed oil content is poor. At normal temperatures and pressures, the lower limit of the pore diameters that can contain free oil is 4 nm, and the lower limit of the pore diameters that can contain movable oil is 10 nm.

The importance of pore-fracture connectivity in overmature marine shale for methane occurrence and transportation

Pore-fracture connectivity is a critical factor in gas occurrence and transportation in shale plays. To investigate the limiting factors of multiscale pore-fracture connectivity, which might control methane occurrence and transportation in shale reservoirs, small-angle neutron scattering (SANS) under vacuum and high-pressure conditions incorporated with repeated mercury intrusion capillary pressure (MICP), and field emission-scanning electron microscopy (FE-SEM) imaging after Wood's metal (WM) impregnation were performed on overmature marine shale samples of the Wufeng-Longmaxi and Niutitang Formations from south China. Based on the electron micrographs of the WM-injected samples, it was found that the sealing of the pore system by brittle minerals is the root cause for a reduction in overall pore connectivity within the shale matrix. Aside from being favorable to the preservation of organic and clay mineral pores, brittle minerals however, resulted in the closure of pore network, thus, forming an isolated pore system. The novel approach of integrating repeated MICP measurement and FE-SEM imaging after WM impregnation provides a new evaluation method for pore-fracture connectivity of shale. The minimum fraction of pores within the overmature shales accessible to methane was at 38% and 78% within 100 nm. Moreover, because of confinement effects, the density of methane in a pore space less than 20 nm under high pressure was greater than that of an ideal gas under the same pressure conditions which even increased with decreasing of pore size to several times of its inert state and formed nanoscale methane clusters. The combination of contrast-matching SANS (CM-SANS) and repeated MICP measurements can effectively reveal the connectivity of pores within the matrix and the connectivity between such pores and microfractures, which helps to evaluate the distribution of closed pores and dominant transport spaces of gas in shale reservoirs. Overall, the pore-fracture connectivity in overmature marine shale controls the amount of gas that is supplied from matrix pores into fracture systems and also affects the density of the gas in pore spaces within the matrix.

Key factors controlling oil contents in different lithofacies shales from the Funing Formation, Subei Basin: Evidence from scanning electron microscopy

Lacustrine shales with complex mineral compositions and rock formations are associated with different lithofacies, and shale oil contents vary significantly depending on the lithofacies. This study examines lacustrine shales from the Funing Formation, Gaoyou Sag, Subei Basin using scanning electron microscopy, total organic carbon (TOC), Rock-Eval pyrolysis, X-ray diffraction, thin section, and nuclear magnetic resonance T1–T2 to determine the key factors controlling oil content in different shale lithofacies. Shale lithofacies were determined based on the mineral composition, rock structure, and organic matter content. The micro-distributions of shale oil in different lithofacies were disclosed. The results show that the studied shales in Gaoyou Sag are primarily divided into massive felsic-rich, stratified felsic-rich, laminated felsic-rich, laminated felsic, laminated calcareous-rich, and laminated calcareous shales. Massive felsic-rich shales have the largest TOC, S1, and free oil contents associated with organic-rich shales. Stratified felsic-rich shales have the larger TOC, S1, and free oil contents, followed by the laminated felsic-rich and felsic shales. However, laminated calcareous-rich shales are characterized by larger TOC but lower S1 and free oil contents, whereas laminated calcareous shales have the lowest organic matter and oil contents. Shale oil content is mainly affected by the organic matter content and the development of reservoir space. Massive felsic-rich shales are characterized by almost all pores saturated with oil. The oil contents in stratified felsic-rich, laminated felsic-rich, laminated felsic, and laminated calcareous-rich shales are primarily affected by the development of reservoir spaces, followed by organic matter abundance. However, laminated calcareous shales are the opposite. Interparticle pores at the edge of granules are the most developed pores, whereas interparticle pores associated with quartz are generally saturated with oil, followed by those related to calcite or dolomite. Intraparticle pores in clay minerals are usually free of oil. Moreover, shale oil primarily occurs in large interparticle pores. The organic-rich massive felsic-rich and organic-bearing laminated felsic-rich shales are favorable for shale oil enrichment, and organic-bearing laminated felsic-rich shales with larger pores and interlayer micro-fractures may be the optimal lithofacies for shale oil. This study provides insight into the micro-distribution of shale oil in different lithofacies, which will guide shale oil development in the Gaoyou Sag, Subei Basin.

Study on oil seepage mechanisms in lamellar shale by using the lattice Boltzmann method

The shale oil and gas resources in the world are rich and are an important part of unconventional oil and gas resources. In this paper, firstly, by comprehensively using CT scanning technology, the three-dimensional pore-fracture structure characteristics of shale core samples of different sizes is characterized, and a three-dimensional digital core is established; Secondly, SEM and FIB-SEM techniques are systematically used to describe the microstructure and fracture network development characteristics of shale matrix pores and fractures, and a three-dimensional pore and fracture network model is established; Thirdly, Combined with LBZ simulation method, the mechanism of two-phase fluid transport in shale cross-scale fracture network is explored. Results show that: (a) The relatively dispersed mesopores and macropores in space constitute the main storage space of methane. Some pores in the study area of shale samples have good connectivity, and some samples only have connected pores in the study area of their magnification. (b) A large number of intergranular pores and fissures developed together with the intergranular pores of clay minerals, forming a good network connection system between microscopic pores in laminated shale. (c) when the hydrophilic mineral proportion is increased from 30% to 70%, the relative permeability of oil phase at water saturations of 20%, 40% and 60% has an increase of 6.8%, 7.8% and 4.2%, respectively, and the relative permeability of water phase at water saturations of 20%, 40% and 60% has a decrease of 1.8%, 2.6% and 6.5%, respectively. (d) When the oil phase contact angle is increased from 30° to 70°, the relative permeability of oil phase at water saturations of 20%, 40% and 60% has an increase of 1.9%, 2.7% and 2.2%, respectively, and the relative permeability of water phase at water saturations of 20%, 40% and 60% has a decrease of 1.2%, 2.1% and 3.5%, respectively.

NMR-Based Analysis of Fluid Occurrence Space and Imbibition Oil Recovery in Gulong Shale

The Gulong shale oil reservoir is situated in freshwater to slightly saline lacustrine basins mainly consisting of a pure shale geological structure, which is quite different from other shale reservoirs around the world. Currently, the development of Gulong shale oil mainly relies on hydraulic fracturing, while the subsequent shut-in period for imbibition has been proven to be an effective method for enhancing shale oil recovery. To clarify the characteristics of the fluid occurrence space and the variation in the fluid occurrence during saltwater imbibition in Gulong shale, this paper carried out porosity and permeability tests on Gulong shale cores and analyzed the fluid occurrence space characteristics and imbibition oil recovery based on nuclear magnetic resonance (NMR). In the porosity and permeability tests, T2 distributions were used to correct the porosity measured by the saturation method to obtain the NMR porosity. Combined with the identification of fractures in shale cores using micro-CT and the analysis of porosity and permeability parameters, it was found that the permeability of the shale cores was related to the development of fractures in the shale cores. Through the testing and analysis of T1-T2 maps of the shale cores before and after saturation with oil, it was found that the shale mainly contained heavy oil, light oil, and clay-bound water, and they were distributed in different regions in the T1-T2 maps. Finally, the T1-T2 maps of the shale cores at different imbibition stages were analyzed, and it was found that saltwater mainly entered the minuscule inorganic pores of clay minerals during the imbibition process and squeezed the larger-sized inorganic pores containing light oil through the hydration expansion effect, thus expelling the light oil from the shale core and achieving the purpose of enhanced oil recovery.

Study on the Sedimentary Environments and Its Implications of Shale Reservoirs for Permian Longtan Formation in the Southeast Sichuan Basin

Marine–continental transitional shale is one of the most promising targets for shale gas exploration in the Lower Yangtze region. To investigate the sedimentary environments and the regularity of the enrichment of the Longtan shale, multiple techniques including core and thin-section observations, geochemical and elemental analyses, X-ray diffraction, scanning electron microscopy (SEM), and low-pressure nitrogen adsorption (LPNA) were used to analyze the sedimentology, mineralogy, and pore structure of the Longtan shale. The core descriptions and thin-section observations showed that the Longtan shale was deposited in marine–delta transitional environments including delta-front, shore swamp, mixed tidal flat and shallow shelf environments. The Sr/Cu, V/Cr, CIA, EF (Mo), EF (U), and other major and trace element results indicated warm and moist climates and water-reducing conditions in the Longtan period. Both the climate and water conditions were favorable for organic matter production and preservation. The geochemical results showed that the Longtan shale was in the overmature stage (Ro values ranging from 2.4% to 3.57%) and that the average total organic carbon (TOC) content was 5.76%. The pore system of the Longtan shale consisted of inorganic pores with a small number of organic pores and microfractures. The porosity and specific surface area were mainly affected by the TOC and clay mineral contents. An effective combination of brittle mineral particles, organic matter, and clay minerals provided the necessary conditions for pore preservation. The organic pores, intergranular pores in clay minerals, and brittle mineral pores formed the main network system for the Longtan shale. In summary, the lithological combinations, organic geochemistry, and pore structure system were all affected by the sedimentary environments.

Favorable lithofacies and pore characteristics of the Permian Longtan Formation shale in the southern Sichuan Basin

The marine–continental transitional shale (MCTS) reservoirs of the Longtan Formation (LTF) are widely distributed in the Sichuan Basin. However, the LTF shale exhibits considerable variations in mineral composition and pore characteristics, which makes identifying the 'sweet spot'a challenging task. To address this issue, 10 samples from four typical shale gas wells in the LTF in the southern Sichuan Basin were selected and analyzed for total organic carbon (TOC) content, whole-rock composition using X-ray diffraction (XRD), low-pressure gas adsorption, and high-pressure mercury intrusion. The lithofacies distribution and pore structure of the MCTS were studied to determine the pore structural characteristics and the primary factors influencing pore formation in different types of shale lithofacies in the LTF. The lithofacies of the LTF shale in the study area can be classified into three categories: siliceous clay shale, clay shale and mixed shale. Mineral content has a significant impact on the pore characteristics, while TOC content has a minor effect on the pore volume and specific surface area of micropores and mesopores. It can be inferred that the mesopores in the MCTS are mainly related to clay mineral pores, and mineral dissolution and TOC content are not the primary factors contributing to pore formation.

Characteristics and Influencing Factors of Multi-Scale Pore Structure Heterogeneity of Lacustrine Shale in the Gaoyou Sag, Eastern China

The success of shale oil exploration and production is highly dependent on the heterogeneous nature of the reservoir pore structure. Despite this, there remains limited research on the heterogeneity characteristics of pores at different scales in lacustrine shale oil reservoirs and the factors that impact them. This study aims to quantitatively characterize the multi-scale pore heterogeneity differences of the lacustrine shale found in the Funing Formation in Gaoyou Sag. Additionally, the study seeks to clarify the impact of the total organic carbon (TOC) and lithofacies type on pore structure heterogeneity. To achieve this, nitrogen adsorption, scanning electronic microscope (SEM), mercury intrusion porosimetry (MIP), and other experimental means were adopted in combination with the fractal dimension model of FHH and capillary. The results show that the predominant lithofacies of the Funing Formation shale samples are mixed shale (MS) and siliceous shale (SS), with a limited presence of calcareous shale (CS). The micro-pores of lacustrine shale are dominated by inorganic mineral pores and fewer organic pores. Intragranular pores and clay mineral pores are two types of inorganic mineral pores that are widely found. Small pores (pore diameter < 50 nm) make up 89% of the pore volume (PV) and 99% of the specific surface area (SSA). The fractal dimensions D1, D2, and D3 were calculated to characterize the roughness of the pore surface, the structural complexity of small pores, and the structural complexity of large pores (pore diameter > 50 nm), respectively. The increase in the total organic carbon (TOC) resulted in a decrease in the D1, D2, PV, and SSA, while connectivity showed a slight improvement. The fractal dimension of shale across all lithofacies followed the pattern: D3 > D2 > D1. The pore structure is more complex than the pore surface, and the large pores showed a greater heterogeneity than the small pores. Among the three lithofacies, CS had the largest PV, SSA, D1, and D2, indicating the development of a more complex pore structure network. This expands the space required for shale oil occurrence. However, the connectivity of the CS lithofacies is the lowest among the three, which hinders shale oil production. Although the PV of SS is slightly lower than that of CS, its average pore diameter (AVE PD) and connectivity are significantly advantageous, making SS an ideal shale reservoir. This study provides an important reference for the reservoir evaluation required to better develop lacustrine shale oil around the world.

Pore Structure and Gas Content Characteristics of Lower Jurassic Continental Shale Reservoirs in Northeast Sichuan, China

The Jurassic shale in the northeastern Sichuan Basin is one of the main target intervals for continental shale gas exploitation. Research on the pore structure and gas-bearing properties of shales is the key issue in target interval optimization. Through core observation, geochemistry, bulk minerals, scanning electron microscopy, nitrogen adsorption, and isothermal adsorption experiments, various lithofacies with different pore structure characteristics were clarified. In addition, the factors that control gas-bearing properties were discussed, and a continental shale gas enrichment model was finally established. The results show that the Jurassic continental shale in the northeastern Sichuan Basin can be classified into six lithofacies. Organic pores, intergranular pores, interlayer pores in clay minerals, intercrystalline pores in pyrite framboids, and dissolution pores can be observed in shale samples. Pore structures varied in different shale lithofacies. The contact angle of shales is commonly less than 45°, leading to complex wettability of pores in the shales. Free gas content is mainly controlled by the organic matter (OM) content and the brittleness in the Jurassic shale. The adsorbed gas content is mainly controlled by the OM content, clay mineral type, and water saturation of the shales. The enrichment mode of the Lower Jurassic continental shale gas in the northeastern Sichuan Basin is established. Paleoenvironments control the formation of organic-rich shales in the center part of lakes. The "baffle" layer helps the confinement and high pressure, and the complex syncline controls the preservation, forming the enrichment pattern of the complex syncline-central baffle layer.

Characteristics of In Situ Desorption Gas and their Relations to Shale Components: A Case Study of the Wufeng-Longmaxi Shales in Eastern Sichuan Basin, China

AbstractIn situ desorption gas measurement can be used to evaluate shale gas potential, sweet spot prediction, and production strategy optimization. However, gas contents and carbon isotope compositions of in situ desorption gas and the relationship to reservoir properties and shale compositions are not systematically studied from the actual production situation. In this study, 63 core shales of Wufeng-Longmaxi formation from the YY1 well in the eastern Sichuan Basin were subjected to TOC (total organic carbon), solid bitumen reflectance (Rb), maceral fractions of kerogen analysis, and X-ray diffraction (XRD) analysis to obtain shale compositions, and 10 selected samples were conducted on low-pressure N2/CO2 (N2/CO2GA), mercury injection capillary pressure (MICP), and field emission scanning electron microscopy (FE-SEM) tests to acquire reservoir properties. Meanwhile, 60 samples were also subjected to in situ desorption tests to obtain shale gas content, and 5 selected samples were used to investigate variations in shale gas compositions and carbon isotopes during the desorption process. Results indicated that transient rates of shale gas during desorption process are significantly controlled by desorption time and temperature. In terms of in situ desorption process, total gas is divided into desorbed gas and lost gas. Desorbed gas is mainly comprised of CH4, N2, CO2, and C2H6, with desorption priorities of N2 > CH4 > CO2 ≈ C2H6, which are consistent with their adsorption capacities. The δ13CH4 values tend to become heavier during desorption process, varying from -37.7‰ to -16.5‰, with a maximum increase amplitude of 18.8‰, whereas the change of δ13C2H6 value, from -38.2‰ to -34.8‰, is minor. Desorbed gas shows carbon isotope reversals, due to that preferential desorption of 12C-CH4 during desorption process results in δ13C value less negative in CH4. The tested desorbed gas, lost gas, and total gas ranged 0.088 to 1.63 cm3/g, 0.15 to 3.64 cm3/g, and 0.23 to 5.20 cm3/g, respectively. Shale gas content, i.e., desorbed gas and lost gas, is controlled primarily by TOC content and organic matter (OM)-hosted nanometer-size pores. Clay mineral content is negatively correlated with shale gas content, due to that, clay mineral pores are more easily compacted during burial and occupied by water molecules. Compared with shale gas reservoirs in North America, the studied shale reservoir has high brittle mineral content and permeability, which is considered to have great potential of shale gas resource and to be the next commercial development zone in south China.

Porosity, permeability and rock mechanics of Lower Silurian Longmaxi Formation deep shale under temperature-pressure coupling in the Sichuan Basin, SW China

To investigate the porosity, permeability and rock mechanics of deep shale under temperature-pressure coupling, we selected the core samples of deep shale from the Lower Silurian Longmaxi Formation in the Weirong and Yongchuan areas of the Sichuan Basin for porosity and permeability experiments and a triaxial compression and sound wave integration experiment at the maximum temperature and pressure of 120 °C and 70 MPa. The results show that the microscopic porosity and permeability change and the macroscopic rock deformation are mutually constrained, both showing the trend of steep and then gentle variation. At the maximum temperature and pressure, the porosity reduces by 34%–71%, and the permeability decreases by 85%–97%. With the rising temperature and pressure, deep shale undergoes plastic deformation in which organic pores and clay mineral pores are compressed and microfractures are closed, and elastic deformation in which brittle mineral pores and rock skeleton particles are compacted. Compared with previous experiments under high confining pressure and normal temperature, the experiment under high temperature and high pressure coupling reveals the effect of high temperature on stress sensitivity of porosity and permeability. High temperature can increase the plasticity of the rock, intensify the compression of pores due to high confining pressure, and induce thermal stress between the rock skeleton particles, allowing the reopening of shale bedding or the creation of new fractures along weak planes such as bedding, which inhibits the decrease of permeability with the increase of temperature and confining pressure. Compared with the triaxial mechanical experiment at normal temperature, the triaxial compression experiment at high temperature and high pressure demonstrates that the compressive strength and peak strain of deep shale increase significantly due to the coupling of temperature and pressure. The compressive strength is up to 435 MPa and the peak strain exceeds 2%, indicating that high temperature is not conducive to fracture initiation and expansion by increasing rock plasticity. Lithofacies and mineral composition have great impacts on the porosity, permeability and rock mechanics of deep shale. Shales with different lithologies are different in the difficulty and extent of brittle failure. The stress-strain characteristics of rocks under actual geological conditions are key support to the optimization of reservoir stimulation program.

Differences in Pore Type and Pore Structure between Silurian Longmaxi Marine Shale and Jurassic Dongyuemiao Lacustrine Shale and Their Influence on Shale-Gas Enrichment

The Silurian Longmaxi (S1l) marine shale and Jurassic Dongyuemiao (J1d) lacustrine shale in the Sichuan Basin, West China have attracted considerable attention from the oil-and-gas industry in China. Currently, the differences in pore types and pore structures between them are poorly understood, which has limited shale-resource exploration in the Sichuan Basin. This paper systemically compares the pore characteristics of Longmaxi shale and Dongyuemiao shale and investigates their impact on shale-gas enrichment by integrating field-emission scanning electron microscopy (FE–SEM), X-ray diffraction (XRD), low-pressure gas (CO2 and N2) adsorption and mercury-intrusion porosimetry, high-pressure sorption isotherms, gas-saturation measurement, molecular-dynamics simulation, etc. The results show that the S1l organic-rich marine shale and the J1d lacustrine shale have different pore types and pore structures. The S1l shale is dominated by organic pores, mainly micropores and mesopores with ink-bottle-like pore shapes, while the J1d shale is primarily composed of clay-mineral pores, mainly mesopores and macropores with slit- or plate-like pore shapes. Organic pores can provide considerable storage space for shale-gas enrichment in S1l marine shale, which also determines the adsorption capacity of shale reservoirs. Although organic pores are not the most prevalent in the Dongyuemiao lacustrine shale, they also play an important role in enhancing reservoir quality and absorbed-gas enrichment. Clay-mineral pores contribute weakly to the storage space of J1d-lacustrine-shale reservoirs. Mesopores are the most important form of storage space in both S1l shale and J1d shale, contributing significantly to shale-gas enrichment. Micropores are secondary in importance in S1l marine shale, while macropores are secondary contributors to pore volume in J1d lacustrine shale.

Paleo-sedimentary environment and lithofacies of Jurassic Da’anzhai Member in the Central Sichuan Basin-A case study of Well Ren’an 1

The Jurassic Da’anzhai Member in Sichuan Basin is an important target for shale oil exploration. Whole rock X-ray diffraction analysis, thin section, SEM and TOC testing, as well as major and trace element analysis are used to analyze the relationship of lithofacies and pore types with the sedimentary environment of the Da’anzhai Member in the Central Sichuan Basin. The results show the Da’anzhai Member in the Well Ren’an 1 (RA1) is divided into six types of lithofacies, based on a three-level division method of mineral composition-TOC-mineral structure— namely, massive mud-bearing shell limestone lithofacies (F), thick argillaceous shell limestone lithofacies (E), laminated clay silt shale lithofacies (D), thin shell calcareous shale lithofacies (C), laminated shell-bearing shale lithofacies (B), and thick clay shale lithofacies (A). The pore spaces include intergranular pores, intergranular dissolution pores, authigenic calcite intergranular pores, authigenic quartz intercrystalline pores, intergranular pores of clay minerals or pyrite nodules, as well as organic pores. The Da’anzhai Member was deposited in a semi-deep to shallow lake sedimentary environment, with relatively low salinity. This strata experienced moderate-to-strong chemical weathering as a result of the semi-arid, warm and humid paleoclimate environmental conditions that persisted during its deposition; low weathering and dry paleoclimate conditions occurred periodically. Paleoenvironment is an important influence on the lithofacies and pore types of the Da’anzhai Member. The persistence of arid climate conditions contributed to a decline in water depth, relatively high salinity, low organic productivity, and the deposition of carbonate rocks that characterize lithofacies E and F; mostly intercrystalline pores formed in these lithofacies in response to the prevailing arid climate conditions. Conversely, warm, and humid climate conditions increased the inflow of fresh water, terrigenous debris, and nutrients into the lacustrine basin that led to the deposition of fine-grained sedimentary rocks of lithofacies A, B, and C. These lithofacies are characterized by abundant nano pores, such as clay intercrystalline pores and organic pores.

Source rock and reservoir qualities of middle Jurassic Lianggaoshan lacustrine shale at fuxing area, Sichuan Basin: Implication for shale-oil enrichment

The shale oil exploration, in the Middle Jurassic Lianggaoshan Formation in the Fuxing area of Sichuan Basin, is in preliminary stage, requiring further in-depth study on shale oil and gas enrichment conditions. The lithological, organic geochemical, and reservoir characteristics of the Lianggaoshan Formation shale were analyzed using a suite of tests, including common thin section observation, organic carbon determination, pyrolysis experiment, combined N 2 -high pressure mercury test and argon ion polishing-scanning electron microscope, to elucidate source rock and reservoir qualities and their variation in vertical. Results suggest that the medium-carbon argillaceous shale, medium-carbon shell calcareous-argillaceous shale, and low-carbon argillaceous shale facies were mainly developed in Member 1 and Member 2 of the Lianggaoshan Formation. The medium-carbon argillaceous shale facies in the sub-layer ④ was rich in organic matter, with abundant sapropel, chitinous and secondary organic components, which were considered as a set of medium-quality source rocks. The medium-carbon shell calcareous-argillaceous shale and low-carbon argillaceous shale in the sub-layers ② and ③ have relatively low organic matter abundance, with vitrinite and inertinite as major organic microscopic components, revealing poor hydrocarbon generation potential. The porosity of shale reservoirs in sub-layers ②‒④ was higher than 3.0%, with predominant mesopores, followed by macropores, consisting of mainly clay mineral pores, organic pores, and microfractures related to organic matter. The medium-carbon argillaceous shale facies at the Lianggaoshan Formation is high-quality source rocks and reservoirs and is thus a potential target for lacustrine shale oil exploration in the Fuxing area of the Sichuan Basin. • The medium carbon clayey shale, medium carbon shell calcareous-clayey shale, and low carbon clayey shale were mainly developed in Member 1 and Member 2 of the Lianggaoshan Formation. • The medium carbon clayey shale facies in the sub-layer ④ exhibits adequate potential as hydrocarbon source rock and reservoir. • Sub-layer ④ is thus a potential target for continental shale oil exploration in the Fuxing area of the Sichuan Basin.

Impacts of different matrix components on multi-scale pore structure and reservoir capacity: Insights from the Jurassic Da’anzhai member in the Yuanba area, Sichuan Basin

Pore structure is an important parameter for the gas-bearing evaluation of lacustrine shale. However, the characteristics and influencing factors of pore structure and the shale reservoir capacity remain unclear due to the heterogeneity and complexity of shale reservoirs. This study focused on Da’anzhai shale to research the pore structure characteristics using a combination of field emission scanning electron microscopy, low pressure gas adsorption, and mercury intrusion porosimetry. The effects of different matrix components on multi-scale pore structure and the reservoir capacity are discussed. The results show that the total organic carbon (TOC) and vitrinite reflectance (Ro) are 0.7%–1.68% (average of 0.98%) and 1.42%, respectively. The organic macerals are vitrinite, inertinite, and solid bitumen, with the vitrinite predominating. The main minerals are clay minerals, quartz, and calcite. Matrix pores, including mineral-associated pores and organic matter pores, and microfractures jointly constitute the pore system of the Da’anzhai shale. Clay-mineral pores dominate, followed by organic matter pores. Pore sizes mainly range from 0.3 nm to 20 nm, reaching up to 10μm. Mesopore volumes are dominant, followed by micropores and macropores. The pore specific surface areas are 12.76–21.24 m2/g (average of 17.43 m2/g), of which micropores and mesopores account for 48.7% and 51.3%, respectively. TOC, organic macerals, and clay minerals are the controlling factors of the pore structure. In contrast, the impacts of Ro and the framework mineral content on shale pore structure are relatively weak. Da’anzhai shale has sufficient pore volume and specific surface area but the shale is dominated by clay mineral-associated large-size pores and microfractures with few organic micropores, resulting in limited adsorption capacity for the shale. A greater understanding of the pore formation mechanism of shale reservoirs is obtained through this study, which is of great significance for gas-bearing evaluations.

Pore Structure Characteristics and Permeability Stress Sensitivity of Jurassic Continental Shale of Dongyuemiao Member of Ziliujing Formation, Fuxing Area, Eastern Sichuan Basin

A shale condensate gas reservoir with a high clay content and a high formation pressure was found in the Jurassic shale of the Dongyuemiao Member in the Fuxing area of the eastern Sichuan Basin. Reservoir characteristics and formation pressure have a significant influence on optimal development. The present study investigated the continental shale of the Dongyuemiao Member in Well F. The petrological properties, physical properties, and pore structure of the Dongyuemiao Member were studied using X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), N2 adsorption, and mercury intrusion porosimetry (MIP). The permeability stress sensitivity characteristics of the shale reservoirs are discussed based on the change in shale porosity and permeability under overburden pressure. The tested shale samples yielded total organic carbon (TOC) and S1 + S2 values ranging mainly from 1.0 wt.% to 1.5 wt.% and from 0.39 to 2.28 mg/g, respectively, which was in the high maturity stage of the thermal evolution of organic matter (OM). The shales of the Dongyuemiao Member were found to contain high average clay mineral contents (more than 50%) of calcite and quartz, as well as albite, pyrite, dolomite, and halite. The main developments were identified as silica-rich argillaceous shale lithofacies, argillaceous shale lithofacies, and mixed argillaceous shale lithofacies. The pores were found to mainly be plate-like and flake-like interlayer pores of clay minerals and OM pores with various shapes. The pore size was mainly concentrated below 110 nm, and the pore volume increment increased in flakes with pore diameter. The average porosity and permeability of shale were found to be 4.827% and 0.243 mD, respectively. Clay minerals and quartz are beneficial for improving the porosity and permeability of reservoirs, while carbonate minerals have the opposite effect. The permeability of the shale showed a negative exponential change with increasing effective stress under overburden pressure. When the effective confining pressure was greater than 20 MPa, the decline rate of the shale permeability decreased with increases in the effective stress. The higher the clay mineral and TOC content, the stronger the stress sensitivity of shale permeability. The higher the carbonate mineral content, the weaker the stress sensitivity of shale permeability. The porosity sensitivity exponent indicates that matrix pores and micro-fractures are both developed in the Dongyuemiao Member, and the development of internal fractures is the main factor in the strong stress sensitivity of the shale permeability in the study area.

Differential effects of pore structure of mineral and maceral components on the methane adsorption capacity evolution of the lower jurassic Da'anzhai member of the Ziliujing Formation lacustrine shale, Sichuan Basin, China

Adsorbed gas makes a great contribution to shale gas reserves. During the geological evolution process, it is of prominent significance to clarify the dynamic evolution mechanism of methane adsorption capacity (MAC) of shale to enhance exploration. Variations of the pore structure and surface properties of shales lead to their different MAC. However, the pore structure characteristics and the evolution mechanism of different maceral and mineral components is different. The co-evolution modes and influence mechanism on the MAC of shale remains poorly understood. Therefore, in order to investigate the influential relationship between pore structure evolution and MAC of shales, methane adsorption experiments were conducted on a series of shale samples with the same composition at different thermal maturities. In addition, the original components of the shale sample were analyzed by measuring total organic carbon (TOC) content and mineral composition. Pore structures of the four shale samples were characterized by N2 adsorption, high-pressure mercury intrusion porosimetry (HPMIP), and digital analyses of field-emission scanning electron microscopy (FE-SEM). The results showed a good correlation between the APpore (apparent porosity of pore) of organic pores with the size ranging from 10 to 30 nm and MAC (R2 = 0.943), confirming the prominent influence of organic pores on the MAC of shale. In addition, the APpore of pores within 10–30 nm and aspect ratio of secondary organic matter with spongy pores are highly correlated with MAC (R2 are 0.833 and 0.811, respectively), which suggests that secondary organic matter with spongy pores have a crucial influence on MAC. Clay mineral pores with a pore size of 10–30 nm also effect the MAC of shale. A large number of clay mineral microfractures, with a scale of less than 200 nm, appear to effectively connect organic pores, providing a viable mechanism for hydrocarbon migration and enhancing the MAC of shale. Siliceous mineral dissolution pores and microfractures are not conducive to hydrocarbon migration due to their inability to form effective connections with organic pores and fractures and showing a weak correlation with MAC. The outcome of this study elucidates the main controlling mechanism affecting methane adsorption behavior of continental shale reservoirs and provides a path for the efficient exploration and evaluation of shale gas under actual geological conditions.