Pore Structure Of Shale Research Articles

Gas generation potential and pore characteristics of Jurassic lacustrine shale containing type Ⅱ kerogen: A case study of the Yabulai Basin, northwestern China

Jurassic lacustrine shales containing kerogen types Ⅱ and Ⅲ are widely distributed in sedimentary basins around the world. Previous studies on gas generation potential and pore characteristics of Jurassic lacustrine shales mainly focused on type Ⅲ kerogen, but ignored the systematic study of the shales containing type Ⅱ kerogen. This led to a poor understanding of the gas generation potential and pore characteristics of Jurassic lacustrine shales, which limits the effective exploration and development of shale gas. Taking the Lower Xinhe (J2x1) shale of the Yabulai Basin in northwestern China as the research object, this paper examines the gas generation potential and pore characteristics of a Jurassic lacustrine shale containing type Ⅱ kerogen. The J2x1 shale is largely classified as a very good source rock, kerogen is predominantly type Ⅱ, with thermal maturity ranging from mature to highly over-mature. The J2x1 shale is characterized by low porosity and permeability, and high content of brittle minerals. Different from the Jurassic lacustrine shales containing type Ⅲ kerogen, the J2x1 shales have a large amount of interparticle and intraparticle dissolution pores in the clay minerals as well as organic pores. The porosity and pore structure of the J2x1 shale are strongly controlled by total organic carbon (TOC) content. The methane adsorption capacity of the J2x1 shale is in the range of 2.10–2.99 m3/t, which is controlled by TOC content, clay mineral content, temperature and pressure. The geochemical characteristics, mineral composition and adsorption capacity suggest that the J2x1 shale has good shale exploration and development potential. A mathematical model is established to describe the various characteristics of methane adsorption capacity with depth and TOC content. The methane adsorption capacity of the J2x1 shale first increases and then decreases with increasing depth, with the depth corresponding to the maximum methane adsorption increases with increasing TOC content. When the TOC values of the J2x1 shale are mainly between 1% and 10%, the corresponding depth of the maximum methane adsorption capacity is 400–800 m, and the adsorption amount of the shale tends to minimize at a depth range of 2600–5100 m. The favorable shale gas exploration depth of the J2x1 shale in the study area increases with increasing TOC content. This research provides a geological reference for the exploration of this Jurassic shale gas in the Yabulai Basin, and the relevant experimental data provide important parameters for the numerical simulation of shale gas reservoirs in the study area. Moreover, the results of this study also provide an important reference for other basins in northwestern China, as well as continental basins with similar geological conditions in other regions.

The main controlling factors of tensile strength in sight of shale reservoir under horizontal bedding: Example of the Lower Paleozoic Niutitang Formation shale from Micangshan, China

Understanding the mechanical characteristics of marine shale during fracturing is essential for shale gas development, and its core scientific problem is what factors in shale control its mechanical properties. The 12 shale samples from the Lower Paleozoic Niutitang Formation in Micangshan are tested for tensile strength and examined using X-ray diffraction, low-field nuclear magnetic resonance (NMR), EA2000 elemental analyzer, and scanning electron microscopy to explore the main controlling factors of shale tensile strength under horizontal bedding conditions. The findings are as follows. (1) The tensile strength of the shale is relatively high, ranging from 10.05 MPa to 20.34 MPa. Quartz is the largest proportion of the shale minerals, accounting for 53.2 wt%–59.0 wt%, followed by anorthose and clay minerals. Total organic carbon (TOC) concentration ranges from 1.7 wt% to 4.1 wt%. (2) NMR results indicate that the pore structure of shale is mainly mesoporous, accounting for 75.76%–88.03%, followed by macropores (12.57%–21.24%) and micropores (0.68%–4.91%). Low-pressure nitrogen adsorption and desorption results indicate that the average pore diameter of shale is 12.58–16.02 nm, which is basically consistent with NMR results. The negative correlation between fractal dimension D2 and tensile strength indicates that the higher the tensile strength of the shale, the lower the complexity of its seepage pores. (3) Micropores occur mainly in clay minerals, whereas quartz indicates positively correlation with mesoporous content. The higher the proportion of mesopores, the lower the tensile strength. This indicates that the mesopores are the main factor controlling the tensile strength, and the quartz content in minerals is a secondary factor restricting the tensile strength. TOC has little controlling action on the tensile strength. This contribution provides a theoretical basis for shale fracturing.

Characteristics and controlling factors of pore structure of shale in the 7th member of Yanchang Formation in Huachi area, Ordos Basin, China

To clarify the influence of organic matter and mineral composition on the pore structure of shale reservoirs in the 7th member of the Yanchang Formation (Chang 7 Member) in the Ordos Basin, we characterized the pore structure of Chang 7 shale reservoirs using argon ion polishing-field emission scanning electron microscopy (FE-SEM) and low-pressure nitrogen adsorption (LP-N2A). This characterization was combined with whole-rock mineral composition and organic geochemical experiments to analyze the main controlling factors of the pore structure of Chang 7 Member shale. The results reveal the presence of various pore types in shale, including organic matter pores, intergranular pores, intercrystalline pores, dissolved pores, and micro-cracks. The LP-N2A isotherms of shale consistently exhibit type Ⅱ isotherms with H3 and H4 hysteresis loop characteristics, indicating the relatively developed nature of mesopores and a pore morphology characterized by parallel lamellar and “ink bottle” shapes. The primary determinants of shale pore structure are identified as organic matter, clay minerals, quartz, feldspar, and pyrite. Among these factors, clay mineral phase transformation generates a substantial number of micropores and mesopores within the mineral crystal layers, serving as the main source of shale pores in the study area. Additionally, liquid hydrocarbons generated, solid bitumen, and euhedral pyrite fill inorganic mineral pores, thereby reducing the pore space of Chang 7 shale to a certain extent. These results provide a new cognition into understanding the pore structure characteristics and controlling factors of Chang 7 shale.

Nanopore structures and controlling factors of the Early Cambrian shale reservoir in the Middle Yangtze Platform, South China

At present, the characteristics and controlling factors of nanopore structure in shale reservoirs are still not well understood owing to the concurrence of both organic matter (OM) and inorganic mineral (IM) pores. This issue is more prominent for the Early Cambrian shale in South China owing to the greatly variable nanopore structures of the samples from different areas. In this study, a set of Early Cambrian shale samples was taken from an exploration well in the Middle Yangtze Platform, a newly-determined shale gas play with a great potential outside the Sichuan Basin, their OM-removed (OMR) samples were obtained by a high-temperature oxidation method, and the pore structures of the bulk shales and their OMR-samples were analyzed by low-pressure gas adsorption experiments. The OM nanopore structure parameters of shale were calculated, and the controlling factors of OM and IM nanopores in the shale were investigated. The results show that the shale nanopores are mainly mesopores, their OM nanopores, especially OM micropores, are obviously more developmental compared with the IM nanopores. The TOC content is the dominant influencing factor of the shale nanopores. The brittle minerals support the formation of interparticle pores, and provide protection to OM pores. The clay minerals provide a certain amount of nanopores, but the strong compaction result in rich micropores. The carbonate minerals decrease the shale nanopores owing to the strong cementation. The favorable area of shale gas in the Early Cambrian strata in the studied area was predicted by the TOC content and preservation conditions.

Complexity and Heterogeneity Evaluation of Pore Structures in the Deep Marine Shale Reservoirs of the Longmaxi Formation, China

The structural evolution and sedimentary differentiation of the Sichuan Basin in China are complex, with intricate reservoir pore structures that significantly impact shale gas production. This study examines the complexity and heterogeneity of the microscopic pore structures in the deep marine shale reservoir in the Longmaxi Formation. Pore structure characterization techniques are used to compare deep and shallow–medium marine shales, and siliceous and silty shales. The results reveal the factors influencing pore structure and their impact on exploration and development. The key points are as follows: (1) The pore structure of deep siliceous shale is the most complex due to its diverse range of pore development patterns, pore types, and sizes. (2) The box dimension of full pore size is about 1.52 for deep marine shale and 1.46 for shallow–medium shale. Organic matter (OM) content, the degree of pore development, and inorganic mineral content all correlate positively with the complexity of the pore structure in deep marine shale, which affects the formation of high-quality reservoirs. (3) Lateral heterogeneity of pore structures shows strong regional variations in the study area. Heterogeneity is more pronounced in the deep marine shale than in the medium and shallow shale formations. OM mesopores significantly influence the overall heterogeneity of the shale pore system. The deep marine shale reservoir is situated in an area with strong regional variations. The pore structure of high-quality reservoirs is more complex than those of shallow–medium marine shales, displaying notable heterogeneity. Pore structures with fractal dimension values close to that of the shallow–medium formations (box dimensions within 1.5) offer promising targets for the exploration and development of deep marine shale gas.

Lithofacies influence characteristics on typical shale pore structure

Clarifying the three-dimensional pore throat structure characteristics of shale is the foundation for efficient development of shale oil and gas. In this paper, firstly, by using FIB-SEM high-tech characterization technology, three-dimensional quantitative characterization of shale pore-throat structures under different lithological conditions was carried out. Secondly, reconstruct through binary images to establish a three-dimensional pore-throat structure model. Thirdly, the coupling mechanism of “pore distribution, form factor, coordination number, throat diameter” is quantitatively clarified. Results show that: (a). For six shale samples, the volume fraction is mostly concentrated in the range of pore diameter greater than 20 nm and less than 300 nm. When the pore diameter is greater than 300 nm, the proportion of volume fraction is lower. (b). For six shale samples, the pore quantity distribution is mostly concentrated in the range of pore shape factor greater than 0.04 and less than 0.07. When the pore diameter is less than 0.04 or greater than 0.07, the pore quantity distribution is lower. (c). For six shale samples, the pore volume distribution is mostly concentrated in the range of coordination number greater than 1 and less than 4. When the pore diameter is less than 1 or greater than 4, the pore volume distribution is lower. (d). For six shale samples, the throat volume distribution is mostly concentrated in the range of throat diameter greater than 8 nm and less than 120 nm. When the throat diameter is less than 8 nm or greater than 120 nm, the throat volume distribution is lower. The pore structure of shale is very complex, mainly manifested by a variety of pore types.

Logging evaluation of pore structure and reservoir quality in shale oil reservoir: The Fengcheng Formation in Mahu Sag, Junggar Basin, China

The Permian Fengcheng Formation in the Mahu Sag of the Junggar Basin is characterized by frequent changes of mineral compositions and lamina structure. The alkali lacustrine shale reservoir shows strong heterogeneity and anisotropy, it is particularly important to clarify the relationship between pore structure and reservoir quality. The pore characteristics were investigated by using thin sections, Scanning Electron Microscope (SEM), and Nuclear Magnetic Resonance (NMR) analyses. The pore types are mainly composed of inorganic pores, organic pores, and microfractures. The storage space is dominated by inorganic pores and microfractures. The pore structure was divided into four types by NMR parameters including T2 spectral morphology, T2gm, total porosity, and movable fluid porosity. Combined with core NMR experiments and two-dimensional (2D) NMR logs, 21 ms was adopted as the T2cutoff value to represent the demarcation between movable and bound fluids. From Type I to Type IV, the energy clusters reflect the movable fluids including movable oil and movable water gradually decreasing in the upper right corner. The energy clusters reflect the bound fluids including clay-bound water and bitumen gradually increasing in the lower left corner in the T1-T2 map. The results show that the heterogeneity of mineral compositions and lamina structures are the key factors directly leading to the complexity and distribution of pore structure. Quartz with strong compaction resistance helps keep a large number of primary interparticle pores, and feldspar dissolution pores caused by organic acids are present. Dolomite intercrystalline pores and dissolution pores provide a large amount of storage space for the shale, while the cementation of calcite reduces pore spaces. The increase of felsic mineral content is conducive to improving the pore structure and oil-bearing potential of oil shale reservoir, while clay minerals and calcite are contrary. There are abundant primary interparticle pores and dissolution pores in the layered siliceous (felsic) shales, and they consist of the upper sweet spot in the Fengcheng Formation. The longitudinal time (T1) and transverse time (T2) spectra are bimodal with high total porosity and movable oil content, reflecting high reservoir quality and oil-bearing property. Laminated dolomite shales contain dolomite intercrystalline pores and dissolution pores, and they consist of the lower sweet spot in the Fengcheng Formation. The results above provide a new perspective on the evaluation of pore structure and reservoir quality of shales in the context of an alkaline lake.

Characterizing multi-scale shale pore structure based on multi-experimental imaging and machine learning

An accurate and comprehensive understanding of shale pore structure is fundamental and critical for accurate reserves evaluation and efficient hydrocarbon development. Thus, by taking the shale of Paleogene Eocene Shahejie Formation in the Jiyang Depression, Bohai Bay Basin, as an example, the 2D and 3D multi-resolution images of the shale microstructure are obtained by multiple imaging technologies, including X-ray computed tomography, large-field scanning electron microscopy, scanning electron microscopy and focused ion beam scanning electron microscopy. By integrating image processing and machine learning algorithms, the shale pore structure is characterized at a single scale and multi scales. The results are obtained as follows. First, the shale pore space in the study area is mainly composed of microfractures, inorganic pores, organic matters and organic pores, and exclusively shows multi-scale characteristics. Second, there are various types of inorganic pores, and abundant dissolution pores; organic matters are distributed as strips and patches, and no organic pores are found in some organic matters. Third, pores with radius less than 20 nm account for 25%, those with radius between 20 and 50 nm account for 19%, those with radius between 50 and 100 nm account for 29%, those with radius between 100 and 500 nm account for 14%, those with radius between 500 nm and 20 μm account for 11%, and those with radius between 20 and 50 μm account for 2%. Fourth, the organic pores are less connected than the inorganic pores. The connectivity between organic pores and inorganic pores plays a crucial role in hydrocarbon migration, and microfractures control fluid flow channels. Fifth, pores with radius less than 50 nm are dominantly organic pores, those with radius between 50 and 500 nm are mainly organic and inorganic pores, and microfractures mainly contribute to the pores with radius more than 500 nm. It is concluded that a single imaging experiment cannot accurately and comprehensively reveal the multi-scale micro pore structure of a shale reservoir. Through integration of multiple imaging technologies and machine learning algorithms, the shale pore structure can be recognized and characterized at both single scale and multi scales. The proposed new method provides accurate and comprehensive information of multi-scale pore structures.

Multicomponent digital core construction and three-dimensional micro-pore structure characterization of shale

The components and pore structure of shale are complex due to the heterogeneous distribution of organic matter and the complex distributions of the minerals. The digital core, possessing the advantages of being economical and reusable, can be widely used to directly characterize the three dimensional (3D) micro-pore structure and to numerically simulate its physical properties. During construction of a digital shale core, it is a challenge to solve the multicomponent segmentation for the digital shale core, the contradiction between the sample size and image resolution, and the identification of the pore types in the 3D pore space. Therefore, an automatic workflow based on the gray gradient-maximum entropy-3D morphology was developed. The gray gradient-maximum entropy algorithm was used to segment each sub-image of focused ion beam scanning electron microscope images to generate segmented images. On this basis, the pore size distribution was optimized via 3D morphological erosion. Based on the concept of pore clusters, the organic and inorganic pores were identified using the 3D morphological method for the first time. The construction of a multicomponent digital shale core was realized. The 3D micro-pore structure of the organic and inorganic pores was characterized by pore connectivity, heterogeneity, and pore size distribution. The accuracy of the proposed method was verified using low-temperature N2 adsorption experiment data. The results of this study provide new insight into the multicomponent digital shale core construction and lay the foundation for the characterization of the petrophysical properties and micro-/nano-scale fluid flow simulations of shale.

Geological Characteristics of Shale Reservoir of Pingdiquan Formation in Huoshaoshan Area, Junggar Basin

Unconventional oil and gas, represented by shale gas and shale oil, have occupied an important position in global energy. The rapid growth of shale gas and shale oil production shows great potential for the exploration and development of shale resources. Junggar basin, the main oil-bearing basin in China, is rich in oil and gas resources, so it is of great practical significance to carry out systematic research on the geological characteristics of shale reservoirs in this region. To this end, this paper designates the shale reservoir of Pingdiquan Formation in Huoshaoshan area of the Jungar Basin as the research object, carries out a geological survey in that area, analyzes reservoir forming conditions using the geological interpretation method, analyzes different local trap reservoir types and their main control factors by dissecting the explored reservoir, optimizes and evaluates favorable traps using the source, fault, facies and circle coupling analysis method, establishes single good identification standard of sedimentary microfacies, and carries out well-connected sedimentary microfacies analysis. Using geochemical methods, such as rock pyrolysis, maceral analysis, vitrinite reflectance, kerogen carbon isotope, saturated hydrocarbon chromatography, etc., the abundance and types of organic matter of shale in different intervals are analyzed and the geological characteristics of shale reservoirs are evaluated. This paper aims to analyze the oil and gas content of the shale reservoir in Pingdiquan Formation in the Junggar Basin to provide reliable reservoir evaluation and guide better development of shale oil and gas resources in the future. The innovative expenditure of this paper lies in conducting the research from two aspects: the analysis of the main controlling factors of reservoir formation from the structural point of view and the analysis of the pore structure and geochemical characteristics of shale from the core experiment point of view, and also the classification of organic matter, so as to provide a basis for finding favorable traps. The results show that the shale sedimentary system in the study area is a small fluvial delta, which belongs to a compression structure, with developed NNE-oriented structural belts and faults; the structural form is a short-axis anticline as a whole, forming a structural coil closure at −900 m, with a trap area of 50 km2 and a closure height of 180 m. According to the geological interpretation method, 19 faults of all levels were found in the area and the vertical migration conditions of oil and gas were good. Pingdiquan Formation was oil-bearing, with many vertical oil-bearing strata and strong horizontal independence of the reservoir. The sedimentary thickness of the Permian Pingdiquan Formation in the study area is 300~1200 m and the oil-bearing strata are divided into 3 oil-bearing formations, 9 sublayers, and 22 monolayers from top to bottom. The abundance of organic matter in different strata is generally high, with an average total organic carbon content of 3.53%, an average hydrocarbon generation potential of 18.1 mg/g, an average chloroform asphalt content of 0.57%, and an average total hydrocarbon content of 3011 μg/g, all of which belong to the shale standard, especially Ping-2. The organic matter in different layers belongs to types I-II1, and the organic matter types are I-II1, I-II2, and II1-II2, respectively. The average carbon isotope of shale kerogen is −2.4%, which belongs to type II2 kerogen.

Matrix Compressibility and Its Controlling Factors of the Marine Shale Gas Reservoir: A Case Study of the Ning228 Well in the Southwest Sichuan Basin, China

Exploring the compressibility of the deeply buried marine shale matrix and its controlling factors can help achieve efficient petroleum production. Taking ten sets of deeply buried marine shale core samples from Ning228 wells in the Yanjin area as an example, the matrix compressibility and pore characteristics of deeply buried marine shale reservoirs were investigated by applying mercury intrusion porosimetry (MIP) and nitrogen adsorption/desorption isotherms at a low temperature of 77 K. Mathematical models (based on MIP and nitrogen adsorption/desorption isotherms) were established to analyze the effects of TOC, mineral components, and pore structure on matrix compressibility. The relationship between the compressibility coefficient and the brittleness index was also established. The results show that the compressibility of the shale matrix is significant when the mercury injection pressure ranges from 8.66 to 37 MPa. For deeply buried marine shale, the matrix compressibility is in the range of 0.23 × 10−4–22.03 × 10−4 MPa−1. The influence of TOC and minerals on matrix compressibility is mainly reflected in the control effect of pore structure. High TOC content decreases the overall shale elastic modulus, and high clay mineral content enhances shale stress sensitivity, resulting in a significant matrix compressibility effect. For the effect of pore structure on compressibility, the pore content in shale has a positive effect on matrix compressibility. In addition, the pore-specific surface area is critical to the effective variation of shale matrix compressibility, indicating that the complexity of the shale pore structure is a key factor affecting matrix compressibility.

Pore Structure Characterizations of Shale Oil Reservoirs with Heat Treatment: A Case Study from Dongying Sag, Bohai Bay Basin, China.

Heat treatment plays a significant role in determining the petrophysical properties of shale reservoirs; however, the existing studies on the evolution of pore structures are still insufficient. This study conducts a series of tests, including Rock-Eval, low-temperature nitrogen adsorption-desorption, nuclear magnetic resonance (NMR) T2, and T1-T2 tests on samples from Shahejie Formation, Dongying Sag, Bohai Bay Basin. The tests aim to determine the changes in the shale pore structures under increasing heat treatments (ranging from 110 to 500 °C) and identify the factors that control pore structures. The results show that the gradual decomposition of organic matter leads to an eventual decrease in the total organic carbon (TOC) content. The decrease in TOC is more prominent when the temperature exceeds 300 °C. For shales with lower TOC contents (<2%), the Brunauer-Emmett-Teller specific surface area (BET SSA) first decreases, then increases, but eventually decreases again. However, the average pore diameter demonstrates an opposite trend when the temperature increases. In contrast, for organic-rich shales (TOC > 2%), the BET SSA increases at temperatures above 200 °C. The similarity between the D1 values implies that the complexity and heterogeneity of shale pore surface only undergo minor changes during heat treatment. Porosity shows an increasing trend, and the higher the contents of clay minerals and organic matter in shales are, the greater the change in porosity is. The NMR T2 spectra suggest that micropores (<0.1 μm) in shales first decrease and then increase, whereas the contents of meso- (0.1-1 μm) and macropores (>1 μm) increase, corresponding to the increase in free shale oil. Moreover, shale pore structures are primarily controlled by clay minerals and organic matter contents during heat treatments, with higher contents resulting in better pore structures. Overall, this study contributes to detailing the shale pore structure characteristics during the in situ conversion process (ICP).

Evolution of Pore Structure and Methane Adsorption in Lower Silurian Longmaxi Shale: Implications for Uplifted Shale Gas Reservoirs

Evolution of Pore Structure and Methane Adsorption in Lower Silurian Longmaxi Shale: Implications for Uplifted Shale Gas Reservoirs

How pore structure evolves in shale gas extraction: A new fractal model

The reservoir can be divided into four components with different properties: inorganic matrix, hydraulic fracture, natural fracture and kerogen according to the internal structure characteristics and the natural gas migration mode after hydraulic fracturing. Previous studies usually focus on the relationship between reservoir porosity and permeability, but ignore the influence of reservoir microstructure on gas production. The microstructure of different reservoir components can be described by corresponding fractal dimensions. The structure of fractures can be characterized by fractal dimension of fractures and the fractal dimension of pores can characterize the pore structure of inorganic matrix. Considering the complexity of mass transfer between components and structural deformation, in order to describe the evolution of reservoir microstructure and the influence of various factors on gas production, a fully coupled multi-scale fractal model is established. To verify that the model is reliable, the simulation results contrast with the conclusions of field tests. The effects of adsorption parameters, initial diffusion coefficient and compressibility coefficient on gas production and pore structure evolution were studied. The results show that:(1) when the adsorption constant decreases, the variation of the fractal dimension of pore structure becomes more obvious, and the shale reservoir's gas production and pore structure are most sensitive to the volume constant; (2) the deformation of pore structure increases with the increase of effective diffusion coefficient; (3) the change of compressibility of a single medium only has a major impact on the evolution of its own structure.

Multiscale pore structural alteration in gas shale by supercritical water stimulation

Hydraulic fracturing can induce high conductive fracture networks to stimulate shale gas well production. Large amounts of fracturing fluid generally retained in shale matrix after hydraulic fracturing will limit the shale gas well production. Reusing retained fracturing fluid by in-situ transformed into supercritical water (SCW) via formation heat treatment (FHT) is a state-of-the-art method to improve the shale gas well production by further altering shale multiscale pore structure. In this study, the changes in shale multiscale pore structure was visually and quantitatively characterized. The pore volume with a size range of 2 nm–5000 nm increased significantly. Inducing intragranular dissolution pores, pyrite dissolution pores, interparticle dissolution pores, and hydrothermal fractures stimulated the multiscale pore structure alteration during supercritical water stimulation (SCWS). Additionally, the advantage of SCWS in altering shale pore structure was systematically summarized, including further extend the hydraulic fracturing stimulation scale, enhancing multiscale shale gas flow capacity and ultimately improving well production. This work sheds light on the influence of supercritical water stimulation on the pore structure evolution in shale matrix, which is expected to be an innovative method for increasing the estimated ultimate recovery of a shale gas reservoir.

Siliceous Origin of the Cambrian Qiongzhusi Formation Shale in the Middle Part of the Upper Yangtze Platform: Significance of Organic Matter Enrichment.

The early Cambrian Qiongzhusi Formation shale is rich in organic matter and is a high-quality marine Source rock. However, the origin of Qiongzhusi Formation siliceous rocks is unknown, and the role of siliceous rocks in the process of organic matter enrichment or preservation is also lacking. This study combines thin section, scanning electron microscopy, SEM/EDS, major and trace element analysis, and N2 adsorption experiments to analyze and evaluate the shale of the Qiongzhusi Formation in the central region of the Sichuan Basin. The quartz types in the shale of the Qiongzhusi Formation are divided into four types, namely, bioclastic siliceous rocks, terrestrial detrital quartz, siliceous microcrystalline quartz particles, and microcrystalline quartz aggregates; at the same time, according to petrographic and geochemical parameters, the content of authigenic quartz in Qiongzhusi Formation shale decreases from top to bottom, and terrigenous detrital quartz tends to increase, and biogenic silicon accounts for the majority of authigenic quartz components; autogenous quartz has a positive impact on the pore structure of shale, providing sufficient pore space for the development of organic pores and protecting the internal pore network by forming intergranular pores as rigid frameworks. At the same time, it plays a crucial role in the enrichment and preservation of organic matter.

Pore structure evolution of Qingshankou shale (kerogen type I) during artificial maturation via hydrous and anhydrous pyrolysis: Experimental study and intelligent modeling

In this study, alterations in the pore structure of the Qingshankou shale during hydrous and anhydrous pyrolysis (HP and AHP) over wide ranges of temperature (300–450 °C) were studied to elucidate the role of water. Mineralogy of the original shale sample along with geochemical properties and pore structure after each step of artificial thermal maturation were analyzed using X-ray diffraction (XRD), Rock-Eval pyrolysis, and N2 adsorption, respectively. Complexity of pore structure was assessed via fractal dimension analysis followed by delineating different pore families in the samples' PSD curves. Next, four common artificial neural networks (ANNs) models were implemented along with Bayesian regularization (BR) and Levenberg-Marquardt (LM) optimization algorithms to model the N2 adsorption/desorption volume as thermal maturity progressed. Results showed that all samples represent Type IV hysteresis loop while the amount of N2 adsorption during HP was much higher than that of the AHP revealing the importance of water. Overall, the complexity of AHP samples’ pore structure was less than that of the HP since the count of pores with smaller pore width was reduced more during thermal progression. Deconvolution analysis showed that the original sample has eight pore families (7 in mesopore and 1 in the macropore range), while pore families with larger mean pore width were formed and expanded and pore families with smaller mean pore width were eliminated as thermal maturation progressed in both HP and AHP. Moreover, the average absolute percent relative error (AAPRE) of 3.74% for the entire data inferred that generalized regression neural network (GRNN) model was superior for the estimation of N2 volume adsorbed and desorbed. Finally, sensitivity analysis revealed that the relative pressure and pyrolysis method (AHP or HP) respectively had the strongest linear and non-linear relationships with the N2 adsorption/desorption volume. Collectively, this case confirmed the role that water plays in the evolution of pore structures throughout thermal maturation, which could be even more significant than temperature.

Heat-Induced Pore Structure Evolution in the Triassic Chang 7 Shale, Ordos Basin, China: Experimental Simulation of In Situ Conversion Process

The reservoir properties of low–medium-maturity shale undergo complex changes during the in situ conversion process (ICP). The experiments were performed at high temperature (up to 450 °C), high pressure (30 MPa), and a low heating rate (0.4 °C/h) on low–medium-maturity shale samples of the Chang 7 Member shale in the southern Ordos Basin. The changes in the shale composition, pore structure, and reservoir properties during the ICP were quantitatively characterized by X-ray diffraction (XRD), microscopic observation, vitrinite reflectance (Ro), scanning electron microscopy (SEM), and reservoir physical property measurements. The results showed that a sharp change occurred in mineral and maceral composition, pore structure, porosity, and permeability at a temperature threshold of 350 °C. In the case of a temperature &gt; 350 °C, pyrite, K-feldspar, ankerite, and siderite were almost completely decomposed, and organic matter (OM) was cracked into large quantities of oil and gas. Furthermore, a three-scale millimeter–micrometer–nanometer pore–fracture network was formed along the shale bedding, between OM and mineral particles and within OM, respectively. During the ICP, porosity and permeability showed a substantial improvement, with porosity increasing by approximately 10-times and permeability by 2- to 4-orders of magnitude. Kerogen pyrolysis, clay–mineral transformation, unstable mineral dissolution, and thermal stress were the main mechanisms for the substantial improvement in the reservoir’s physical properties. This study is expected to provide a basis for formulating a heating procedure and constructing a numerical model of reservoir properties for the ICP field pilot in the Chang 7 shale of the Ordos Basin.

Pore Structure and Fluid Evaluation of Deep Organic-Rich Marine Shale: A Case Study from Wufeng–Longmaxi Formation of Southern Sichuan Basin

Deeply buried (&gt;3500 m) marine shale has become a focus point for the future exploration and exploitation of shale hydrocarbon in China. Low-temperature nitrogen adsorption (LTNA), scanning electron microscopy (SEM), nuclear magnetic resonance (NMR), and other experiments were combined to characterize the pore structure and fluid division in deep-marine shale of the southern Sichuan Basin in this study. The results suggest that the deep-marine shale had a relatively developed nanopore network, especially with honeycomb organic pores. These organic pores were largely macropores with good connectivity in three-dimensional space and constituted the major reservoir space of the deep-marine shale gas. Microfractures were predominantly clay-mineral-related fractures, and the development degree of microfractures connected with organic pores was low, which contributed to the preservation of organic pores. Within the deep-marine shale interval, the pore volumes of Section 1 and Section 3 were higher. Pore volume was predominantly contributed by pores above 10 nm, where macropores accounted for a large proportion. Based on a combination of high-speed centrifugation and gradient temperature drying, the pore fluid of deep-marine shale reservoirs was quantitatively classified into four types: clay-bound fluid, capillary-bound fluid, free-flowing fluid, and closed-pore fluid. The clay-bound fluid existed in pores of less than 4.25 nm, which cannot be exploited. Quantitative division of the shale pore system could be realized by using the pore space differences of different types of fluids.

Contribution of Various Shale Components to Pore System: Insights from Attributes Analysis

Shale pore systems are the result of the geological evolution of different matrix assemblages, and the composition of gas shale is considered to affect the pore systems in shale reservoirs. This study aimed to investigate the impact of both organic and inorganic constituents on the shale pore system, including specific surface area (SSA) and pore volume in Wufeng–Longmaxi Shale. Multiple linear regression (MLR) was employed to examine the contributions of different components to shale pore structure. The pore structure parameters, including pore SSA and pore volume, were obtained by gas adsorption experiments in 32 Wufeng–Longmaxi Shale (Late Ordovician–Early Silurian) samples. Both pore SSA and pore volume were calculated by the density functional theory (DFT) model on shale samples, and the pore types were determined by high-resolution field emission scanning electron microscopy (FE-SEM). The results of the X-ray diffractometer (XRD) analysis indicate that the Wufeng–Longmaxi Shale is dominated by quartz, clays, carbonates, feldspar, pyrite, and organic matter. Four models were made using SPSS software, all of which showed significant correlation between shale pore size and organic matter (OM) and clays. The content of organic matter played the biggest role in determining the size and structure of the pores. Although the content of quartz is the highest and serves as a rigid skeleton in shale reservoirs, it has complicated effects on the pore structure. In this study, most of the quartz is biogenetic and part of it is transformed from clays in deep shale. Therefore, these two parts of quartz are, respectively, related to organic matter and clays. In essence, the pores related to these two parts of quartz should be attributed to organic matter and clays, which also support the conclusion of the MLR models.