Low-pressure N2 Adsorption Research Articles

Experimental study on pore structure evolution of thermally treated shales: implications for CO2 storage in underground thermally treated shale horizons

Extracting gas from unconventional shale reservoirs with low permeability is challenging. To overcome this, hydraulic fracturing (HF) is employed. Despite enhancing shale gas production, HF has drawbacks like groundwater pollution and induced earthquakes. Such issues highlight the need for ongoing exploration of novel shale gas extraction methods such as in situ heating through combustion or pyrolysis to mitigate operational and environmental concerns. In this study, thermally immature shales of contrasting organic richness from Rajmahal Basin of India were heated to different temperatures (pyrolysis at 350, 500 and 650 °C) to assess the temperature protocols necessary for hydrocarbon liberation and investigate the evolution of pore structural facets with implications for CO2 sequestration in underground thermally treated shale horizons. Our results from low-pressure N2 adsorption reveal reduced adsorption capacity in the shale splits treated at 350 and 500 ºC, which can be attributed to structural reworking of the organic matter within the samples leading to formation of complex pore structures that limits the access of nitrogen at low experimental temperatures. Consequently, for both the studied samples BET SSA decreased by ∼58% and 72% at 350 °C, and ∼67% and 68% at 500 °C, whereas average pore diameter increased by ∼45% and 91% at 350 °C, and ∼100% and 94% at 500 °C compared to their untreated counterparts. CO2 adsorption results, unlike N2, revealed a pronounced rise in micropore properties (surface area and volume) at 500 and 650 ºC (∼30%–35% and ∼41%–63%, respectively for both samples), contradicting the N2 adsorption outcomes. Scanning electron microscope (SEM) images complemented the findings, showing pore structures evolving from microcracks to collapsed pores with increasing thermal treatment. Analysis of the SEM images of both samples revealed a notable increase in average pore width (short axis): by ∼4 and 10 times at 350 °C, ∼5 and 12 times at 500 °C, and ∼10 and 28 times at 650 °C compared to the untreated samples. Rock-Eval analysis demonstrated the liberation of almost all pyrolyzable kerogen components in the shales heated to 650 °C. Additionally, the maximum micropore capacity, identified from CO2 gas adsorption analysis, indicated 650 °C as the ideal temperature for in situ conversion and CO2 sequestration. Nevertheless, project viability hinges on assessing other relevant aspects of shale gas development such as geomechanical stability and supercritical CO2 interactions in addition to thermal treatment.

Comprehensive evaluation of the organic-rich saline lacustrine shale in the Lucaogou Formation, Jimusar sag, Junggar Basin, NW China

To explore a comprehensive evaluation method for saline lacustrine shale, samples were collected from the shale strata of the Lucaogou Formation in the Jimusar Sag, Junggar Basin. Organic geochemical and mineralogical parameters were assessed through TOC evaluation, rock pyrolysis, and XRD. Quantitative analysis of pore structure was achieved using a combined low-pressure N2 adsorption and mercury intrusion. Optical microscopy and FE-SEM analyzed macerals and pore morphology, respectively, while 2D NMR identified varied hydrogen-containing components in the shale. The findings revealed predominance of inorganic pores in saline lacustrine shale strata, with a lower occurrence of organic pores. The saline lacustrine sediments were in the late stage of oil generation. The siltstone and type III3 carbonate felsic shale displayed an abundance of type II1 organic matter, low vitrinite and inertinite contents, high macroporous volumes and surface areas, and they possessed a high content and fluidity of free oil, despite being lower maturity (0.85%<Ro<1.1%), making them attractive for shale oil exploration. Finally, we propose a comprehensive evaluation method for saline lacustrine shale strata considering free oil content (26% contribution), pore structure (23% contribution), maturity (16% contribution), macerals (13% contribution), free oil mobility (12% contribution), and organic matter type (10% contribution), encompassing various lithofacies.

Evolution of kerogen structure during the carbonization stage

Currently, certain unconventional gas is mainly extracted from high-maturity shale reservoirs, but limited attention has been given to the evolution of kerogen structure subsequent to the overmature, gas generative stage, corresponding to metagenesis and is termed the carbonization stage. In this study, we performed heating treatment on overmature kerogen samples to obtain samples in the carbonization stage and then conducted Raman, thermogravimetric-mass spectrometric analysis (TG-MS), X ray diffraction (XRD), and high resolution transmission electron microscope (HRTEM) experiments on these samples to investigate the changes in kerogen structure. Low pressure N2 and CO2 adsorption experiments also were performed to investigate the changes in pore structure. The results show that as the heat treatment temperature is raised to 1000 °C, the ID/IG ratio (D band intensity to G band intensity) experiences an increase, reaching 1.12. Additionally, the full width at half maximum (FWHM) of 002 peak consistently remains above 3.8°. This suggests that these samples were matured to an early meta-anthracite (meta-kerogen) stage, which is significantly distant from the graphite stage. During this particular stage, the most obvious changes in molecular structure are the enlargement of aromatic clusters and the decrease in hydrogen atoms, and thus, H2 rather than methane is produced, as revealed by the results of TC-MS experiment. Following an initial increase, the pore volume and surface area of kerogen samples decrease gradually, reaching their maximum values at 700 °C. Kerogen subjected to a heating temperature of 1000 °C exhibits a greater pore volume in comparison to the initial overmature kerogen. Thus, this observation provides evidence that shale kerogen in carbonization stage, which is typically lying at significant depths, holds promise as a viable reservoir for shale gas extraction.

Pore systems and their correlation with oil enrichment in various lithofacies of saline lacustrine shale strata

The potential of China's saline lacustrine shale oil resources is enormous. Currently, the storage space of saline lacustrine shale oil remains unclear, posing significant challenges for commercial development. In this study, we selected the samples from the typical saline lacustrine shale strata of the Lucaogou Formation, Jimusar Sag, Junggar Basin and investigated the pore systems and their relationship with oil content S1 of different lithofacies. The pore structures were quantified by using the combination of low-pressure N2 adsorption and mercury intrusion. TOC assessment, rock pyrolysis, and XRD were utilized for characterizing the organic geochemical and mineralogical parameters. The results showed that the organic matter comprising type III mainly appears in the clay-enriched lithofacies (types I2, II1 and III2), while the organic matter types I, II1 and II2 can be found in other lithofacies. Regarding the nine lithofacies, siltstone has the highest oil content S1, followed by the felsic-enriched lithofacies (types III3 and III1). The enrichment of oil in siltstone, carbonate rocks, and felsic-enriched lithofacies (types III3 and III1) is primarily attributed to macropores. Conversely, in clay-enriched lithofacies (types I2, II1 and III2), the oil content S1 is attributed to both the mesopore fractal dimensions (D1 and D2) and the TOC content. Moreover, the higher the complexity of the mesoporous structure (D2) and the larger the macropore surface area in clayey carbonate felsic shale (II3), the greater the oil content S1. It is further observed that, macropores with size range between approximately 60 nm and 3000 nm are abundant in siltstone and felsic mineral-enriched lithofacies (i.e., carbonate felsic shale III3 and felsic shale III1). Furthermore, the siltstone shows the widest oil-rich macropore size range (range of 70–1000 nm), followed by felsic shale (III1) (range of 150–1000) and carbonate felsic shale (III3) (range of 100–110 nm). Siltstones and felsic-enriched shales are optimal for exploiting saline lacustrine shale deposits.

Mechanism of water-induced alterations to nanoscale pores: Implications from anhydrous versus hydrous pyrolysis

In this study, shale samples from the Chang7 Member of Triassic Yanchang Formation in Ordos Basin, China were used to conduct artificially induced thermal maturity experiments from 250 °C to 450 °C for 72 h. The role of water in organic matter (OM) conversion and nanoscale porosity alterations were observed and discussed comprehensively by Rock-Eval pyrolysis, low pressure N2/CO2 adsorption, Fourier transform infrared spectroscopy (FTIR) and water-soluble organic acids (WSOAs) experiments. Results show that Rock-Eval pyrolysis parameters (Tmax, S1, and S2), TOC content, WSOAs and pore volume (PV) show slight changes below 350 °C while these parameters were considerably altered above 400 °C under two different pyrolysis conditions (anhydrous and hydrous), indicating that after 400 °C, the OM conversion and bitumen cracking will accelerate. In comparison to anhydrous pyrolysis, hydrous pyrolysis always has smaller Tmax, implying that water could inhibit OM thermal progression. Moreover, S1 of hydrous pyrolysis is approximately two times higher than that of anhydrous pyrolysis, which originates from water providing an exogenous source of hydrogen to generate excessive volumes of hydrocarbons, enhancing the conversion rate of OM. The WSOAs are 2 to 4 times greater under hydrous pyrolysis than anhydrous pyrolysis, denoting that the presence of water could improve the yield of organic acids via inhibiting the polycondensation of oxygen-containing functional groups and oxidizing organic components by hydroxyl radicals. Moreover, below 350 °C, pyrolysis shale residues exhibit a slightly smaller PV in hydrous pyrolysis, mainly due to the infilling effect of bitumen. However, exceeding 400 °C, PV that was obtained from low pressure N2 adsorption under hydrous pyrolysis conditions is found to be two times as large as the value under anhydrous pyrolysis conditions, which is attributed to the net-PV increase reactions such as thermal cracking, and the dissolution of organic acids. Furthermore, in anhydrous pyrolysis, the polycondensation of oxygen-containing functional groups and the carbon-carbon cross linking could be considered as the two main reaction pathways to release the sources of hydrogen. Collectively, the presence of water is significant for hydrocarbon generation and porosity evolution during thermal progression of OM at various stages.

Changes in physical and chemical structure and Full-stage oxidation characteristics of coal caused by igneous intrusion

The influence of igneous intrusion on entire coal oxidation and its mechanism remains unclear, impacting mining operations. To investigate spontaneous combustion characteristics, this study analyzed the composition and physicochemical structure of igneous intrusion coal (II coal) using various experimental methods: low-temperature oxidation, low-pressure N2 adsorption, XPS, FTIR, and TGA-DSC. Results show that II coal has developed pores favourable for coal-oxygen interaction, but increased moisture and ash relative content, and decreased volatile and reactive functional groups, implying reduced low-temperature oxidation and combustion reactivity. The decrease in CO and CO2 production and the increase in XPT and apparent activation energy confirm this result. Notably, II coal releases more CO and CO2 below 400 K and the gases are lower than raw coal after 400 K, suggesting native CO and CO2 exist in coal and abundant native active sites which are rapidly consumed during this stage. These findings provide insights into predicting spontaneous combustion in mines extracting coal seams affected by igneous intrusion.

Expulsion of small molecule hydrocarbons and expansion of nanopores effect in tectonically deformed coal evolution

This work aimed to investigate the impact of the evolution of small molecular structures during the deformation of coal on the constraints imposed on nanoscale pores and adsorption behaviors. Both undeformed and tectonically deformed coal (TDC) from the Huaibei mining area in China were collected for analysis. The pyridine was employed for the extraction of small molecules from coal, which was further complemented by Fourier-transform infrared spectroscopy (FTIR) and low-pressure CO2 and N2 adsorption experiments (LP-CO2/N2AD). The study yielded the following results: (1) Intense tectonic stresses facilitate the removal and recombination of small molecular side chains within the basic structural units (BSU) of coal. As deformation occurs, hydroxyl groups, aliphatic hydrocarbons, C=O, C=C, aromatic hydrocarbons, and 'C' structures tend to accumulate, resulting in an enhanced extraction rate. (2) The deformation process of the coal demonstrates a significant pore-expansion effect, with the most substantial increase observed in micropores (surface area increased by over 70 %), followed by mesopores and macropores. This enlargement facilitates the aggregation of small molecules and gas storage. (3) Intense deformation stages involving shear slip, ductile deformation, and maceral fragmentation result in small molecular fractures and an increased number of micropores. The removal and recombination of I, DOC, and CH2/CH3 within BSUs lead to the formation of larger interconnected pores accompanied by the aggregation of hydroxyl groups (OH–), C=O, C=C, aliphatic hydrocarbons, and 'C' structures. (4) The adsorption capacity of residual coal is lower than that of the raw coal before extraction, indicating that small molecular structures contribute to increased adsorption. This likely plays a significant role in the higher gas content observed in structurally deformed coal. The removal of small molecular structures effectively diminishes the adsorption capacity, providing novel perspectives for coalbed methane development and gas extraction in TDC areas.

Significance of particle size and lithotype on adsorption equilibrium in low pressure N2 and CO2 adsorption of coal: Implications for abnormal phenomenon of adsorption in N2 adsorption of semianthracite

Low pressure N2 and CO2 adsorption was conducted on different lithotypes (vitrain and clarain) with ten different particle sizes ranging from 2.8-2.0 mm to 0.045–0.020 mm of semianthracite (Ro, max = 2.06%) having the abnormal phenomenon of adsorption in N2 adsorption. The effects of particle size and lithotype on adsorption equilibrium in N2/CO2 adsorption and associated pore structure were systematically analyzed to explore the possible reason for the abnormal phenomenon of adsorption and propose the suitable particle size for N2/CO2 adsorption. Decreasing particle size in vitrain and clarain shortens the gas flow paths and removes the constrictions, which facilitates the complete adsorption equilibrium in CO2 adsorption and improves the degree of adsorption equilibrium in N2 adsorption. For different lithotypes with the same particle size, clarain achieves complete adsorption equilibrium easier and quicker in CO2 adsorption and has higher degree of adsorption equilibrium in N2 adsorption than vitrain. The abnormal phenomenon of adsorption in N2 adsorption is resulted from the combined effect of extremely low degree of adsorption equilibrium and elastic deformation of coal. The abnormal phenomenon of adsorption is more pronounced in vitrain than in clarain and gradually disappears with decreasing particle size in both vitrain and clarain. Particle sizes of <0.075 mm (>200 mesh) and <1.0 mm (>18 mesh) are recommended as the suitable particle sizes in N2 adsorption and CO2 adsorption to accurately characterize pore structure for the coals having the abnormal phenomenon of adsorption, respectively.

Experimental investigation and intelligent modeling of pore structure changes in type III kerogen-rich shale artificially matured by hydrous and anhydrous pyrolysis

The occurrence and enrichment of shale plays are highly controlled by pore characteristics of the formation. In this study, an immature sample rich in kerogen type III from the Damoguaihe formation, Hailar Basin in China is subjected to hydrous and anhydrous pyrolysis (HP and AHP) across an extensive temperature range (300–450 °C). Next, low-pressure N2 adsorption analysis was conducted on the pyrolyzate of each maturity stage to study the pore structures’ evolution during thermal maturity simulation. Moreover, deconvolution and fractal dimension analyses were implemented to study pore families and the complexity of pores within the shale samples. Finally, radial basis function (RBF) neural networks optimized by four evolutionary approaches were applied for modeling N2 adsorption data obtained from the HP and AHP samples. According to the results, the original shale sample and all pyrolyzates obtained with HP and AHP scenarios exhibited type IV isotherm with H3 hysteresis loops. As a whole, BET surface area, micro-, meso- and total pore volume of HP pyrolyzates were higher than AHP ones. The unheated shale sample had seven families containing three mesopore and four macropore groups. Although all pyrolyzates obtained from the pyrolysis had families with similar means, their pore volumes were entirely different, which proves that the pore structure of samples undergoes changes during thermal maturation and the presence of water can also enforce these changes. Both fractal dimensions showed a direct relationship with BET surface area and a negative correlation with the average pore diameter of shale samples. The RBF model optimized by differential evolution (DE) delivered a mean absolute percent relative error (MAPRE) value of 4.84% and determination coefficient (R2) of 0.9946 for the total data set, which outperforms other RBF models in predicting N2 adsorption/desorption tests of pyrolyzates. The outcome of sensitivity analysis suggested that the N2 adsorption/desorption behavior of the pyrolyzates was mostly affected by relative pressure and the pyrolysis type (HP or AHP). Ultimately, the results clearly revealed that the effect of water on the pores' alteration of shales with type III kerogen is greater than the effect of temperature or thermal maturity itself.

Pore structure characteristics and impact factors of laminated shale oil reservoir in Chang 73 sub-member of Ordos Basin, China

This research paper focuses on the laminated shale oil reservoir in the third sub-member of the seventh member of Yanchang Formation (Chang 73 sub-member) in the Ordos Basin. The study aims to comprehensively analyze the lithofacies type, micro qualitative and quantitative pore structure parameters, and the main controlling factors of the pore structure in laminated shale. The analysis involves various techniques, including a comprehensive analysis of TOC, rock-eval, X-ray diffraction, polarized light and fluorescence microscope observation, field emission scanning electron microscope observation, and low-pressure N2 adsorption analysis. Based on the sedimentation characteristics, geochemistry, and mineral composition differences, the Chang 73 laminated shale can be classified into three lithofacies types: tuffaceous-organic matter binary laminated shale, clayey-organic matter binary laminated shale, and felsic-clayey binary laminated shale. The pore network consists primarily of organic hydrocarbon generation pressurization fractures, clay mineral felsic intergranular composite pores, and felsic plasmid intergranular pore fracture systems. Mesopores are the most developed pore type. The pore volume and specific surface area increase in the order of “tuffaceous-organic matter”, “clayey-organic matter”, and “felsic-clay”, while the heterogeneity of the pore network gradually weakens, and the roughness of the pore surface enhances. The overall development of organic matter pores is limited, with organic matter-pyrite-clay mineral composite pores being the main components of micropores. The primary intergranular pore system, associated with rigid quartz particles, dominates the mesopores and macropores, and acts as the main framework of the entire pore network. The development of feldspar dissolution pores is limited and contributes minimally to the pore network.

Study of pore structure of shale formation for CO2 storage

Carbon Geosequestration is considered a trending research area as it helps in mitigating the greenhouse gas effects on the environment by controlling global temperature. Recently, geo sequestration is considered one of the alternative ways to store CO2 for long periods. The shale is considered as the most suitable geological formation for CO2 storage due to its high adsorption capacity, microfractures, etc. Adsorption capacity in shale formation is highly influenced by pore structure, mineral composition, geomechanical properties, pressure, depth, etc. The shale pore structure is mainly dominated by mesopores (2–50 nm) and micropores (less than 2 nm). Storage of CO2 in the pores matrix is generally studied by using low-pressure N2 and CO2 adsorption isotherms, FE-SEM, etc. These techniques help in identifying types of pores, and their sizes, morphology, etc. Evaluation of pore microstructures helps to estimate the CO2 storage capacity in the formations. The present article discusses the importance of pore size, pore diameter, and pore volume distribution in shale formation for CO2 storage. A detailed review is carried out to analyze the methods of CO2 storage.

Pore size estimation of indian coal through low-pressure N2 adsorption

The Low-pressure N2 sorption method was used to evaluate the effect of particle size on the characteristics of the pore structure of the coal sample. Crushing led to a change in the pore structure. New pores were also developed while pulverizing the coal. Samples with 250 µm size showed the maximum specific surface area and micro- and mesopore volume. The quantity of low-pressure N2 adsorption was maximum for 250 µm particle size. Mesopore constituted most of the pore systems in the tested coal samples. However, if the analysis is performed with a smaller particle size, there might be an error of overestimating the gas reserves in actual coal seam conditions. Hence, in this study, 250 µm is suggested to better estimate the pore characteristics.

Role of Pore Structure Parameters of Clay and Modified Clay Minerals on Their Hydrogen Adsorption at Low- and High-Pressure Conditions

Hydrogen can act as a potential alternative to fossil fuels; however, storage of this energy source is a challenge to overcome. Researchers have been concentrating on geological hydrogen storage in sandstones and shales. Gas in the latter porous rock is primarily stored in the adsorbed phase, to which inorganic minerals, like montmorillonite, illite, and kaolinite, contribute significantly. In this work, the adsorption of gaseous hydrogen on different clay and clay minerals has been studied experimentally at low-pressure–low-temperature (LPLT, 77 K) and high-pressure–high-temperature (HPHT, 313 K) conditions. Further, the pore characteristics of the selected clay samples have been analyzed using low-pressure N2 (77 K) and CO2 (273 K) adsorption. Scanning electron microscopy (SEM) images of the samples have been utilized to study their morphology, particle sizes, and pore structures. The role of pore structure parameters on hydrogen adsorption at LPLT and HPHT has been investigated. Through these investigations, it has been found that the specific surface area and micropore volume positively affect hydrogen adsorption and the average pore width affects it negatively. Further, the applicability of some well-known adsorption models, like Langmuir, Freundlich, Toth, and Sips, has been investigated. It has been found that the Langmuir model gives a poor fit in both experimental conditions. The Toth and Sips models are good at LPLT as well as HPHT conditions.

Effect of Sedimentary Facies Characteristics on Deep Shale Gas Desserts: A Case from the Longmaxi Formation, South Sichuan Basin, China

Shale gas is one of the hot spots of energy development. Due to the strong heterogeneity and low physical properties of shale gas reservoirs, and the complex influencing factors of pore development, it is necessary to conduct a comprehensive analysis of the control factors of high-quality reservoirs. The sedimentary characteristics, mineral composition, pore structure and controlling factors of high quality reservoir development are studied on the basis of thin section, scanning electron microscopy (SEM) and QEMSCAN analysis, X-ray diffraction (XRD), total organic carbon (TOC), Nano-CT scanning and Low-pressure N2 adsorption (N2GA) analysis on shale samples from the Longmaxi Formation in South Sichuan Basin. The results show the following: (1) According to lithology, sedimentary structure, organic carbon content and mineral composition, six sedimentary microfacies can be divided. (2) Organic matter pores are developed in organic-rich siliceous shale and organic-rich silty shale at the bottom of the first member of the Longmaxi formation, with average porosity of more than 5% and permeability of more than 2 × 10−3 μm2, which is conducive to the formation of high-quality shale gas reservoirs. (3) The contents of siliceous and TOC are positively correlated with porosity and specific surface area, while the contents of carbonate and clay minerals are negatively correlated with reservoir quality. (4) In the first member of the Longmaxi formation, the sedimentary water depth becomes shallower from bottom to top, and the sedimentary environment changes from a reduction to an oxidation environment. The contents of siliceous and organic matter decrease, while the contents of clay minerals and carbonate minerals show the opposite trend. The difference in sedimentary microfacies affects the distribution of mineral and organic matter and controls the heterogeneity of the shale reservoir.

Influence of premixed chlorine salt on the pore characteristics of cement-based hardened grout containing a large amount of bentonite

Moderate content of premixed chlorine salt could improve the fluidity and strength of cement-based grouts containing a large amount of bentonite, while its effect on pore structure is still unclear. In this study, pore characteristics were systematically described by low-field NMR combined with low-pressure CO2 and N2 adsorption. Pores were classified into five types according to their size to clarify the effect of chloride content, curing time, and chloride type (NaCl or CaCl2) on various pore volumes. This was further analyzed by the introduction of unit volume variation (U). Results show that the volume of inter gel pore (2–10 nm) and middle capillary pore (50–1000 nm) increases with the increase of chloride content while that of fine (10–50 nm) and large (>1000 nm) capillary pore decreases. The inter gel pore volume and fine capillary pore volume depend on C–S–H content and surfactant micelles number, respectively. The volume of middle and large capillary pores is mainly affected by the hydration product content. For intra sheet pores (<2 nm), their volumes show an inverted “N” shape with the increase of NaCl content and a “U” shape for CaCl2, which is mainly related to the ettringite dissolution and nano-SiO2 dispersion. The chloride content and curing time also have a large reduction effect on the U of intra sheet pores, fine and large capillary pores. Furthermore, CaCl2 contributes more than NaCl to the development of pore structure, especially for inter gel pores and middle capillary pores.

Shallow burial shale gas accumulation pattern of the Wufeng–Longmaxi Formations in the northern Guizhou area, western Yangtze platform

Although continuous breakthroughs of economic shale gas exploitation have been made globally within the middle–deep buried depth (∼1500–3500 m), the shallow–buried (less than 1500 m) shales are also widely distributed, showing excellent exploration prospects. However, the shale gas accumulation (SGA) pattern of the shallow burial shale remains unknown, limiting future shale gas exploration. To investigate the SGA pattern and the exploration potential of shale gas in shallow–buried shales, experiments such as X–Ray Diffractometer, N2 and CO2 adsorption, Focused Ion Beam Scanning Electron Microscopy (FIB-SEM), total organic carbon (TOC) content, gas chromatography–mass spectrometry, and field gas content test were carried out based on three wells penetrated the Wufeng–Longmaxi Formation with the buried depths of less than 700 m in the Northern Guizhou area, western Yangtze Platform. The geochemical and mineral records indicate that the organic matter is enriched as a result of global climate and regional tectonic activity, indicating the sufficient gas generation potential. The results of low pressure N2 and CO2 adsorption, as well as images of the FIB–SEM show that the mesopores are controlled by the organic matter, and the micropores, which are associated with minerals (primarily clays), can provide much more specific surface area and pore space in shallow–buried shales. Furthermore, carbonates with low porosity and permeability from the Songkan, Jiancaogou and Baota Formations, and the shale interval with low TOC values, weak brittleness, and low porosity, can serve as good roofs and floors for the SGA. Despite the fact that multi–stage tectonic movements resulted in the formation of faults and fractures, the good preservation, adequate gas storage space, and sufficient hydrocarbon generation potential contribute to the SGA in the shallow–buried shale.

Pore Structure and Its Controls of Shale in the Qingshankou Formation, Sanzhao Sag, Songliao Basin

The exploration and development of Gulong shale oil in the Songliao Basin has achieved a major breakthrough, with the result that a national shale oil demonstration area is being built. The shale in the Sanzhao Sag is abundant in organic matter and is an important replacement area. For this reason, it has recently become a focus for research and exploration. Compared with the Gulong Sag, the Qingshankou Formation in the Sanzhao Sag is relatively immature, and comparatively little is known about its pore structure. For this study, well ZY1, a key well in the Sanzhao Sag, was selected as the research object. Thin section observation, high-resolution field emission scanning electron microscopy, Modular Automated Processing Systemimaging, X-ray diffraction of whole rock and clay, TOC pyrolysis, and Low-pressure N2 adsorption were used to investigate the pore structure in the sag to determine the factors influencing pore development. The principal understandings are as follows: (1) The Qingshankou Formation in the Sanzhao Sag is predominantly clay shale, with a high content of clay minerals (32.8 to 70%) and TOC contents of 0.7 to 11%. These values indicate good hydrocarbon generation potential. (2) Interparticle pores, intraparticle pores, and organic matter pores are developed. Intergranular pores are the main type, mostly observed between granular minerals or between granular minerals and clays. Intraparticle pores are observed in pyrite mass and dissolved unstable minerals. Organic matter pores (OMP) occur in primary organic matter and migrate into solid bitumen. (3) The shale pores in the Sanzhao Sag are mainly H3-type slit pores, with specific surface areas of 5.4~22.9 m2/g and pore volumes of 0.03~0.07 cm3/g. Mesopores make the largest contribution to pore volume and specific surface area. Scanning electron microscope (MAPS) imaging shows that the pore size distribution of shale is mainly 20~30 nm and 100~200 nm and that large pores, especially pores of 100~200 nm and 1~2 μm, make the largest contribution to the facies. (4) The pore structure in the Sanzhao Sag is affected by mineral composition, abundance of organic matter, thermal evolution degree, and diagenesis. Organic-inorganic interactions influence and determine the pore structure characteristics of the Qingshankou Formation shale. This paper is intended to provide scientific guidance and technical support for evaluating the effectiveness of shale oil reservoirs and selecting sweet spots in the Sanzhao Sag.

Effect of Petroleum Generation and Retention on Nanopore Structure Change in Laminated and Massive Shales-Insights from Hydrous Pyrolysis of Lacustrine Source Rocks from the Permian Lucaogou Formation.

The lacustrine shale of the Middle Permian Lucaogou Formation in the Jimusar Sag is the principal prospective unconventional target in the Junggar Basin. The effect of petroleum generation and retention on nanopore structure change during thermal maturity in lacustrine shale is still unclear. In this study, two laminated and two massive shale samples from the Permian Lucaogou Formation were selected to study this change by closed hydrous pyrolysis. The pyrolysis temperatures were 295, 320, 345, 370, and 400 °C, which cover from the mature to the post-mature stage. Total organic carbon (TOC), Rock-Eval, and low-pressure N2 adsorption tests on pyrolyzed shale samples before and after extractable organic matter (EOM) extraction were conducted systematically. The results indicate that (1) the petroleum generation on nanopore structure change is in stages. The peak nanopore volume expanding stage is the late oil window (R o = 0.9-1.35%). At the post-mature stage (R o > 1.35%), the mesopore volume decreased and the majority of the nanopore space is from macropores. (2) The presence of EOM decreased both mesopores and macropores in the peak oil window. (3) The organic-rich laminated shale generated more macropores than massive shale with increasing thermal maturity. The results of this study shed light on the dynamic effect of laminae fabric, petroleum generation, and retention on shale nanopore structure change across the oil window.

Nanopore Characteristics of the Cambrian Niutitang Formation Organic-Rich Shales in the Middle Yangtze Region and Its Formation Controlling Factors

The shale of Cambrian Niutitang Formation is one of the most important shale gas reservoirs in the Middle Yangtze region, South China. Nanopores are important reservoir spaces for shale gas. The study of pore characteristics and its formation controlling factors is of great significance for the exploration and development of shale gas in the Niutitang Formation. In this study, two drilling core samples and two profile samples were investigated. The laser Raman, X-ray diffraction analysis, FE-SEM, and low-pressure N2 and CO2 adsorption methods are used to study the geochemical and mineral compositions of the shales, and the nanopore characteristics and its formation controlling factors of the shales are discussed. Results show that the shales have the following features: (1) rich in organic matter (OM) and the total organic carbon (TOC) contents ranging from 2.65 to 11.33%, with an average value of 6.81%. (2) The main mineral components of these shales are quartz, feldspar, clay minerals, calcite, and a small amount of pyrite. (3) The samples from the center of the Middle Yangtze region (EY1 well and BGP profile) have a higher maturity value ( Rmc R 0 % = 4.0 %) relatively to the samples from the south of the Middle Yangtze region (XD1 well and JF profile), where the Rmc R 0 % is 2.8%. (4) The maximum N2 adsorption capacity of the four groups of shale samples ranges from 5.090 to 27.333 cm3/g, with an average value of 15.571 cm3/g, while the maximum CO2 adsorption capacity ranges from 2.686 to 5.567 cm3/g, with an average value of 3.776 cm3/g. The higher maturity leads to the EY1 well having the lowest average maximum N2 adsorption capacity, while most of the OM pores in the EY1 well and BGP profile samples are smaller than 10 nm in diameter. The tectonic uplift leads to the profile samples having more meso-macropores than the core samples. The dissolution pores and granular mineral support are the key factors for the better pore structure of the high-evolution stage Niutitang Formation shale.

Effect of lithofacies on differential movable fluid behaviors of saline lacustrine fine-grained mixed sedimentary sequences in the Jimusar sag, Junggar Basin, NW China: Forcing mechanisms and multi-scale models

The crude oil movability, acting as one of the controlling parameters for estimating how difficult it is to exploit petroleum resources from lacustrine shale reservoirs, had still not been investigated systematically, especially for the saline lacustrine fine-grained mixed sedimentary series. How to establish an effective assessment criterion which is suitable for deciphering shale oil movability classically, and how to probe the root cause of the differential movable fluid saturation in heterogeneous lithofacies ? In order to unravel the causal linkage and confirm a coupling relationship between lithofacies heterogeneity and hydrocarbon fluid flow activity for the saline lacustrine fine-grained mixed sedimentary series, we present a set of new results from organic geochemistry analysis, FE-SEM imaging, low-pressure N2 adsorption, high-pressure mercury injection intrusion experiments (MIP), and nuclear magnetic resonance (NMR) experiments from the targeted dessert reservoir of the saline lacustrine fine-grained mixed depositional systems of the Middle Permian Lucaogou Formation in the Jimusar Sag, Southern Junggar Basin, NW China. Our results demonstrated a relatively obvious triple-level distribution of the movable fluid-bearing capacity and also reservoir quality for the dominant five identified lithofacies. The sandy dolomitic sandstones and felsic siltstones act as the first-class categories mainly characterized by a highest total pore volume range and also pore volume within pore size range of 50–300 nm, as well as a relatively lowest D2 values defined as the pore-throat fractal dimension of movable fluid. Secondly, both the dolarenites and dolomitic mudstones are considered as the medium quality reservoirs, and particularly noteworthy is a development of the characteristic microfractures in dolomitic mudstones greatly facilitates the formation and widespread distribution of pore-fracture network systems, leading to a relatively better storage capacity for movable fluid as suggested by relatively higher pore volume and lower fractal dimension values compared with those of micritic dolomites suspected as the most unfavorable category. More importantly, a multi-scale detailed model is proposed to illustrate the potential linkage spanning a total of three different scales respectively as lithofacies associations, microscopic reservoir textures and architectures, as well as fluid occurrence behaviors. This work can be considered as an analogue to better understand the spatial distribution patterns of dessert reservoir intervals and differential recoverability of saline lacustrine mixed-source shale oil resources, and to provide further conceptual basis for optimization of development engineering technique schemes.