Shale Pore Research Articles

Modeling of adsorption-controlled binary gas transport in ultratight porous media

Organic-rich ultratight porous media such as shales have complicated pore types and sizes, dictating their unique fluid transport and storage mechanisms. This paper introduces a diffusion-based binary gas (CH4 and CO2) transport model in such porous media, incorporating key transport and storage mechanisms. Binary gas mixture within the pore volume is divided into two domains: the free-phase and the sorbed-phase, both of which contribute to gas mass transport. Thermodynamic properties of the free phase are determined using the Peng-Robinson equation of state, while a modified extended Langmuir isotherm describes the sorbed phase. The bulk diffusion, Knudsen diffusion, and viscous diffusion are reconciled to describe binary gas transport in the free phase, while the surface diffusion is considered in the sorbed phase. The mass flux is finally related to the effective diffusion coefficient and the free-phase concentration gradient through coupling all transport mechanisms via the equivalent resister network model. The governing equations are solved numerically using a finite difference approach to simulate co-diffusion and counter-diffusion of a binary gas mixture in two nanoporous media, shale and coal.The results reveal that surface diffusion is more pronounced in coal than in shale due to coal's higher adsorption capacity. In co-diffusion cases, both free-phase and sorbed-phase concentrations decrease over time. However, the decline of sorbed-phase concentrations is slower than that of the free-phase. Moreover, CO2 tends to remain adsorbed within the coal matrix due to its stronger adsorption affinity, unlike CH4, which is more likely to flow out. In counter-diffusion cases, injected CO2 first accumulates near the fracture region and then diffuses further into the matrix. Despite shale's pore volume being twice that of coal, similar amounts of CO2 are injected, which can be attributed to coal's higher CO2 adsorption capacity.

Mechanisms of Reservoir Space Preservation in Ultra-Deep Shales: Insights from the Ordovician–Silurian Wufeng–Longmaxi Formation, Eastern Sichuan Basin

This study aims to explore the reservoir characteristics and formation mechanisms of ultra-deep shale gas in the Ordovician–Silurian Wufeng–Longmaxi Formation in the Sichuan Basin in order to provide theoretical support and practical guidance for the exploration and development of ultra-deep shale gas. With recent breakthroughs in ultra-deep shale gas exploration, understanding its organic matter development, mineral composition, and reservoir space characteristics has become particularly important. The background of this research lies in the significant potential of ultra-deep shale gas, which remains inadequately understood, necessitating an in-depth analysis of its pore structure and reservoir quality. Through a systematic study of the ultra-deep shale in well FS1 of Sichuan Basin, that the following was found: (i) The ultra-deep shale in the Wufeng–Longmaxi Formation is mainly composed of quartz and clay minerals, exhibiting high total organic carbon (TOC) and high porosity characteristics, indicating it is in an overmature thermal evolution stage. (ii) Organic pores and microcracks in the ultra-deep shale are more developed compared to middle-shallow and deep shale, forming a complex pore structure that is conducive to gas storage. (iii) In the diagenesis process, the dissolution and recrystallization of the biogenic skeleton promote the cementation between autogenetic quartz particles, forming a rigid skeleton that effectively inhibits the impact of mechanical compaction. (iv) The overpressure environment created by the hydrocarbon generation process, along with gas production from hydrocarbon cracking, can effectively offset the mechanical compaction of overburden pressure on micropores, and this overpressure environment also promotes the further development of microfractures, which is beneficial for the development and preservation of ultra-deep shale pores. In summary, this study not only reveals the reservoir characteristics and formation mechanisms of ultra-deep shale but also provides essential references for the exploration and development of ultra-deep shale gas in the Sichuan Basin and similar regions, emphasizing the ongoing significance of research in this field.

A modified surface to volume (SVR) method to calculate nuclear magnetic resonance (NMR) surface relaxivity: Theory and a case study in shale reservoirs

Surface relaxivity (ρ2) is a critical parameter for converting nuclear magnetic resonance (NMR) T2 data to pore size distribution (PSD). The surface-to-volume ratio (SVR) method, known for its simplicity and ease of operation, has been widely used for ρ2 calculation in unconventional reservoirs. However, previous studies often overlooked the equivalence of pore ranges characterized when directly applying the classical SVR model. Moreover, shale reservoirs generally develop layered fractures, whose ρ2 values are different from matrix pores. The logarithmic mean value of the T2 distribution (T2LM) is significantly influenced by layered fractures, therefore, relying solely on the T2LM value of a whole sample under fluid-saturated state will lead to inaccurate ρ2 values of matrix pores, particularly in laminated shales where fractures are well developed. However, insufficient attention has been paid to the effect of fractures on the ρ2 calculation. In this study, a modified SVR method based on the theory of NMR relaxation in partially fluid-saturated pores was proposed to characterize the ρ2 of shale matrix pores. Twenty-four shale core samples from the Shahejie Formation in the Jiyang Depression, China were selected, and subjected to series of NMR experiments at varying oil-bearing conditions, and low-temperature nitrogen adsorption (LTNA) analysis. The results indicate a strong linear correlation (R2 > 0.85) between the inverse T2LM (1/T2LM) and the inverse fluid saturation (1/f) when oil molecules across the entire surface layer participate in the exchange process. For a whole core sample, ρ2 values obtained using the modified SVR model are higher than those obtained using the classical SVR model, especially in samples with numerous fractures. The modified SVR method effectively reduces the impact of fractures on the characterization of ρ2 of matrix pores. For shale pore ρ2 characterization, the classical SVR model may be more suitable for pores smaller than 300 nm, with a recommended T2 range of <33 ms. Additionally, ρ2 values for different pore ranges (<25 nm, 25–100 nm, and >100 nm) within individual samples were estimated. It is found that the ρ2 values of smaller pores is greater than those of larger pores, which may be due to differences in mineralogy of the pores across various size ranges. The small pores are more associated with clay minerals while large pores are surrounded by quartz and rigid minerals. In addition, ρ2 is lower in larger pores and fractures that do not contain organic matter and clays, thus the underestimation of ρ2 by the classical SVR method can be corrected by modified SVR method. This study represents the first attempt to examine ρ2 variations across different pore ranges in shale reservoirs. The methodology presented can be applied to other formations, enhancing NMR data application in both laboratory settings and well logging.

The impact of pore heterogeneity on pore connectivity and the controlling factors utilizing spontaneous imbibition combined with multifractal dimensions: Insight from the Longmaxi Formation in Northern Guizhou

The heterogeneity of shale pores, a crucial factor in the occurrence and migration of shale gas, exerts a significant impact on the pore connectivity. Pores exhibiting a range of structural attributes to the complexity of pore connectivity. A comprehensive study into the impact of pore heterogeneity on pore connectivity in shale is lacking. This study aims to explore the impact of pore heterogeneity on pore connectivity in shale and the primary controlling factors of pore connectivity. Shale pore connectivity, pore structures, mineral composition, and geochemical parameters were assessed using various tests, including spontaneous imbibition, adsorption, mercury intrusion capillary pressure (MICP), focus ion beam-scanning electron microscopy (FIB-SEM), sulfur and carbon analysis, vitrinite reflectivity, and X-ray diffraction (XRD). Pore heterogeneity was quantitatively analyzed using the multifractal dimensions method. Results show that the increased heterogeneity of pore structure and surface roughness facilitating the potential for increased connectivity. The presence of well-developed micro-mesopores within the organic matter, alongside numerous disconnected and independent pores, contributes to an increase in pore heterogeneity. Micro-mesopore structures have a more pronounced impact on pore heterogeneity than macropores. The heterogeneity of the pores is predominantly influenced by variations in the PV and SSA of micro-mesopores. Furthermore, the heightened heterogeneity of pore structure (D1) and surface roughness (D2) leads to a more complex pore structure with increased roughness, promoting the potential for enhanced connectivity through additional throats and facilitating the formation of secondary microfractures. Shale cores characterized by high total organic carbon (TOC) content, porosity, and clay mineral content are conducive to improved pore connectivity. Conversely, the increase of thermal evolution maturity of shale in the over-mature stage is not conducive to the increase of pore connectivity. Thermal evolution maturity, TOC content, and clay mineral are key factors that control pore heterogeneity, further affecting the connectivity of shale pores. High pore connectivity is conducive to spontaneous imbibition capacity and the formation of hydraulic microfractures, promoting the migration of shale gas.

Imbibition mechanism of water in illite nanopores of deep shales by molecular simulation

Hydraulic fracturing is an important technique to develop deep shale gas. After hydraulic fracturing, a large amount of fracturing fluid fails to flow back and retains in deep shales. This phenomenon leads to fracturing fluid imbibition and significantly impacts on gas production. However, the understanding of imbibition mechanism in deep shales is very limited. In this work, the microscopic mechanism of fracturing fluid imbibition into illite pores of deep shales was studied using molecular simulation. The factors affecting imbibition were also analyzed. Results show that water imbibition in illite pores can be divided into three stages. In stage 1, the hydrogen bonds between water molecules and illite pore walls are formed, which forces water to enter the pores and becomes a water layer. In stage 2, the hydrogen bonds between water molecules and the water layer are formed, and gas begins to be displaced out of the pores by water. In stage 3, water molecules no longer enter the pores, and the system becomes equilibrium. As for the influencing factors, fugacity pressure mainly affects the imbibition time. The imbibition time becomes longer when fugacity pressure rises. Pore size plays a significant role in imbibition. Gas in illite pores can be totally displaced if the pore size is smaller than 5 nm. The imbibition is also affected by the amount of water. More gas tends to be displaced out of the pores when the ratio of water volume to pore volume (RWP) increases.

Molecular insights into dual competitive modes of CH4/CO2 in shale nanocomposites: Implications for CO2 sequestration and enhanced gas recovery in deep shale reservoirs

CO2 enhanced shale gas recovery has significant potential for improving the recovery rate of adsorbed gas and facilitating the geological sequestration of CO2. Nevertheless, the feasibility and microscopic mechanisms of CO2 enhanced gas recovery in deep shale gas reservoirs remain to be elucidated. In this study, a quartz-kerogen slit model was constructed to represent the shale composite nanopores of deep shale reservoirs. Utilizing the grand canonical Monte Carlo and molecular dynamics methods, the adsorption and diffusion behavior of CH4, CO2 and their mixtures was investigated under high-temperature and high-pressure conditions representative of deep shale reservoirs. The influences of temperature, pressure and aperture size were analyzed. The microscopic mechanisms governing the CH4/CO2 competitive adsorption in deep shale nanopores were uncovered by considering the competitive interactions between different rock constituents and quantifying the various gas storage states. The results show that the adsorption capacity of CO2 is greater than that of CH4 under the deep shale reservoir conditions. The replacement efficiency of CH4 by CO2 is higher in small shale pores. High temperature has a more significant negative impact on the adsorption of CO2 compared to that of CH4. Compared to mid-deep shale reservoirs, the nanopores of deep shale reservoirs have a higher proportion of free CH4/CO2 states. Quartz exhibits greater affinity for CH4/CO2 than kerogen, but kerogen possesses a larger specific surface area, resulting in a higher adsorption capacity per unit volume. The hierarchy of CH4/CO2 diffusion capacity in various storage states is as follows: dissolved gas in the kerogen matrix < adsorbed gas on the quartz surface < adsorbed gas on the kerogen surface < free gas in the pore center. This study improves the understanding of CO2 enhanced gas recovery in deep shale gas reservoirs.

Shale Reservoir Rock Physics Modeling and “Sweet Spot” Prediction Based on Digital Core

Abstract With the increasing advancement in shale exploration and development, the complex pore structure and organic-rich characteristics of shale have gradually become the focus of rock physics models. This study combined digital core technology to obtain detailed information on the shale mineral composition, content, pore and crack contents, and composition. The isotropic self-compatible approximation (SCA) model was used to couple the shale minerals and hard pores to construct a brittle mineral framework. The VRH model was used to mix kerogen and clay, and the SCA-DEM (differential equivalent medium) model was used to add organic pores to construct a clay-organic matter mineral framework. The anisotropic SCA model treated the clay-organic matter mineral framework as an inclusion added to the brittle mineral framework to construct the shale mineral framework. The Eshelby–Cheng model was used to add fracture to the mineral framework and establish a physical shale model. This model was used to optimise the selection of sensitive elastic parameters for physical properties such as brittle mineral and kerogen content, fracture density, and porosity, and the optimisation results were combined to construct an explanatory quantity template. In addition, according to actual data from a study area in southwestern China, we combined to the interpretation chart established by the model to perform isotropic inversion. Then, we analyzed and interpreted the brittleness index (BI) and total organic carbon (TOC) content of the reservoir and predicted the sweet spot area of the shale reservoir.

Wetting mechanism and alteration of nano-sized shale pores: Insights from contrast variation small angle neutron scattering

Wettability of tight shale is crucial for fluid flow and mass transport process in energy geosciences. However, understanding the interfacial chemistry and wetting mechanisms at sub-nano-pore scales remains a formidable challenge. In this study, the Contrast Variation technique of Small Angle Neutron Scattering (CV-SANS) is employed to investigate shale’s interfacial chemistry using reagents that possess a range of different polarities, including water, n-decane, toluene, and dimethyl methanamide. Through five different experimental strategies, we have demonstrated a successful modification of shale wettability, ranging from enhancement, weakening, to reversal. Delving into the mechanisms, we illustrated the crucial role of pre-existing liquid films in these changes, where the uniquely co-existing polar and non-polar functional groups in dimethyl methanamide acted as a conduit for interfacial chemistry adjustments. Furthermore, a solvent immersion led to matrix dilation as well as liberation of residual oil-occupied pores, resulting in altered pore size distributions, with hydrogen bonding playing a significant role in the polar groups. Interestingly, despite shale exhibiting a stronger affinity for oil over water, hydrophilic solvents induced more substantial dilation than lipophilic ones. Collectively, this work elucidates the dynamic change of interfacial chemistry via the configuration of polarity using chemical reagents, and the CV-SANS technique underscores its invaluable utilities in decoding the interfacial wettability traits in nanopore space of shale.

Heterogeneity properties and permeability of shale matrix at nano-scale and micron-scale

Heterogeneity of shale pores at nano-scale and micrometer-scale is of great significance to gas transport properties. In this study, the pore structure of shale samples from lower Silurian Longmaxi Formation in the Sichuan basin is investigated by field emission-scanning electron microscopy (FE-SEM) and x-ray micro-computed tomography (Xμ-CT) technology. Based on fractal theory, the lacunarity is introduced to describe the clustering degree of pores in shale matrix, which can compensate for the limitations of fractal dimension. Combining lacunarity with fractal dimension allows for quantification of subtle differences in pore spatial distribution. For FE-SEM images at nano-scales, the fractal dimension changes in a “U” shape, while lacunarity changes in a “∩” shape. For Xμ-CT images at micrometer-scale, both the fractal dimension and lacunarity change in a logarithmic function. Lacunarity at both nano-scale and micrometer-scale linearly decreases with the increase in fractal dimension. By three-dimensional (3D) pore network modeling analysis, the structure properties of the connected pores, such as the number of pores and throats, pore diameter, pore volume, pore surface, throat length, and coordination number, are quantitatively calculated, and these structure parameters show strong heterogeneity. The average coordination number of the connected pores ranges in 2.92–4.36. This indicates that these pores in shale matrix have poor connectivity. The permeability varies from 0.06 to 0.17 μm2 in two-dimensional (2D) Xμ-CT images but from 3.20 to 34.99 μm2 in a 3D structure. The permeability in the 3D structure is about two order higher in magnitude than that in the 2D Xμ-CT images.

Characterization of Pore Structure and Fluid Mobility of Shale Reservoirs.

Accompanying the commercial exploitation of shale oil and gas in North America, shale oil has gradually become an important resource, sparking great interest among countries around the world in recent years. In this study, focusing on the Paleogene Shahejie Formation in Bohai Bay (Eastern China), techniques such as CT, nitrogen adsorption, mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR) were used to characterize the pore structure and mobility of the shale reservoir. Based on the X-ray CT data, the pore radius of the shale reservoir is in the range 0.5-65 μm, and the pore coordination number is concentrated in the range of 1-4. The shale reservoir is poorly connected. The minimum size of the unit body for establishing the digital core model is 380 μm. Based on the experimental data of nitrogen adsorption and MICP, the pores of shale in the study area are mainly classified as ink-bottle-shaped pores, transition-shaped pores, and flat plate slit-shaped pores. The specific surface area and volume of pores are mainly attributed to meso- and macropores. The movable fluid saturation of shale is distributed from 23.59 to 44.42%, the pore throat radius is distributed from 0.001 to 6 μm, and the lower limit of the movable pore throat radius of shale is distributed between 9.0 and 20.1 nm. The movable fluid porosity is mainly distributed between 0.84 and 4.08%, with an average movable fluid porosity of 2.37%. The findings provide a theoretical basis for the efficient development of shale oil resources.

Evolution of pore structure and diagenetic stages of late Permian shales in the Lower Yangtze Region, South China

This study examines the evolution characteristics of shale pores in the Late Permian Longtan Formation located in the Lower Yangtze region of South China. The complete process of thermal evolution of the samples was achieved through thermal simulation experiments while identifying qualitatively the pore types and their development characteristics using field emission-scanning electron microscope (FE-SEM). Quantitative analysis of pore size distribution was conducted through mercury intrusion capillary pressure (MICP), nitrogen (N2) and carbon dioxide (CO2) adsorption experiments. The paper comprehensively analyzed the pore evolution characteristics and controlling factors of shale in the study area, with an analysis of diagenetic differences. Findings reveal that during the pore evolution process, both morphology and pore size are influenced by thermal maturity. The pore volume is dominated by mesopores and macropores, while the specific surface area is mainly dominated by mesopores and micropores. Thermal evolution promotes the formation of micropores and mesopores but hinders the development of macropores. Moreover, clay minerals transformation and mineral dissolution make certain contributions to the development of micropores. The diagenesis in the study area is controlled primarily by the pyrolysis of organic matter. Pyrite and clay minerals are the first to dissolve, followed by calcite and quartz. Five stages of evolution characterization have been identified from low-mature stage (Ro = 0.88 %) to overmature stage (Ro = 3.35 %) in combination with diagenesis. The development of pore structure and its influencing factors vary across different stages. The influencing factors mainly include hydrocarbon generation from organic matter, compaction, mineral transformation, and dissolution. The process of hydrocarbon generation in organic matter occurs throughout the entire pore evolution process, resulting in the development of numerous micropores and mesopores. Compaction primarily impacts pore development during the early diagenetic stage, causing a substantial transition of primary mineral pores from macropores to mesopores. Mineral transformation and dissolution take place during and after the middle diagenetic stage. The former governs the development of mesopore-sized clay interlayer pores, while the latter primarily generates micropores.

Compositional controls on the Lower Cretaceous Rodby Shale pore structure and surface area: a planned CCS top seal caprock for the Acorn storage site

Fine-grained lithologies above CCS reservoirs cannot automatically be assumed to be mineralogically stable, or high quality top-seals to highly pressured CO2 as saline aquifer have previously contained hydrostatically pressured water. We have investigated the mineralogy, pore systems and surface area characteristics of the Lower Cretaceous Rodby Shale, the caprock to the Captain Sandstone at the UK's planned Acorn/Goldeneye CCS site. Rodby Shale core was logged and analysed by XRD, light microscopy, and SEM. Grain size was measured using laser particle size analysis. Mercury intrusion porosimetry and nitrogen adsorption analysis were used to characterise the pore network. The Rodby is smectite-rich and contains abundant calcite as well as quartz silt with small quantities of chlorite and plagioclase. Calcite was sourced from benthic microfossils, locally recrystallised to create a pore-filling cement. The mean pore throat and pore body diameter are about 17 nm putting the Rodby in the mesopore range and suggesting a predominance of slit-like pores. There are three lithofacies in the Rodby Shale: (i) high surface area clay-rich shale, (ii) low surface area calcite-rich shale, (iii) intermediate surface area quartz-rich. if the second lithotype encountered CO2, then the resulting calcite dissolution would lead to increasing surface area of the remaining shale. The Rodby Shale has good potential to be an effective barrier for CO2 escape, based on assessments of diffusion rate and post-breakthrough advection rate as well as stability and sealing assessments.

Improving Shale Stability through the Utilization of Graphene Nanopowder and Modified Polymer-Based Silica Nanocomposite in Water-Based Drilling Fluids

Shale formations present significant challenges to traditional drilling fluids due to fluid infiltration, cuttings dispersion, and shale swelling, which can destabilize the wellbore. While oil-based drilling fluids (OBM) effectively address these concerns about their environmental impact, their cost limits their widespread use. Recently, nanomaterials (NPs) have emerged as a promising approach in drilling fluid technology, offering an innovative solution to improve the efficiency of water-based drilling fluids (WBDFs) in shale operations. This study evaluates the potential of utilizing modified silica nanocomposite and graphene nanopowder to formulate a nanoparticle-enhanced water-based drilling fluid (NP-WBDF). The main objective is to investigate the impact of these nanoparticle additives on the flow characteristics, filtration efficiency, and inhibition properties of the NP-WBDF. In this research, a silica nanocomposite was successfully synthesized using emulsion polymerization and analyzed using FTIR, PSD, and TEM techniques. Results showed that the silica nanocomposite exhibited a unimodal particle size distribution ranging from 38 nm to 164 nm, with an average particle size of approximately 72 nm. Shale samples before and after interaction with the graphene nanopowder WBDF and the silica nanocomposite WBDF were analyzed using scanning electron microscopy (SEM). The NP-WBM underwent evaluation through API filtration tests (LTLP), high-temperature/high-pressure (HTHP) filtration tests, and rheological measurements conducted with a conventional viscometer. Experimental results showed that the silica nanocomposite and the graphene nanopowder effectively bridged and sealed shale pore throats, demonstrating superior inhibition performance compared to conventional WBDF. Post adsorption, the shale surface exhibited increased hydrophobicity, contributing to enhanced stability. Overall, the silica nanocomposite and the graphene nanopowder positively impacted rheological performance and provided favorable filtration control in water-based drilling fluids.

Investigation of the Pore Characteristics and Capillary Forces in Shale before and after Reaction with Supercritical CO2 and Slickwater

CO2–slickwater hybrid fracturing technology is an essential part of shale gas recovery and CO2 geo-storage. However, the exposure to supercritical CO2 (ScCO2) and slickwater can result in potential changes of the pore structures and surface wetting behavior, which affect the gas transportation and CO2 sequestration security in shale reservoirs. Therefore, in this paper, X-ray diffraction (XRD), low-pressure nitrogen gas adsorption (N2GA), mercury intrusion porosimetry (MIP), and fractal analysis were used to describe the pore characteristics of shale before and after ScCO2–slickwater coupling treatments. Shale’s surface wettability was confirmed by contact angle measurements. After the ScCO2–slickwater treatments, the number of micropores (&lt;3.5 nm) and mesopores (3.5–50 nm) increased, while that of macropores (&gt;50 nm) declined based on the N2GA and MIP experiments. Combined with fractal analysis, we argue that the pore connectivity diminished and the pore structure became more complicated. By analyzing the results of XRD, shale pore changes occurring after the ScCO2–slickwater treatment can be explained by the adsorption of polyacrylamide (PAM). Contact angle measurement results showed that the shale’s surface treated by ScCO2 and slickwater was more hydrophilic than that treated by ScCO2 and water, and indirectly prove our argument above. Hence, the coupling using effect of ScCO2 and slickwater can impair the negative effect of CO2 on the shale capillary force to improve shale gas productivity, but it can negatively affect the security of CO2 sequestration in shale reservoirs.

Environmentally friendly and temperature resistant water-based drilling fluids with highly inhibitory synthetic nanocellulose polymers for deep sea drilling

The ocean is rich in sustainable hydrocarbon. The process of extracting these resources poses challenges such as coexistence of low temperature and high temperature, high pressure of deepwater and unpredictable shale formations. A kind of ionic crosslinking polymer consisting of N, N-dimethylacrylamide (DMA), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), and Cellulose Nanofibers (CNF) (PADC), was synthesized to address these challenges. Cellulose was first oxidized to nanocellulose (CNF) through 2,2,6,6-tetramethylpiperidinyl-1-oxide (TEMPO) oxidation. Subsequently, the ionic crosslinking polymer, consisting of DMA, AMPS, and CNF, was synthesized using ionic crosslinking polymerization. The surface characteristics and morphology were characterized by transmission electron microscopy (TEM), nanoparticle size analysis, and zeta potential analysis. The structural composition was analyzed by Fourier Transform Infrared Spectroscopy (FT-IR). The shale inhibition mechanism was investigated through contact angle and pressure transmission experiments. The results indicated that the average length of PADC is approximately 1450 nm, with an average diameter of less than 100 nm and contains sulfonic acid groups. The shale contact angle increased from 16.75° to 82°, indicating that PADC increased the hydrophobicity of the shale by 390%. Pressure transfer experiments show that PADC can reduce shale permeability by 37%, which means PADC has good hydration inhibition performance. In addition, a drilling fluid system suitable for deep sea drilling was proposed. The drilling fluid system exhibits good rheological properties at 160 °C and 0 °C. The fluid loss after hot rolling at 160 °C is less than 12 mL. The linear expansion of shale core after 16 h is only 0.7%, and the rolling recovery rate at 160 °C is as high as 99.48%. Luminescent bacteria EC50 is 2.0 × 105 mg/L, which means it is non-toxic and environmentally friendly. And drilling fluid conforms to the power law flow model. Therefore, the drilling fluids proposed in this paper can meet the requirements of deep sea drilling in terms of rheological properties and filtration loss properties at 0–160 °C, and can seal shale pores and inhibit shale hydration through the ionic cross-linking PADC. This research offers insights into the utilization of cellulose in well drilling processes and provides references for designing deep sea drilling fluids.

Molecular simulation study on the adsorption and storage behavior of CO2 in different matrix components of shale

ABSTRACT This study investigates the adsorption and storage behaviour of CO2 in the different matrix components of shale based on a molecular simulation method. First, based on the Grand Canonical Monte Carlo (GCMC) method, we successfully established five pore models three fluid models to study the effects of temperature, pressure, pore diameter, water content, and CH4 on the adsorption of CO2. Then, based on the actual data from the shale of the Longmaxi Formation in Sichuan Basin, China, the storage capacity of CO2 in the shale is determined by calculating the density distribution of CO2 and the proportion of excess adsorbed gas. The results demonstrate that both high temperatures and water content are unfavourable for the adsorption of CO2 in the shale pores. The adsorption of CO2 increases with rising pressure while it decreases with increasing pore size. The magnitude and stability of CO2 adsorption in the pores of various matrix components is as follows: organic matter > montmorillonite > illite > kaolinite > quartz. Compared to the scenarios neglecting the adsorption of CO2, the storage capacity of CO2 decreases by 7.87%. The main finding of this study is expected to provide theoretical guidelines for CO2 adsorption storage in shale.

Thermo-hydro-mechanical coupling in oil shale: Investigating permeability and heat transfer under high-temperature steam injection

Steam convective heating emerges as a sustainable and effective method for extracting oil shale, where understanding the temperature-dependent evolution of its pyrolytic characteristics, microstructure, and permeability is vital for efficient resource extraction. Through a stress-sensitive micro-CT scanning and a high-temperature and pressure triaxial test apparatus, this research utilizes Balikun oil shale samples to investigate the changes in microstructure and gas production from 20 °C to 550 °C. The study integrates theoretical analysis and numerical simulations to uncover the fundamental connections between internal permeability and heat transfer mechanisms during steam injection. It reveals that oil shale undergoes two critical evolutionary phases: a stability phase below 350 °C, where volatile dispersion occurs, and a rapid increase phase above 350 °C, marked by significant microstructural changes from micro-fractures to extensive through-going fractures due to intense thermal decomposition. This decomposition leads to increased gas production and enhanced thermal fracturing. The threshold temperature is identified at 400 °C, above which the oil shale's mechanical strength and pore pressure increase, leading to decreased volumetric compression until stabilization. These findings demonstrate that higher temperatures enhance fracture connectivity and steam flow, optimizing the heating efficiency in oil shale extraction.

Multifractal characteristics on pore structure of Longmaxi shale using nuclear magnetic resonance (NMR)

The efficient exploration and extraction of shale gas is essential for China's energy structure as a replacement for natural gas. In this research, shale samples from the Longmaxi Formation in Changning, Sichuan Province were investigated for their pore structure. To achieve this, X-ray diffraction (XRD) and nuclear magnetic resonance (NMR) experiments were performed on the samples. Fractal theory was employed to characterize the pore structure and fractal features of the shale reservoirs. The fractal characteristics of reservoir rocks were correlated with physical parameters and mineral components to identify the controlling factors for the multifractal dimension. The results indicate the following: ① Quartz predominates in the mineral composition of shale in the study area, while clay minerals are the least abundant. ② The primary pore types observed in the samples are bound fluid pores, primarily controlled by mesopores (2 nm ≤ r ≤ 50 nm). ③ The calculated multifractal parameters show that the heterogeneous pore structure exhibits multifractal characteristics. ④ The low probability multifractal parameters Dmin-D0 and αmax-α0 were found to be negatively correlated with reservoir porosity, permeability, and clay mineral content, while the high probability multifractal parameters D0-Dmax and α0-αmin were found to be positively correlated with them. The comprehensive fractal characterization of reservoir rocks demonstrates the applicability of multifractal dimensions in characterizing the heterogeneity of shale reservoir pore structures, which holds potential promise for coal methane exploration.

Shale pore characteristics and their impact on the gas-bearing properties of the Longmaxi Formation in the Luzhou area

Deep shale has the characteristics of large burial depth, rapid changes in reservoir properties, complex pore types and structures, and unstable production. The whole-rock X-ray diffraction (XRD) analysis, reservoir physical property parameter testing, scanning electron microscopy (SEM) analysis, high-pressure mercury intrusion testing, CO2 adsorption experimentation, and low-temperature nitrogen adsorption–desorption testing were performed to study the pore structure characteristics of marine shale reservoirs in the southern Sichuan Basin. The results show that the deep shale of the Wufeng Formation Longyi1 sub-member in the Luzhou area is superior to that of the Weiyuan area in terms of factors controlling shale gas enrichment, such as organic matter abundance, physical properties, gas-bearing properties, and shale reservoir thickness. SEM is utilized to identify six types of pores (mainly organic matter pores). The porosities of the pyrobitumen pores reach 21.04–31.65%, while the porosities of the solid kerogen pores, siliceous mineral dissolution pores, and carbonate dissolution pores are low at 0.48–1.80%. The pores of shale reservoirs are mainly micropores and mesopores, with a small amount of macropores. The total pore volume ranges from 22.0 to 36.40 μL/g, with an average of 27.46 μL/g, the total pore specific surface area ranges from 34.27 to 50.39 m2/g, with an average of 41.12 m2/g. The pore volume and specific surface area of deep shale gas are positively correlated with TOC content, siliceous minerals, and clay minerals. The key period for shale gas enrichment, which matches the evolution process of shale hydrocarbon generation, reservoir capacity, and direct and indirect cap rocks, is from the Middle to Late Triassic to the present. Areas with late structural uplift, small uplift amplitude, and high formation pressure coefficient characteristics favor preserving shale gas with high gas content and production levels.

Pore structure evolution of organic-rich shale induced by structural deformation based on shale deformation experiments

The effect of structural deformation on shale pore structure is a key scientific problem in the development of shale gas resources in structurally complex areas. In this study, we investigated the evolution rules and mechanisms of pore structures in organic-rich shale subjected to structural deformation of varying mechanisms and intensities, by conducting whole-aperture pore structure characterization on experimentally deformed shale rather than naturally deformed shale. Results showed that brittle deformed samples developed more mesopores, macropores, and fracture pores. The inter-granular pores between mineral fragments and the inter-layer pores and micro-fractures were the primary sources of the increased pore structures. The ductile deformation of shale promoted large-aperture transitional pores, mesopores, and small-aperture macropores but was adverse to small-aperture transitional pores, large-aperture macropores, and fracture pores. The primary contributors to the enhanced pore structures were inter-granular pores and inter-layer micro-fractures formed during crumpled deformation and inter-layer sliding of clay minerals, and inter-granular pores caused by the grinding, rounding, and rotation of mineral fragments under the flow deformation of the shale matrix. The irreversible compression of organic matter pores, mineral-related pores, and pre-existing large-aperture pores and fractures was the main reason for the reduction in small-aperture transitional pores, large-aperture macropores, and fracture pores.