Pore Structure Of Shale Research Articles

Fractal dimension changes of shale pore structure and influence on mechanical properties, relative permeability under different hydration degree

Fractal dimension changes of shale pore structure and influence on mechanical properties, relative permeability under different hydration degree

Microstructures of continental organic-rich shale and its adjacent siltstone and carbonate rocks—An example from the Lucaogou Formation, Jimusar Sag, Junggar Basin, NW China

To investigate pore structure of a continental shale and its adjacent carbonate rock and siltstone, 93 shales, 30 carbonate rocks and 10 siltstone samples from the Lucaogou Formation, Junggar Basin were examined by using low-pressure gas (N2 and CO2) adsorption, mercury intrusion and FE-SEM. Total organic carbon (TOC) evaluation, Rock-Eval pyrolysis, and X-ray diffraction (XRD) were used to characterize the organic geochemical parameters and mineralogical parameters of studied samples. The results showed that the free hydrocarbon S1 decreased in the order of siltstone, shale and carbonate rock, which is in accordance with the macropore surface area results. The carbonate rock has the highest TOC content and pyrolytic hydrocarbon S2, followed by shale and siltstone. The inter-crystalline pores of clays and intergranular pores exist widely in shale and siltstone, and a large number of dissolution pores were developed within shale, carbonate rock and siltstone. The smectite, illite and illite/smectite together control the micropores and mesopores of shale, more macropores and mesopores are present in the low TOC shale, carbonate rock and siltstone, however, the promotion effect of TOC on micropores of carbonate rock is stronger than clay. The more macropores of shale and siltstone, causes higher amounts free hydrocarbon S1. In addition, the free hydrocarbon S1 is higher at low fractal dimension D1 (D1＜2.3) and high fractal dimension D2 (D2＞2.6) of mesopore in shale. The free hydrocarbon S1 of the massive siltstone and thin layered shale are significantly higher than that of other types, which may be related to that high macropore volume and low mesopore fractal dimension D1 of the thin layered shale and the high macropore surface area of massive siltstone.

Lattice Boltzmann modeling of the coupled imbibition-flowback behavior in a 3D shale pore structure under reservoir condition

Imbibition and flowback of fracturing fluid usually occur in the shale matrix after hydraulic fracturing, which significantly impacts shale gas production and environmental protection. The rocks of deep shale gas reservoirs are under high-temperature and high-temperature conditions. There are rich micro-nano pores with various pore structures in deep shale. In addition, the flowback behavior is significantly affected by the imbibition behavior because the flowback begins after the end of the imbibition. Therefore, an accurate pore-scale description of the coupled imbibition-flowback behavior is crucial to understand the flowback mechanism and its impacts. In this paper, a pseudo-potential lattice Boltzmann method is employed to simulate the coupled imbibition-flowback behavior in a digital shale core, where the digital core is reconstructed by Markov Chain-Monte Carlo method based on scanning microscope images of deep shale cores. The microcosmic mechanism of the imbibition and flowback is studied under deep shale conditions. The influence of some factors, such as pore structure, fluid viscosity, wettability, and flowback pressure difference, on the flowback behavior of fracturing fluid is investigated. It is found that the fracturing fluid advances almost uniformly throughout the pore space during the imbibition process. The fracturing fluid is easy to adsorb on the pore wall, and the shale gas is located in the middle of the pore space. The viscous fingering is clearly observed during the flowback process, where shale gas flows through large pores to form a flow channel, and the fracturing fluid stays in tiny pores. The flowback rate increases gradually with the flowback time and eventually tends to be almost constant. The wettability, flowback pressure difference, and pore structure significantly influence the flowback behavior, while the fracturing fluid viscosity has a smaller effect on the flowback process.

Pore system classification of Jurassic Da’anzhai Member Lacustrine Shale: Insight from pore fluid distribution

Lacustrine shale oil has the potential to lead the development of China's oil and gas industry. By integrating scanning electron microscopy, low-temperature CO2 and N2 adsorption, high-pressure mercury intrusion, and nuclear magnetic resonance with centrifugation at different speeds, the pore system and pore fluid distribution of Da’anzhai Member lacustrine shale in the Sichuan Basin are studied. The results show that: (1) The reservoir space is mainly inorganic pores and micro-fractures. Nano-micron scale pores are commonly found and widely distributed in the Da’anzhai shale with multiple peaks of 28 nm, 200 nm, 900 nm, and 3.5 µm. The total pore volume ranges from 0.00849 to 0.02808 cm³/g, and the pores ranging from 100 nm to 1000 nm are the main contributors to total pore volume. (2) Pore fluid can be divided into movable oil, bound oil, and adsorption oil. The proportion of movable oil, bound oil, and adsorbed oil is 21.4%, 12.4%, and 66.2% in Da’anzhai shale, respectively. Movable oil mainly occurs in pores larger than 350 nm, bound oil is 30–350 nm, while adsorbed oil mainly exists in pores below 30 nm. (3) The higher the total organic carbon content and clay minerals content, the smaller the pore size, resulting in the low content of movable oil. The higher the content of brittle minerals such as quartz, the better the development of intergranular pores and microfractures, and the higher the content of movable oil. Through the grading evaluation of shale pore structure and pore fluid, it is conducive to guide the exploration and development of Da’anzhai shale oil, which has important theoretical and practical significance.

Method Selection for Analyzing the Mesopore Structure of Shale—Using a Combination of Multifractal Theory and Low-Pressure Gas Adsorption

Nitrogen adsorption experiments have been extensively applied to shale pore structure research and evaluation. The pore structure can be quantitatively characterized in accordance with the nitrogen adsorption–desorption isotherm using various calculation models, whereas the results obtained using different models can more effectively indicate the pore characteristics of shale remains unclear. Further, there has not been any unified process in the optimization of calculation models for pore size distribution (PSD). In this study, the Barret–Joyner–Halenda adsorption (BJH-AD) and BJH desorption (BJH-DE) models were used with Longmaxi Formation shale as an example. Subsequently, the density functional theory (DFT) calculations were conducted on different shale lithofacies samples. Next, the pore structure parameters and heterogeneity obtained using different models were compared, and the consistency parameters of different models were obtained in accordance with Cronbach’s alpha. The results indicated that the pore structure parameters obtained using the BJH-AD model were underestimated since the macroscopic thermodynamic theory was not applicable to this study. The DFT model showed multiple peaks in the range of 1–10 nm, whereas the BJH-DE model had a significant artificial peak in the range of 3.8 nm due to the tensile strength effect, thus suggesting that the DFT model is more capable of characterizing the pores with a pore size 10 nm lower than the BJH model. The PSD curves generated using the three models exhibited multifractal characteristics, whereas the results of the heterogeneity achieved using different models were different. Moreover, the consistency of the results of different models can be studied in depth by combining Cronbach’s alpha with various heterogeneity parameters. The DFT model exhibited high consistency in pore structure parameters and pore heterogeneity, thus suggesting that the DFT method of N2 is the optimal physical adsorption data analysis method in the shale mesoporous range. Accordingly, the nitrogen adsorption curve, the hysteresis loop shape, multifractal parameters, and Cronbach’s alpha were integrated to generate a working flow chart of the nitrogen adsorption model for N2-adsorption-model optimization.

Characterization on Structure and Fractal of Shale Nanopore: A Case Study of Fengcheng Formation in Hashan Area, Junggar Basin, China

The Lower Permian Fengcheng Formation in Halaalate Mountain in the Junggar Basin has enormous potential for shale oil, while few investigations on quantifying pore structure heterogeneity have been conducted. Thus, total organic carbon (TOC), X-ray diffraction (XRD), scanning electron microscopy (SEM), and low-temperature N2 adsorption tests were conducted on the shales collected from the HSX1 well in the Hashan region to disclose the microscopic pore structure and its heterogeneity. Results show that the selected shales mainly consist of quartz, plagioclase, calcite, and clay minerals. The primary pore types are intergranular pores in quartz and carbonate and intragranular pores in clays, while organic matter (OM) pores are rare. Typical types of H2 and mixed H2-H3 were observed. Type H3 shale pore size distributions (PSD) are unimodal, with a peak at about 70 nm, while Type H2-H3 shales are bimodal, with peaks at about 70 nm and 3 nm, respectively. Type H3 shales have lower D2 than Type H2-H3 shale, corresponding to weaker pore structure heterogeneity. Multifractal analyses indicate that macropores in Type H3 shales have stronger heterogeneity with large D10−D0 ranges, while minor D−10−D0 ranges mean weaker heterogeneity of micro- and mesopores, and so do Types H2-H3 shales. The higher the contents of plagioclase and clay minerals, the more heterogeneous the micro- and mesopores are; a larger content of quartz leads to more heterogeneous macropores. Specific surface area, micro-, and mesopores contents positively correlate to D2, while average pore diameter and macropores are on the contrary, thus the higher the content of micro- and mesopores and the specific surface area, the lower the content of macropores and average pore diameter, the more complex the microscopic pore structure of shale. Micro- and mesopores control the heterogeneity of shale pore development with a great correlation of D−10−D0 and D−10−D10, and D2 can effectively characterize the heterogeneity of a high porosity area with a strong correlation of D2 and D0−D10.

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.

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

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

Thermal and nonthermal effect of microwave irradiation on the pore microstructure and hydrocarbon generation of organic matter in shale

In situ heating conversion is the most effective means to develop medium-low maturity shale oil. Herein, the effects of microwave irradiation on the shale pore structure and hydrocarbon generation of organic matter were studied using an independent development microwave device in combination with Rock-Eval, Leco analysis, X-ray diffraction, field emission scanning electron microscopy, low-temperature N2 adsorption/desorption, nuclear magnetic resonance, Fourier transform infrared spectroscopy and kinetic simulation of hydrocarbon generation. The results show that microwave irradiation can effectively heat shale and the temperature can rise to hundreds of degrees Celsius in a short time (10 min), with 400 °C as the best temperature for in situ conversion of medium-low maturity shale, at which the pore volume and surface area reach the maximum. Microwave irradiation is conducive to pyrolysis and hydrocarbon generation of aliphatic structure in shale organic matter. There are differences in the response of different organic components to the nonthermal effect of microwave irradiation, which reduces the activation energy of hydrocarbon generation during organic matter pyrolysis. Heating shale by microwave irradiation can effectively promote organic matter pyrolysis and hydrocarbon generation, improve rock reservoir and seepage capacity, and is of great significance for the efficient development of shale oil.

Large-volume FIB-SEM 3D reconstruction: An effective method for characterizing pore space of lacustrine shales

Focused ion beam scanning electron microscopy (FIB-SEM) is a commonly used three-dimensional (3D) pore-network reconstruction method for shales due to its unique capability in imaging nano-scale pores. However, it has been found that for pore space of lacustrine shales with strongly heterogeneous pore structures, the conventional FIB-SEM 3D models usually with dimensions of 10 μm × 10 μm × 10 μm cannot adequately characterize the pore structures as the representative element volume required is much larger than the FIB models. Here, we propose to utilize large volume FIB-SEM (LV-FIB-SEM) 3D models to resolve this challenge. The LV-FIB-SEM model has a significant enhancement in the model size compared with the commonly used conventional FIB-SEM models and a much higher spatial resolution than non-synchrotron nano X-ray CT models for similar imaging sample sizes. With 75 μm × 65 μm × 60 μm as predesigned reconsruction size, after image processing two LV-FIB-SEM 3D models with sizes of 73.56 μm × 38.13 μm × 52.59 μm and 74.01 μm × 43.05 μm × 42.00 μm and model resolution of 30 nm were reconstructed and quantitatively analyzed. When use the conventional FIB-SEM models of 10 μm × 10 μm × 10 μm, the relative deviations between the porosities derived from 100 stochastic models and the average porosity for the two samples studied are −41.13% ∼ +87.31% and −51.66% ∼ +56.05%, respectively, indicating that such small models are not representative of the actual pore structure of the shales investigated. When the model sizes have been increased by 96 times volumetrically, the probabilities of matching average porosities for the two samples increase from 13% to 86% and from 12% to 100%, respectively. This research demonstrates that the upsizing of the FIB-SEM models enables an effective improvement on the representativeness of shale pore structures characterized. It is recommended that LV-FIB-SEM 3D reconstruction be employed to study pore space of lacustrine shales with strongly heterogeneous pore structures, which would enable a more accurate characterization and evaluation of reservoirs for shale oil exploration and development.

Dual effects of retained fracturing fluid on methane diffusion in shale containing adsorbed methane

Retained fracturing fluids have dual effects on methane diffusion in organic-rich shale, which disrupt the methane transport. To understand these dual effects, the methane transport behavior was investigated before and after water entered the shale pore structure. We simulated the entry of the fracturing fluid into shale by changing the imbibition pressure difference. Meanwhile, nuclear magnetic resonance (NMR) was employed to analyze the distribution of water in the multiscale pore structure of shale. Results indicate that water is mainly distributed in pores with a diameter (D) of <50 nm, especially in pores with D of 2–10 nm. When water entered the shale pore structure, the methane diffusion rate decreased in pores with D > 10 nm and increased in pores with D < 10 nm. In the presence of water, the methane diffusion rate in shale macropores decreased by 13.8%–52.6%, and the methane diffusion rate in micropores increased by 67.9%–223.7%. These results indicate that although water retention is not beneficial to the slip flow and Knudson diffusion of methane, it facilitates the surface diffusion of methane. These conclusions hold high significance for determining the shut-in time and fracturing fluid flowback in shale gas wells.

The microdistribution of fluid and its effect on pore structure in shale: A case study of lacustrine Chang 7 shale, Ordos Basin

The pore fluid distribution in nanosized pores in shale cannot be observed directly with the current observation equipment which makes it difficult to study the fluid behavior in the shale pore system. To better understand pore fluid evolution and distribution in shale and its effect on pore structure with increasing maturity from immature to oil windows, a serial of samples with different maturity have been collected from the Lower Triassic lacustrine clay-rich Chang 7 shale in the Ordos Basin and treated with oven drying and sequential extraction to remove water, mobile oil, and asphaltene. We have measured the pore-size distributions in the presence of different pore fluids by using the mercury intrusion and N2 adsorption and desorption testing. The results indicate that (1) the pores in the clay-rich samples are mostly slit-shaped mineral pores, consist of a small number of macropores (pore size &gt;50 nm) and a large number of mesopores (pore sizes between 7 and 36 nm), and also including a small amount of poorly developed organic matter-hosted pores. (2) Different types of pore fluids appear to occupy different pore-size ranges. Water prefers to occupy the mineral mesopores. Mobile oil (extracted by n-hexane) is mostly distributed in 2–10 nm-sized organic-matter-hosted mesopores. Asphaltenes are mostly distributed in mesopores in the range of 25–36 nm. (3) The presence of pore fluid significantly impacts the pore structures of shale. The pore volume and specific surface area decrease due to pore fluid occupation, even for low-maturity samples in which the organic matter pores also are developed but cannot be observed under a scanning electron microscope. (4) Organic matter abundance and thermal maturity have significant effects on the pore fluid composition and distribution. With increasing maturity, water is gradually displaced by oil due to hydrocarbon generation and accumulation in large mineral pores.

Pore structure and fractal characteristics of Wufeng–Longmaxi formation shale in northern Yunnan–Guizhou, China

In this study, the microscopic pore characteristics of shale in marine strata are evaluated. Based on field emission scanning electron microscopy (FE-SEM), low-temperature N2 adsorption (LT-N2GA), low-pressure CO2 adsorption (LP-CO2GA) and high-pressure methane adsorption (HPMA) experiments, the pore characteristics of 12 shales from the Wufeng–Longmaxi Formations in northern Yunnan and Guizhou are characterized qualitatively and quantitatively. Fractal Frenkel–Halsey–Hill (FHH) theory is used to analyse the fractal characteristics, and the adsorption pore characteristics of shale are discussed. The correlation between the fractal dimension and pore structure and adsorption performance is determined. The results show that the total organic carbon (TOC) contents of the 12 shales are in the middle–low level, ranging from 0.43% to 5.42%, and the shales are generally in the highly mature to overmaturity stage (vitrinite reflectance (Ro) values between 1.80% and 2.51%). The mineral composition is mainly quartz and clay minerals. The average clay mineral content is 40.98% (ranging from 24.7% to 63.3%), and the average quartz content is 29.03% (ranging from 16.8% to 39.6%), which are consistent with those of marine shale in the Sichuan Basin. FE-SEM and LT-N2GA isotherms reveal a complex shale pore structure and open pore style, mainly ink bottle-shaped and parallel plate-like pores. The total pore volumes (PVs) range from 0.012–0.052 cm3/g, and the specific surface area (SSA) values range from 18.112–38.466 m2/g. All shale samples have abundant micropores and mesopores, accounting for &amp;gt;90% of the total SSA. The fractal dimensions, D1 and D2, were obtained from N2 adsorption data, with different adsorption characteristics at 0–0.5 and 0.5–1.0 relative pressures. The fractal dimensions increase with increasing BJH PV and BET SSA and decrease with decreasing average pore diameter (APD). The fractal dimensions are positively correlated with the TOC and clay mineral contents and negatively correlated with the quartz content. The fractal dimension can be used to evaluate the methane adsorption capacity; the larger the fractal dimension is, the larger the methane adsorption capacity is. Fractal analysis is helpful to better understand the pore structure and adsorption capacity of shale gas reservoirs.

Characterizations of Organic Matter Chemical Structure and Pore Structure in High-Temperature Metamorphic Shales——Insights into the Effect of Graphitization on Porous Organic Matter

Characterizations of Organic Matter Chemical Structure and Pore Structure in High-Temperature Metamorphic Shales——Insights into the Effect of Graphitization on Porous Organic Matter

Pore Structure and Fractal Characteristics of Continental Low Maturity Organic-Rich Shale in the Sha-4 Member of the Liaohe Western Depression

The research on pore structure and heterogeneity of shale reservoirs has always been a hotspot in the study of unconventional reservoir characteristics. China is a country dominated by continental shale. Compared with marine shale, continental shale has lower maturity and stronger reservoir heterogeneity. In this study, Sha-4 shale in the Liaohe Western Depression was selected for low-temperature nitrogen adsorption, scanning electron microscopy and other experiments revealing the pore structure and fractal characteristics of continental low mature organic-rich shale. The fractal dimension was calculated by the FHH model and the effects of TOC and mineral composition on pore structure and fractal characteristics were discussed. The results show that the Sha-4 shale in the study area is mainly mesoporous and the main pore types are inorganic pores with relatively large pore diameters, such as intergranular pores and inter-crystalline pores. The pore morphology is very complex, mainly narrow slit and flat pore, and the pore is often filled with organic matter. The fractal dimensions D1 range from 2.58 to 2.87 and D2 range from 2.18 to 2.55, and the pore structure shows obvious dual fractal characteristics. The pore structure and fractal characteristics of shale are mainly affected by TOC and quartz due to the low degree of the thermal evolution of shale and their effects are different from those of marine shale reservoirs. The increase in TOC reduces the heterogeneity of the shale reservoir. In addition, mineral particles with strong weathering resistance and stability such as quartz can protect the pore structure of shale, improve the pore structure and reduce the reservoir heterogeneity. This study can provide support for the study of low maturity continental shale reservoir heterogeneity in the Sha-4 member of the Liaohe Western Depression.

Characteristics and kinetics of Maoming oil shale pyrolysis in the presence of CoCl2 assisted steam

In this work, a series of experiments on pyrolysis of Maoming oil shale were conducted in a custom-built reactor, in order to investigate the pyrolysis characteristics and the pyrolysis kinetic of Maoming oil shale heated by CoCl2 assisted steam. The experimental results show that compared with conventional and steam heating, the combined physical and chemical action of CoCl2 assisted steam heating can reduce the initial pyrolysis temperature and apparent activation energy of oil shale, and increase its mass loss. CoCl2 assisted steam heating is helpful to destroy the pore structure of oil shale, the CoCl2 assisted steam preheating treatment of oil shale near the initial pyrolysis temperature is beneficial to the production of volatiles in oil shale pyrolysis. According to the theory of consecutive reaction model, the larger the ratio of the first to the second reaction rate constant, the greater peak of relative concentration of thermal bitumen can be obtained which is the intermediate product. After reaching the peak relative concentration of thermal bitumen, the oil shale pyrolysis enters the main production stage. The pyrolysis specific rate increases with the heating temperature, and the pyrolysis specific rate is higher and the pyrolysis reaction time is shorter under CoCl2 assisted steam heating.

Effects of Supercritical CO2 Injection on the Shale Pore Structures and Mass Transport Rates

Characterizing the pore structures and transport properties of low-permeability shales is critical for evaluating these formations as potential seals or storage sites for geological CO2 sequestration. Here, we use low-pressure gas adsorption in conjunction with nuclear magnetic resonance (NMR) to characterize the pore-size distribution of shales before and after injection of supercritical CO2. Nitrogen gas was used as the detecting phase for the adsorption experiments and pentane liquid was used for the NMR experiments. We also performed time-resolved NMR and gravimetric microbalance measurements to observe mass transport during desaturation. We use these data to estimate the self-diffusion coefficient of pentane and changes in the saturation state of the pore network. We analyzed samples with a range of compositions from the Wolfcamp shale before and after exposure to supercritical CO2 for 3 days. Integrating the gas adsorption and NMR data shows how supercritical CO2 injection alters the pore-size distribution for pore sizes <1 nm to 1 mm. Our results provide insights on how the pore structure and mass transport properties of different shale lithologies may evolve during storage of supercritical CO2.

Investigation of induced change in pore structure by the reaction of shale with fracturing fluid

To study the change in the shale pore structure during the reaction between shale and fracturing fluid, a soaking experiment was conducted on shale from the Longmaxi Formation in the Sichuan Basin, China. The changes in the pore structure before and after the experiment were analyzed. The results show that the number of mesopores, macropores, and microfractures increased after the shale reacted with fracturing fluid. The analysis reveals that the dissolution of salts is the main reason for the change in the shale's pore structure. In addition, the dissolution of salt promotes the hydration of clay minerals and changes the pH of the fracturing fluid to produce 500–1000 nm corrosion pores.

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

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

Impact of cyclic liquid nitrogen treatment on the pore and fracture structures of shale at different scales and its effect on permeability enhancement

The ultra-low permeability of shale reservoirs limits shale gas production. Liquid nitrogen (LN2) fracturing is a promising reservoir stimulation technology that has attracted considerable attention in the unconventional natural gas industry. However, the evolution of pore and fracture structures in shale subjected to cyclic LN2 treatment and its effect on permeability enhancement have not been fully elucidated, especially with the presence of pore or fracture water. In this study, the physical response of Longmaxi Formation shale to cyclic LN2 treatment was carefully investigated. Scanning electron microscopy (SEM) and computed tomography (CT) were used to investigate the alteration of the pore and fracture structures in water-saturated and dry shale samples at different scales before and after cyclic LN2 treatment. Based on digital image processing and the fractal theory of pore structure, the variation in pore and fracture structures in shale matrices at the microscale was quantitatively analyzed. The experimental results indicate that cyclic LN2 treatment can effectively enhance pore volume and induce microfracture initiation and propagation. These phenomena were more significant in the water-saturated shale samples. Different correlations between the areal porosity of matrices and overall porosity/permeability in dry and water-saturated samples indicate that thermal stress and frost-heave force have different effects on shale pore and fracture structures. Owing to the different generation mechanisms, thermal stress was mostly applied to shale matrices, whereas frost-heavy force only existed near water-rich minerals, which were mainly clay in shale natural fractures. These two driving forces also had different responses to cyclic LN2 treatment. Because the new generated pores and microfractures have increased the distance among mineral particles, thermal stress gradually decreased with increasing LN2 treatment cycles. However, frost-heavy force could still induce macro-fractures along the bedding face of shale samples after several LN2 treatment cycles, owing to water migration during water-ice phase change.