Shale Pore Research Articles

Microscopic occurrence and distribution of oil and water in situ shale: Evidence from nuclear magnetic resonance

Characterizing the microscopic occurrence and distribution of in-situ pore water and oil is crucial for resource estimation and development method selection of shale oil. In this paper, a series of nuclear magnetic resonance (NMR) experiments were conducted on shales from the Gulong Sag, Songliao Basin, China, at AR, WR-AR, WOR-AR, Dry, SO, and WR states. In-situ pore water and oil were reconstructed after WOR-AR. An improved T1–T2 pattern for shale oil reservoirs comprising water and oil was proposed to classify and quantitatively detect pore fluids at different occurrence states. The total and free oil contents derived from NMR T1–T2 spectra at AR states were found to correlate well with those from multistage Rock-Eval. Moreover, the NMR-calculated total and free oil are generally larger than those measured from multistage Rock-Eval, whereas adsorbed oil is the opposite, which implies that adsorbed, bound, and movable oils in shale pores can be accurately and quantitatively detected via NMR, without absorbed hydrocarbons in kerogen. As per the NMR T2 and T1–T2 spectra at WOR-AR state, the microdistributions of in-situ pore water and oil were clearly demonstrated. Adsorbed, bound, and movable oils primarily occur in the micropores (<100 nm), mesopores (100–1000 nm), and macropores (>1000 nm), respectively, whereas capillary-bound water is primarily correlated with micropores. Thus, the microscopic occurrence and distribution of adsorbed oil are remarkably affected by pore water, followed by bound oil, and movable oil is hardly affected. This study would be helpful in further understanding the microscopic occurrence characteristics of pore fluids in-situ shale oil reservoirs.

Intelligent Identification and Quantitative Characterization of Pores in Shale SEM Images Based on Pore-Net Deep-Learning Network Model

Among the various shale reservoir evaluation methods, the scanning electron microscope (SEM) image method is widely used. Its image can intuitively reflect the development stage of a shale reservoir and is often used for the qualitative characterization of shale pores. However, manual image processing is inefficient and cannot quantitatively characterize pores. The semantic segmentation method of deep learning greatly improves the efficiency of image analysis and can calculate the face rate of shale SEM images to achieve quantitative characterization. In this paper, the high-maturity shale of the Longmaxi Formation in the Changning area of Yibin City, Sichuan Province, and the low-maturity shale of Beibu Gulf Basin in China are studied. Based on the Pore-net network model, the intelligent identification and quantitative characterization of pores in shale SEM images are realized. The pore-net model is improved from the U-net deep-learning network model, which improves the ability of the network model to identify pores. The results show that the pore-net model performs better than the U-net model, FCN model, DeepLab V3 + model, and traditional binarization method. The problem of low accuracy of the traditional pore identification method is solved. The porosity of SEM images of high-maturity shale calculated by the pore-net network model is between 12 and 19% deviation from the experimental data. The calculated porosity of the SEM image of the low-maturity shale has a large deviation from the experimental data, which is between 14 and 47%. Compared with the porosity results calculated by other methods, the results calculated by pore-net are closer to the true value, which proves that the porosity calculated by the pore-net network model is reliable. The deep-learning semantic image segmentation method is suitable for pore recognition of shale SEM images. The fully convolutional neural network model is used to train the manually labeled shale SEM images, which can realize the intelligent recognition and quantitative characterization of the pores in the shale SEM images. It provides a certain reference value for the evaluation of shale oil and gas reservoirs and the study of other porous materials.

Sodium dodecyl sulphate-treated nanohydroxyapatite as an efficient shale stabilizer for water-based drilling fluids

Drilling water-sensitive shale formations often leads to wellbore instability, resulting in drilling problems because of the clay's high-water affinity. To solve this problem, different nanoparticles (NPs), such as nanosilica, have been used to formulate water-based muds with potassium chloride (KCl-WBM). Nevertheless, the unmatched pore size of shale pores when using nanosilica fails to completely prevent shale swelling and dispersion. This study discusses the effects of KCl-WBM with sodium dodecyl sulphate-treated nanohydroxyapatite (nHAp/SDS) on shale swelling inhibition through various laboratory techniques. These techniques encompass the linear swell meter (LSM), the dynamic linear swell meter (DLSM), hot-rolling dispersion, suspension stability, and pore structure characterization of shale. The rheological and filtration characteristics of nHAp/SDS and compatibility tests were also studied, and the results were compared with those of nanosilica and KCl-WBM. At all concentrations, the performance of the nHAp/SDS test fluids surpassed that of nanosilica. When compared with KCl-WBM system at 10 cP and 25 °C, the nHAp/SDS and nanosilica concentrations increased the plastic viscosity by 20–90 % and 10–70 %, respectively. The inhibitory effect of nHAp/SDS surpasses that of conventional KCl-WBM and inorganic nanosilica. By adding 2.0 wt% nHAp/SDS to KCl-WBM, the shale swelling decreased from 10.1 to 4.7 % (a 53.4 % reduction). Nanosilica also reduced the swelling to 6.1 % (a 39.6 % reduction) during the LSM test at 25 °C. Under the DLSM test conditions, the shale swelling increased due to the activation of the clay platelet site at an increased temperature of 80 °C. For instance, between 25 and 80 °C, the DLSM test revealed that the shale plug height expanded from 6.1 to 9.8 % for 2.0 wt% nanosilica, 4.7–7.6 % for 2.0 wt% nHAp/SDS, and 10.1–18.8 % for KCl-WBM. Furthermore, the recovery rate of hot-rolled shale plugs with KCl-WBM increased from 89.8 to 96.2 % for nHAp/SDS and 76.6 to 88.8 % for nanosilica from the initial rates of 52.1–63.3 % between 65 and 120 °C. The contact angle results showed that nHAp/SDS is hydrophobic, reducing shale-water attraction. Moreover, the 12 nm nanosilica matches nanopore sizes to partially block shale pores. This research found that nHAp/SDS has the potential to improve wellbore stability.

Characteristics of micron-scale pore-fracture modification in marine shale reservoirs with different combustion explosion energy

The combustion explosion fracturing of shale with in-situ methane is a revolutionary fracturing technique, but the modification characteristics of reservoir pores and fractures by combustion explosion energy level are still unclear. In order to study the transformation characteristics of micron-scale pore-fracture systems of marine shale reservoirs with different combustion explosion energies, this study selected a section of shale samples from the Longmaxi Formation in the Luzhou block in the southern Sichuan Basin to carry out different energy gradient combustion explosion test, named W1∼W5 (25–91 MPa). Based on micron CT scanning technology, the three-dimensional reconstruction of shale samples before and after combustion explosion was carried out to analyze the effect of combustion explosion energy on the transformation of the pore-fracture system characteristics. The results show that at the energy between 25 MPa and 45 MPa, the variation characteristics of cracks before and after explosion are not obvious. When the energy of the explosion is in the range of 61 MPa–91 MPa, the cracks gradually extend and become longer, and the distribution density of cracks becomes higher and more interconnected. After the explosion at 91 MPa, it can be seen that a number of annular cracks are generated at the edge of the sample, which are interconnected with radial cracks. Total porosity, connected porosity, pore number, and total pore volume of the shale increased after combustion explosion, where the total porosity at the combustion explosion energy of 91 MPa have the largest increment, while the connected porosity, pore number, and total pore volume in the combustion explosion energy of 71 MPa have the largest relative increments, indicating that there is a fracturing pressure value that strongly breaks through the bottleneck when the explosion pressure is between 61 MPa and 71 MPa. A comparison of different pore size sections before and after the combustion explosion pore volume share found that the explosion pressures of 25 MPa, 45 MPa and 91 MPa tend to expand from 100 to 200 μm pore size to form a larger volume share of >200 μm cracks, while at the explosion pressure of 71 MPa, more inclined to transform the 0–100 μm pores, so that the pores gradually transition to the 100–200 μm. Analysis shows that the gas explosion generates a large pressure, release a large amount of heat. Due to the high temperature and high pressure coupling effect, the pore-fracture in the shale changes significantly. Strong stress waves lead to stress concentration at the tip of shale and crack expansion and extension. At the same time, the local expansion force causes “pore expansion effect”. Various mineral particles in the shale undergo differential expansion, along the crystal rupture or through the crystal rupture. New pore fractures are also generated when the original pores keep expanding, which improves the shale pore connectivity. This understanding can provide a theoretical basis for the selection of the energy level of the in-situ methane combustion explosion in shale.

Experimental study of adsorption/desorption and enhanced recovery of shale oil and gas by zwitterionic surfactants

Shale reservoirs have the characteristics of low permeability and low porosity. In order to enhance the recovery of shale oil and gas, surfactant flooding is a mature reservoir oil recovery method. However, the adsorption of different surfactants on the reservoir rock surface is restricted, depending on the type of surfactant. Therefore, a zwitterionic surfactant (OPHS) was synthesized from oleic acid, 3-dimethylaminopropylamine and sodium 3-chloro-2hydroxypropanesulfonate, and characterized by FTIR, 1H NMR, and TGA, and the mechanism of the OPHS for enhancing oil and gas recovery on shale surfaces was investigated. The results showed that the critical micelle concentration (CMC) of OPHS surfactant solution is 7.9 × 10-4 mol/L and the γCMC is 27.5 mN/m; the concentration of 0.1 % OPHS surfactant solution could reduce the contact angle of the cores from 127.2° to 38.8°, which resulted in spontaneous imbibition; The absolute Zeta potential of shale particles in the OPHS surfactant solution was measured at 39 mV, whereas in deionized water at 15.3 mV. This difference can be attributed to the formation of a stable hydration film on the surface of shale particles induced by the wetting reversal effect. Spontaneous imbibition experiments showed that a 0.1 % solution of OPHS surfactant was able to increase the recovery rate by more than four times compared to the imbibition solution without added surfactant; In high-pressure gas adsorption/desorption experiments, the OPHS surfactant solution demonstrated a higher affinity for adsorption onto the shale surface. It effectively occupied adsorption sites, ultimately facilitating methane gas desorption from the shale. In summary, OPHS zwitterionic surfactants exhibit the capability to desorb hydrocarbons from shale pores through mechanisms such as wetting reversal and competitive adsorption. This research holds significant potential for advancing the field of shale oil and gas recovery, providing valuable insights for enhancing recovery processes.

Microscopic seepage simulation of gas and water in shale pores and slits based on VOF

Abstract The microscopic pore-fracture structure and wettability have a significant influence on the two-phase seepage of shale gas and water. Due to the limitation of experimental conditions, the seepage patterns of gas and water in shale pores and slits under different wetting conditions have not been clarified yet. In this study, the three-dimensional digital rock models of shale inorganic pores, organic pores, and microfractures are established by focused ion beam-scanning electron microscopy scanning, and gas-driven water seepage simulation in shale microscopic pore-fracture structure under different wetting conditions is carried out based on volume of fluid method. The simulation results show that the gas–water relative permeability curves of microfractures are up-concave, and the gas–water relative permeability curves of inorganic and organic pores are up-convex; the gas–water two-phase percolation in microfractures is least affected by the change of wettability, the gas–water two-phase percolation in inorganic pores is most affected by the change of wettability, and the organic pores are in between; the gas–water two-phase percolation zone of microfractures is the largest, and the isotonic saturation is the highest; under the water-wet conditions, the critical gas saturation of microfractures, inorganic pores, and organic pores are 0.13, 0.315, and 0.34, respectively, and the critical gas saturation of organic pores under non-water-wet conditions is 0.525, indicating that under water-bearing conditions, the shale gas flow capacity in water-wet microfractures is the strongest, followed by water-wet inorganic pores, water-wet organic pores, and hydrophobic organic pores, respectively.

High-pressure mercury intrusion analysis of pore structure in typical lithofacies shale

In this paper, statistical research on the characterization of pore and fracture structures is systematically conducted on shale reservoirs in different blocks and under different lithofacies conditions. The impact of lithological characteristics on shale pore fracture structures is revealed, and the coupling mechanism of "high-pressure mercury injection, pore fracture structure, and lithofacies" is clarified. Results show that: (a). When the capillary force is equal to 0.0035 MPa, the pore throat radius is equal to 209.661 μm. (b). There exist turning pressures both in injection curve and removal curve. When the capillary pressure is lower than 100 MPa, the slope of injection curve is high, while when the capillary pressure is higher than 100 MPa, the slope of injection curve becomes lower. (c). The majority of pores is distributed in the pore size interval range from 0.063 μm to 0.004 μm. (d). There are also a certain amount of regular pores in inorganic pores. Part of the pores are secondary intergranular dissolved pores formed by later dissolution.

Pore characterization was achieved based on the improved U-net deep learning network model and scanning electron microscope images

The SEM image method is commonly used in the qualitative characterization of shale pores. The development of shale micro-reservoir pores can be visually observed through SEM images, but the efficiency of manual image processing is low and subjective. The introduction of deep learning greatly improves the efficiency of pore analysis. In this paper, the argon ion polishing SEM image of Longmaxi Formation shale in southern Sichuan is taken as an example. Intelligent identification and quantitative characterization of pores in shale SEM images are realized by Pore-net network model. Pore-net is based on the U-net network model. The way the model reads the data is changed so that the model does not focus on the region of interest. The number of convolutional layers of the model is increased. The Canny edge extraction algorithm is added. It not only reduces the workload of data set production, but also enhances the ability of network model to identify pores. The results show that the deep learning semantic image segmentation method is suitable for pore recognition of shale SEM images. The full convolutional neural network model is used to train the manually labeled shale SEM images, which can realize the intelligent recognition and quantitative characterization of shale SEM images. Compared with FCN and DeepLab V3+ network model, Pore-net performs better. Only 170 data sets are used to train the model. The Pore-net network model still has a good recognition effect on pores, which solves the problem of low accuracy of traditional pore recognition methods. The deviation between the porosity calculated by the Pore-net network model and the experimental data is between 12% and 19%. Compared with the porosity results calculated by the binarization method and other network models, the results calculated by Pore-net are closer to the real values, which proves that the porosity calculated by the Pore-net network model is reliable.

Influence of tectonic preservation conditions on the nanopore structure of shale reservoir: A case study of Wufeng-Longmaxi Formation shale in western Hubei area, south China

Tectonism is one of the dominant factors affecting the shale pore structure. However, the control of shale pore structure by tectonic movements is still controversial, which limits the research progress of shale gas accumulation mechanism in the complex tectonic region of southern China. In this study, 34 samples were collected from two exploratory wells located in different tectonic locations. Diverse experiments, e.g., organic geochemistry, XRD analysis, FE-SEM, low-pressure gas adsorption, and high-pressure mercury intrusion, were conducted to fully characterize the shale reservoir. The TOC, Ro, and mineral composition of the shale samples between the two wells are similar, which reflects that the shale samples of the two wells have proximate pores-generating capacity and pores-supporting capacity. However, the pore characteristics of shale samples from two wells are significantly different. Compared with the stabilized zone shale, the porosity, pore volume, and specific surface area of the deformed zone shale were reduced by 60.61%, 64.85%, and 27.81%, respectively. Moreover, the macroscopic and fine pores were reduced by 54.01% and 84.95%, respectively. Fault activity and uplift denudation are not conducive to pore preservation, and the rigid basement of Huangling uplift can promote pore preservation. These three factors are important reasons for controlling the difference in pore structure between two wells shales. We established a conceptual model of shale pores evolution under different tectonic preservation conditions. This study is significant to clarify the scale of shale gas formation and enrichment in complex tectonic regions, and helps in the selection of shale sweet spots.

Research on the Shale Porosity–TOC Maturity Relationship Based on an Improved Pore Space Characterization Method

Shale pore structure characterization is key to shale reservoir evaluation, sweet spot selection, and economic exploitation. It remains a challenge to accurately characterize shale micro-nano pores. Common experimental characterization methods for shale pore systems are listed, and advantages and weaknesses of each method are analyzed. An improved pore structure characterization method for shale is proposed by combining Helium and NMR. The new method does not affect shale samples and has a higher accuracy. The affecting factors for shale pore evolution for shale are also discussed, showing that organic matter content and maturity are key factors in total porosity development. Furthermore, a shale porosity–TOC maturity relationship chart is developed based on the experimental data of shale samples selected from six shale reservoirs. The application of this chart in Well X in the Gulong field of Songliao Basin proves its utility in evaluating shale reservoirs.

An Optimal Model for Determination Shut-In Time Post-Hydraulic Fracturing of Shale Gas Wells: Model, Validation, and Application

The global shale gas resources are huge and have good development prospects, but shale is mainly composed of nanoscale pores, which have the characteristics of low porosity and low permeability. Horizontal drilling and volume fracturing techniques have become the effective means for developing the shale reservoirs. However, a large amount of mining data indicate that the fracturing fluid trapped in the reservoir will inevitably cause hydration interaction between water and rock. On the one hand, the intrusion of fracturing fluid into the formation causes cracks to expand, which is conducive to the formation of complex fracture networks; on the other hand, the intrusion of fracturing fluid into the formation causes the volume expansion of clay minerals, resulting in liquid-phase trap damage. At present, the determination of well closure time is mainly based on experience without theoretical guidance. Therefore, how to effectively play the positive role of shale hydration while minimizing its negative effects is the key to optimizing the well closure time after fracturing. This paper first analyzes the shale pore characteristics of organic pores, clay pores, and brittle mineral pores, and the multi-pore self-absorption model of shale is established. Then, combined with the distribution characteristics of shale hydraulic fracturing fluid in the reservoir, the calculation model of backflow rate and shut-in time is established. Finally, the model is validated and applied with an experiment and example well. The research results show that the self-imbibition rate increases with the increase in self-imbibition time, and the flowback rate decreases with the increase in self-imbibition time. The self-imbibition of slick water is the maximum, the self-imbibition of breaking fluid is the minimum, and the self-imbibition of mixed fluid is the middle, and the backflow rates of these three liquids are in reverse order. It is recommended the shut-in time of Longmaxi Formation shale is 17 days according to the hydration and infiltration model.

Thermal Maturity Constraint Effect and Development Model of Shale Pore Structure: A Case Study of Longmaxi Formation Shale in Southern Sichuan Basin, China

When the thermal maturity of the Longmaxi Formation in the southern Sichuan Basin is too high, the pore structure of shale becomes poor. Therefore, to investigate the effect of organic matter thermal maturity on shale pore structure, a study was conducted. Using the Longmaxi Formation shale in the southern Sichuan Basin as an example, the intrinsic relationship between shale porosity, pore structure parameters, organic matter laser Raman maturity, and organic matter graphitization degree was examined using X-ray photoelectron spectroscopy, particle helium porosity measurement, organic matter micro-laser Raman spectroscopy, and gas adsorption experiments. The results indicate that thermal maturity is the macroscopic manifestation of the graphitization degree of organic matter, and the correlation coefficient between the two is 0.85. A thermal maturity of 3.5% (with a corresponding organic matter graphitization degree of 17%) aligns with the highest values of shale porosity, pore volume, and pore-specific surface area across all pore size conditions. The evolution model of shale pore structure can be divided into two stages. The first stage is characterized by a thermal maturity between 2.0% and 3.5% (with a corresponding degree of graphitization of organic matter between 0% and 17%). During this stage, the number and connectivity of micro-macropores increase with increasing thermal maturity. The second stage is marked by a thermal maturity between 3.5% and 4.3% (with a corresponding degree of graphitization of organic matter between 17% and 47.32%). Basement faults are present, leading to abnormally high thermal maturity, poor preservation conditions, continuous generation of micropores, better connectivity, and a reduced number of pores. Medium macropores with good connectivity suffer from gas loss in the fracture network, leading to the collapse and disappearance of pores. The results mentioned in the statement have an important guiding role in the efficient exploration of shale gas in the Longmaxi Formation in the southern Sichuan Basin.

Factors controlling the heterogeneity of shale pore structure and shale gas production of the Wufeng–Longmaxi shales in the Dingshan plunging anticline of the Sichuan Basin, China

Shale gas exploration in the Dingshan plunging anticline of the Sichuan Basin, China, has uncovered substantial Wufeng–Longmaxi shale reserves. However, substantial variations exist in shale gas content and production among the wells in this region. We investigated the geological factors and mechanisms influencing shale pore structure heterogeneity and shale gas content and production in the area. We conducted comprehensive analyses of mineralogy, geochemical characteristics, and petrophysical properties on the Late Ordovician Wufeng Formation–Early Silurian Longmaxi Formation shales. Shale samples were collected from a shallow well, Anwen-1, located in proximity to the Qiyueshan thrust fault within the Dingshan plunging anticline. Additionally, samples from Dingye (DY) 1 and DY 3 wells, located at varying distances from the thrust fault, were examined. We also integrated previously published data from two correlative sections in the southeastern margin of the Sichuan Basin, each at different distances from the thrust fault. The pore volume, specific surface area, and porosity of the shales were positively correlated with their total organic content (TOC). However, strong lateral compressive stress, often occurring near the regional thrust fault, attenuated the linear relationship between TOC and pore volume/porosity. Lateral compressive stress did not significant affect shale porosity and pore structure when the distance from the regional thrust fault exceeded approximately 15 km. The specific surface area of the shale was less affected by compressive stress. Moreover, carbonate cementation reduced porosity by sealing shale matrix pores and natural microfractures, reducing nanopore connectivity. Consequently, shale gas production is not solely influenced by shale gas content but is also significantly affected by carbonate cementation. Therefore, shale reservoirs located at relatively long tectonic distances from regional thrust faults (approximately 15 km) within the Dingshan plunging anticline exhibit high pore volume, porosity, and shale gas content, rendering them favorable for shale gas exploration.

Experimental investigation on pyrolysis products and pore structure characteristics of organic-rich shale heated by supercritical carbon dioxide

The efficient pyrolysis and conversion of organic matter in organic-rich shale, as well as the effective recovery of pyrolysis shale oil and gas, play a vital role in alleviating energy pressure. The state of carbon dioxide (CO2) in the pyrolysis environment of shale reservoirs is the supercritical state. Its unique supercritical fluid properties not only effectively heat organic matter, displace pyrolysis products and change shale pore structure, but also achieve carbon storage to a certain extent. Shale samples were made into powder and three sizes of cores, and nitrogen (N2) and supercritical carbon dioxide (ScCO2) pyrolysis experiments were performed at different final pyrolysis temperatures. The properties and mineral characteristics of the pyrolysis products were studied based on gas chromatography analysis, X-ray diffraction tests, and mass spectrometry analysis. Besides, the pore structure characteristics at different regions of cores before and after pyrolysis were analyzed using N2 adsorption tests to clarify the impact of fracturing degree on the pyrolysis effect. The results indicate that the optimal pyrolysis temperature of Longkou shale is about 430 °C. Compared with N2, the oil yield of ScCO2 pyrolysis is higher. The pyrolysis oil obtained by ScCO2 extraction has more intermediate fractions and higher relative molecular weight. The ScCO2 can effectively improve the pore diameter of shale and its effect is better than that of N2. The micropores are produced in shale after pyrolysis, and the macropores only are generated in ScCO2 pyrolysis environments with temperatures greater than 430 °C. The pore structure has different development characteristics at different pyrolysis temperatures, which are mainly affected by the pressure holding of volatile matter and products blocking. Compared to the surface of the core, the pore development effect inside the core is better. With the decrease in core size, the pore diameter, specific surface area, and pore volume of cores all increase after pyrolysis.

Quantitative characterization of organic and inorganic pores in shale based on deep learning

Organic matter (OM) maturity is closely related to organic pores in shales. Quantitative characterization of organic and inorganic pores in shale is crucial for rock-physics modeling and reservoir porosity and permeability evaluation. Focused ion beam-scanning electron microscopy (FIB-SEM) can capture high-precision three-dimensional (3D) images and directly describe the types, shapes, and spatial distribution of pores in shale gas reservoirs. However, due to the high scanning cost, wide 3D view field, and complex microstructure of FIB-SEM, more efficient segmentation for the FIB-SEM images is required. For this purpose, a multiphase segmentation workflow in conjunction with a U-net is developed to segment pores from the matrix and distinguish organic pores from inorganic pores simultaneously in the entire 3D image stack. The workflow is repeated for FIB-SEM data sets of 17 organic-rich shales with various characteristics. The analysis focuses on improving the efficiency and relevance of the workflow, that is, quantifying the minimum number of training slices while ensuring accuracy and further combining the fractal dimension (FD) and lacunarity to study a simple and objective method of selection. Meanwhile, the computational efficiency, accuracy, and robustness to noise of the 2D U-net model are discussed. The intersection over the union of automatic segmentation can amount to 80%–95% in all data sets with manual labels as ground truth. In addition, calculated by the FIB-SEM multiphase segmentation, the organic porosity is used to quantitatively evaluate the OM decomposition level. Deep-learning-based segmentation shows great potential for characterizing shale pore structures and quantifying OM maturity.

Macroscale Gas–Water Two-Phase Transport Simulation in Shales considering Nanomicroscale Effects

As an effective approach to evaluate shale gas production, macroscale numerical simulations have been conducted; however, multiscale storage space and complex gas–water two-phase transport mechanisms are not systematically considered. To deal with this, a rigorous cross-scale gas–water two-phase transport simulation method that considers the pore, core, and field scale is proposed herein. First, to investigate the fluid storage state in different pore types during the gas–water two-phase transport process, a shale pore network gas–water transport simulation is conducted. Subsequently, a core-scale model that considers the distribution of organic matter is constructed, and the gas–water two-phase transport behaviors are upscaled from the pore to the core by incorporating nanomicroscale effects. Next, a shale gas–water two-phase macroscale numerical simulation is implemented based on the core-scale simulation results. Multiple interacting continua are used to describe the shale matrix and microfractures, whereas the embedded discrete fracture method is employed to represent hydraulic fractures. Finally, the manner by which nanomicroscale effects, stress sensitivity, and SRV area affect the production of shale gas reservoirs is discussed comprehensively. This study provides a practical method to estimate shale gas production by rigorously considering gas–water nanomicroscale effects to reduce uncertainties during productivity evaluation.

Research on porosity characterization methods of shale oil reservoirs in Lianggaoshan Formation, Sichuan Basin

Shale oil, an important component of unconventional oil and gas resources, mainly exists in the storage spaces such as shale pores, microfractures, etc. Porosity is commonly used to quantitatively describe the storage space of shale oil and is a key parameter in reservoir evaluation. However, there are significant differences in the results by existing experimental methods for porosity measurement, and moreover, it is difficult to compare the porosity obtained by the experimental measurement method with the logging calculation method. It is urgent to explore reasons for the differences in porosity measurement between various porosity experiments and logging calculations of the shale oil reservoir, and propose an effective method for shale oil reservoir to characterize porosity. In this research, core samples of shale oil reservoirs from the Lianggaoshan Formation of the Sichuan Basin were selected to measure the porosity by means of experimental methods including helium gas charging, saturation liquid method, nuclear magnetic resonance (NMR), etc. Meanwhile, porosity was calculated using the combination method of lithology scanning (LS) logging and conventional logging as well as the NMR logging method. Subsequently, porosity experimental results and logging calculation results were compared to clarify the applicability of various porosity characterization methods. The research results indicate that: 1) The porosity measurement results by the saturation liquid method and the NMR experimental method are close, both greater than that using the helium gas charging method; 2) The hydrogen signal of the dry-state sample is significant in the NMR experiment, mainly originating from organic matter and clay minerals; 3) The NMR short relaxation component in the water-saturated state primarily reflects the signal of organic matter and clay mineral matrix, while the long relaxation component reflects the pore fluid component; 4) After deducting the NMR signal of the dry-state core, the core NMR porosity measurement results under the water-saturated state agree well with that using the saturation liquid method, which is an indicative of effective reservoir porosity; 5) The NMR logging is limited by its echo spacing and cannot reflect the signal from organic matter and the crystal water in clay minerals at T2 &amp;lt; 0.3 ms. Taken together, the porosity measurement method of subtracting the dry-state NMR signal from the water-saturated state NMR signal is considered effective and can be used to reflect the porosity of shale oil reservoirs in the Lianggaoshan Formation of the Sichuan Basin.

Mechanism of pore expansion and fracturing effect of high-temperature ScCO2 on shale

To elucidate the mechanisms underlying the alteration of shale pore fractures by high-temperature supercritical carbon dioxide (ScCO2), this study employed medium–low maturity shale samples from a specific region as research subjects. The samples were subjected to high-temperature ScCO2 reactions in a corrosion-resistant high-pressure reaction vessel at various temperatures. A suite of analytical techniques, including X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), ImageJ image processing software, N2 and CO2 adsorption experiments, thermal gravimetric-differential thermal analysis (TG-DTG) of CO2 pyrolyzed shale oil, and gas chromatography (GC) analysis, were utilized to investigate and analyze the microstructural changes in the shale samples before and after ScCO2 treatment.The results reveal a subtle increase in the content of clay minerals and quartz, accompanied by a decrease in the content of carbonates, potassium feldspar, and calcite. These mineral transformations, encompassing dissolution, precipitation, and swelling processes, exert a substantial impact on the shale surface microstructure and modify the internal pore structure. Consequently, a shift in the mechanical properties of the rock is observed, which bears significance for its fracturing behavior.The experimental results reveal a steady growth in fracture area following high-temperature ScCO2 treatment. Importantly, the extent of initial fracture development plays a crucial role in determining the efficacy of hydraulic fracturing, indicating a positive correlation. Moreover, the connection between fracture area and temperature exhibits a clear trend marked by an initial rise, a subsequent decline, and finally, a resurgence. In particular, the thermal fracturing threshold temperature for the shale samples was found to be around 400 °C.From the analysis, it can be inferred that ScCO2, when subjected to an elevated temperature range of 100-200℃, exhibits mutual interactions with the shale. This results in effective extraction of organic matter and dissolution of mineral constituents within the shale matrix. Consequently, this treatment process leads to a significant reduction in the number of micropores (pore sizes less than 2 nm), while the quantities of mesopores (pore sizes between 2 and 50 nm) and macropores (pore sizes greater than 50 nm) display a noticeable increase.Upon exposure to a temperature range of 200-300℃, a remarkable affinity of the shale for CO2 adsorption becomes evident. The adsorption process contributes to the expansion of the matrix material and deposition of minerals, effectively filling the pore spaces. As a result, the contraction of mesopores and macropores is mitigated, with the predominant change being an increase in the number of micropores.When temperatures reach 300-500℃, the intensified heat initiates thermal decomposition of the kerogen, culminating in the release of pore spaces. This phenomenon prompts an increase in the number of micropores and mesopores, thereby augmenting the pore volume and specific surface area of the shale.

Molecular Dynamics Simulation Study on the Occurrence of Shale Oil in Hybrid Nanopores.

The molecular dynamics simulation was used to simulate the influence of the composite wall stacking effect on shale oil occurrence. The kerogen-illite heterogeneous wall pore model was established to study the effects of temperature, pore size, and wall component ratio on the adsorption ratio and diffusion capacity of shale oil. The calculation results show that the fluid density distribution in the hybrid nanopore is not uniform. When the pore size increases, the proportion of the first adsorption layer to the total adsorption amount decreases rapidly, and the phenomenon of the "solid-like layer" of shale oil in small pores is more obvious. In addition, increases in temperature have little effect on the density peak of the first adsorption layer. With increases in organic matter content in the shale pore model, the diffusion coefficient of fluid decreases gradually, along with adsorption capacity. The influence of the irregular arrangement of kerogen molecules on the adsorption of shale oil is greater than the influence of surface roughness caused by illite on the adsorption.

A Dynamic Permeability Model in Shale Matrix after Hydraulic Fracturing: Considering Mineral and Pore Size Distribution, Dynamic Gas Entrapment and Variation in Poromechanics

Traditional research on apparent permeability in shale reservoirs has mainly focussed on effects such as poromechanics and porosity-assisted adsorption layers. However, for a more realistic representation of field conditions, a comprehensive multi-scale and multi-flowing mechanism model, considering the fracturing process, has not been thoroughly explored. To address this research gap, this study introduces an innovative workflow for dynamic permeability assessment. Initially, an accurate description of the pore size distribution (PSD) within three major mineral types in shale is developed using focussed ion beam-scanning electron microscopy (FIB-SEM) and nuclear magnetic resonance (NMR) data. Subsequently, an apparent permeability model is established by combining the PSD data, leading to the derivation of dynamic permeability. Finally, the PSD-related dynamic permeability model is refined by incorporating the effects of imbibition resulting from the fracturing process preceding shale gas production. The developed dynamic permeability model varies with pore and fracture pressures in the shale reservoir. The fracturing process induces water blockage, water-film formation, and water-bridging phenomena in shale, requiring additional pressure inputs to counteract capillary effects in hydrophilic minerals in shale, But also increases the overall permeability from increasing permeability at larger scale pores. Unlike traditional reservoirs, the production process commences when the fracture is depleted to 1–2 MPa exceeds the pore pressure, facilitated by the high concentration of hydrophobic organic matter pores in shale, this phenomenon explains the gas production at the intial production stage. The reduction in adsorption-layer thickness resulting from fracturing impacts permeability on a nano-scale by diminishing surface diffusion and the corresponding slip flow of gas. this phenomenon increases viscous-flow permeability from enlarged flow spacing, but the increased viscous flow does not fully offset the reduction caused by adsorbed-gas diffusion and slip flow. In addition to the phenomena arising from various field conditions, PSD in shale emerges as a crucial factor in determining dynamic permeability. Furthermore, considering the same PSD in shale, under identical pore spacing, the shape factor of slit-like clay minerals significantly influences overall permeability characteristics, much more slit-shaped pores(higher shape factor) reduce the overall permeability. The dynamic permeability-assisted embedded discrete fracture model (EDFM) showed higher accuracy in predicting shale gas production compared to the original model.