Shale Pore Research Articles

Pore structure evolution of lacustrine organic-rich shale from the second member of the Kongdian formation in the Cangdong Sag, Bohai Bay Basin, China

Pyrolysis experiments were conducted on lacustrine organic-rich shale from Cangdong Sag in Bohai Bay Basin, China, to investigate the impact of hydrocarbon generation on shale pore structure evolution. Thermal evolution is found to control the transformation of organic matter, hydrocarbon products characteristics, and pore structure changes. Furthermore, pore volume and specific surface area increase with increasing maturity. In low-mature stage, the retained oil content begins to increase, pore volumes show slight changes, and primary pores are occluded by the generated crude oil of high molecular weight and density. In the oil-window stage, the retained oil content rapidly increases and reaches maximum, and pore volumes gradually increase with increasing thermal maturity. At high mature stage, the retained oil content begins to decrease, and the pore volume increases considerably owing to the expulsion of liquid hydrocarbon. In over mature stage, natural gas content significantly increases and kerogen transforms to asphalt. Numerous organic pores are formed and the pore size gradually increases, resulting from the connection of organic pores caused the increasing thermal stress. This study lays a foundation for understanding variation of hydrocarbon products during the thermal evolution of lacustrine shales and its relationship with the evolution of shale reservoirs.

Fabrication of a Hydrophobic Hierarchical Surface on Shale Using Modified Nano-SiO2 for Strengthening the Wellbore Wall in Drilling Engineering

Wellbore stability is essential for safe and efficient drilling during oil and gas exploration and development. This paper introduces a hydrophobic nano-silica (HNS) for use in strengthening the wellbore wall when using a water-based drilling fluid (WBF). The wellbore-strengthening performance was studied using the linear swelling test, hot-rolling recovery test, and compressive strength test. The mechanism of strengthening the wellbore wall was studied by means of experiments on the zeta potential, particle size, contact angle, and surface tension, and with the use of a scanning electron microscope (SEM). The surface free energy changes of the shale before and after HNS treatment were also calculated using the contact angle method. The experimental results showed that HNS exhibited a good performance in inhibiting shale swelling and dispersion. Compared with the use of water, the use of HNS resulted in a 20% smaller linear swelling height of the bentonite pellets and an 11.53 times higher recovery of water-sensitive shale—a performance that exceeds those of the commonly used shale inhibitors KCl and polyamines. More importantly, the addition of HNS was effective in preventing a decrease in shale strength. According to the mechanism study, the good wellbore-strengthening performance of HNS can be attributed to three aspects. First, the positively charged HNS balances parts of the negative charges of clay by means of electrostatic adsorption, thus inhibiting osmotic hydration. Second, HNS fabricates a lotus-leaf-like surface with a micro-nano hierarchical structure on shale after adsorption, which significantly increases the water contact angle of the shale surface and considerably reduces the surface free energy, thereby inhibiting surface hydration. Third, the decrease in capillary action and the effective plugging of the shale pores reduce the invasion of water and promote wellbore stability. The approach described herein may provide an avenue for inhibiting both the surface hydration and the osmotic hydration of shale.

Experimental investigation on the shale's time-dependent microphysical characteristics under the fluid-shale interaction

The long-term fracturing process will affect the shale's microphysical characteristics. In this paper, under the fluid-shale interaction with different duration, the evolutions of shale's minerals, pore structure, brittleness, as well as the ions of fluids are investigated. The results show that, as the interaction proceeding, the shale's typical minerals experienced a resolution and regeneration process, while the ions concentration of the fracturing fluid shows negatively correlated with the that of minerals correspondingly. The evolutions of shale's pore volume and the specific surface area show opposite changing trends, which indicates that time-dependent micropore is characterized as dissolution first and then filling. Finally, the shale's time-dependent brittleness model is developed based on the minerals' evolution. These findings will provide a new insight for the optimization of hydraulic fracturing design based on shale's dynamic microphysical characteristics.

The Whole-Aperture Pore Structure Characteristics and Their Controlling Factors of the Dawuba Formation Shale in Western Guizhou

Since shale gas mainly occurs in shale pores, research on pore structure characteristics is the key to understanding the shale gas accumulation mechanism. The pore structure of the Lower Carboniferous Dawuba Formation shale in the Qianxi area, represented by the well QSD-1, which obtains a daily shale gas flow of 10,000 m3 and represents an important breakthrough in the investigation of marine shale gas in the Upper Paleozoic region of southern China, is characterized by high-pressure mercury compression experiments and low-temperature gas adsorption (N2 and CO2) experiments with whole pore size. The main controlling factors affecting the pore development of the shale are discussed. (i) The micropores and mesopores are more developed in the shale, and the macropores are the second most developed in the shales of the Dawuba Formation in the Qianxi area, among which the mesopores and macropores contribute most to the pore volume and the micropores and mesopores contribute most to the pore-specific surface area. (ii) The microfractures and interlayer pores of clay minerals are developed in the shales of the Dawuba Formation, which are the main storage spaces for hydrocarbon gases. (iii) The main factors affecting the adsorption capacity of the shales of the Dawuba Formation in the Qianxi area are the organic carbon content and clay mineral content of the shales, both of which have an obvious positive correlation with the variation of pore structure.

Characteristics and Affecting Factors of K2qn1 Member Shale Oil Reservoir in Southern Songliao Basin, China

Member 1 of the Cretaceous Qingshankou Formation (K2qn1 Member) in the Southern Songliao Basin, composed of mainly semi-deep and deep lacustrine shale layers, is rich in shale oil. Previous studies on shale reservoir characteristics mainly focused on marine shale strata, but few studies have considered lacustrine shale strata, so the pore-throat features and differences between the lacustrine shale reservoir and marine shale reservoir need to be studied. Taking the Class-I and II sweet spot sections and Class-III non-sweet spot section of Da’an shale oil demonstration area as examples, SEM (scanning electron microscopy) was used to qualitatively and semi-quantitatively describe the morphology and occurrence characteristics of the shale. Full-scale pore size distributions of lacustrine shale samples were quantitatively measured by N2GA (nitrogen absorption) combined with dominant pore size segments tested by experiments. Finally, the lacustrine shale reservoir was compared with classical marine shale reservoirs, and factors influencing semi-deep lacustrine and deep lacustrine shale oil in a large depression basin were analyzed by XRD (X-ray diffraction). The results show that Class-I and II sweet spots are rich in organic matter, quartz, and carbonate minerals, have mainly type H2 nitrogen adsorption hysteresis loops, and contain mainly inorganic pores, such as intergranular and intragranular pores in nano-scale, forming nano-scale reservoirs. Lacustrine shale is obviously different from marine shale in terms of pore structure, and the development characteristics of the lacustrine shale pore structure are more influenced by mineral components. Factors affecting the development of shale oil reservoirs in K2qn1 member include mineral components, TOC (total organic carbon), and diagenetic processes. Quartz and carbonate minerals are good for enhancing reservoir quality, while clay minerals are destructive to the development of reservoirs. TOC is the material foundation and main factor for forming organic pores, but the higher the TOC, the smaller the diameter of the organic pores will be. Compaction, cementation, and dissolution are the main diagenetic processes controlling the development of reservoir space.

Water Distribution in the Ultra-Deep Shale of the Wufeng–Longmaxi Formations from the Sichuan Basin

Recently, deep and ultra-deep shales (depth >3500 m) of the Lower Paleozoic Wufeng–Longmaxi formations (WF–LMX) have become attractive targets for shale gas exploration and development in China, and their gas contents may be influenced by the occurrence of water to some extent. However, the water content and its distribution in the different nanopores of the deep and ultra-deep shales have rarely been reported. In this study, a suite of the WF–LMX ultra-deep shale samples (5910–5965 m depth) from the Well PS1 was collected for water content measurements, and low-pressure CO2 and N2 adsorption experiments of both as-received and experimentally dried shale samples were carried out to investigate the distribution of water in the different nanopores. Since the studied ultra-deep shales are characterized by higher thermal maturity (equivalent vitrinite reflectance (EqVRo) > 2.5 %) and ultra-low water saturation, the pore water is generally dominated by irreducible water. The content of irreducible water of the studied shales varies from 1.57 to 13.66 mg/g, averaging 6.74 mg/g. Irreducible water may mainly occur in the clay-hosted pores, while it could also be hosted in parts of organic pores of organic-rich shales. Irreducible water is primarily distributed in non-micropores rather than in micropores of the studied shales, which mainly occurs in micopores with a diameter of 0.4–0.6 nm and mesopores with a diameter of 2–10 nm. Very low contents of irreducible water could reduce the specific surface area and volume of non-micropores of the shales to some extent, but the effect of irreducible water on the specific surface area of non-micropores was more significant than the volume of non-micropores, especially for organic-rich shale samples. The ultra-deep shale gas may be predominately composed of free gas, so low contents of irreducible water may play a limited role in its total gas contents. Overall, our findings can be helpful for a better understanding of water distribution in the highly-matured shales, and provide a scientific basis for ultra-deep shale gas exploration.

Experimental study on reservoir characteristics and oil-bearing properties of Chang 7 lacustrine oil shale in Yan’an area, China

Abstract The Chang 7 Member shale of the Upper Triassic Yanchang formation in the Ordos basin is a hot spot in petroleum geology research. In this study, considering the Chang 7 shale in the Yan’an area as an example, the full-scale pore size characterization of lacustrine shale was realized based on the scanning electron microscopy image gray correction method, nitrogen and carbon dioxide adsorptions, and high-pressure mercury intrusion tests. In addition, the pore structures and oil-bearing properties of the Chang 7 shale were systematically studied. The results show that the Chang 7 shale is rich in organic matter, with an average total organic carbon value of 4.69% and an average R 0 value of 0.9%. It is in the mature-wet gas (crude oil-associated gas) stage. There are certain differences in the development characteristics and pore size distribution of different types of pores in shale. The statistical results showed that the pore diameters of the intergranular pores and intragranular dissolved pores were significantly larger than the intercrystalline pores of clay minerals and the organic pores. The organic pores in solid bitumen are extremely developed, whereas the organic pores in kerogen are relatively underdeveloped. The lower limit of the effective pore size of shale is 20 nm. The network system composed of inorganic pores-microcracks-organic matter-organic pores and siltstone laminae provides important channels and retention spaces for the migration of shale oil and gas within the source. This study found that the proportion of movable oil in sandy layers is relatively high, followed by shale with sandy laminae, whereas pure shale has the lowest proportion of movable oil. Therefore, the degree of sandy laminar development, the abundance of organic matter, and the degree of thermal evolution are the key geological factors that control the porosity and oil-bearing properties of shale oil reservoirs.

Molecular Dynamics Simulation and Experimental Studies of the Wettability Behaviors of Shales

The wettability behaviors of nanoscale pores in shales from Longmaxi Formation in the Sichuan Basin of South China, which contain quartz pores, illite pores, and organic matter pores, were investigated using the molecular dynamics simulation and experimental methods, and the organic matter surface was approximated by grafting oxygenated functional groups onto a graphite surface. The distribution characteristics of a water–methane system in organic matter pores were studied. The results indicate that the organic matter pore network and the inorganic pore network in shales show cross-distribution characteristics. The speed of spontaneous imbibition of oil is less than that of water, and the spontaneous imbibition mass of oil increases with increasing the total organic carbon (TOC) contents. The surfaces of illite and quartz mineral are hydrophilic. With the increase in oxygen-containing functional groups, the interaction energy between the organic matter surface and water molecules decreases, resulting in an increase in the wetting contact angle of the organic matter surface. With increasing temperature, the interaction energy between the organic matter surface and water molecules increases, resulting in a decrease in the wetting contact angle. In symmetrical graphite pore models with different C/O ratios, water molecules are symmetrically spread near the oxygen-functionalized graphite wall, and with a decrease in the C/O ratio, the relative concentration of water molecules increases and the diffusion coefficient decreases. In contrast, methane molecules are gathered and distributed in the center of the pore. In an asymmetric graphite pore model with different C/O ratios, water molecules are asymmetrically spread near the oxygen-functionalized graphite wall, whereas methane molecules are concentrated and spread in the pore center. The side with a lower C/O ratio has stronger hydrophilicity and a higher relative concentration of water molecules, whereas the side with a higher C/O ratio has stronger hydrophobicity and a lower relative concentration of water molecules.

Global Research Trends on Shale Gas from 2010–2020 Using a Bibliometric Approach

In the last few decades, shale gas resources have attracted much global attention as potential sources for clean and affordable energy. Due to this fact, coupled with the increasing energy shortfall, shale gas has become an increasingly attractive energy prospect from both an environmental and economic perspective. This development has led to the rapid growth in the number of researchers and publications in the field of shale gas. Although there are few review articles on the state of research on shale gas, the literature lacked a bibliometric analysis. This study is intended to fill the research gap by carrying out a bibliometric analysis of 9247 shale gas articles that were published between 2010 and 2020. The Web of Science database was used to collect the data. The analysis was performed to identify the most productive authors, institutions, countries, and sources, and to visualize existing collaborations as well as provide valuable information which could form the basis for establishing future collaboration. The analysis results revealed that Li J has the highest number of publications on shale gas whereas Loucks RG is the most cited author. The top three countries with the highest number of publications in shale gas research are China, USA, and Canada, while the China University of Petroleum (Beijing), China University of Geosciences, and Southwest Petroleum University China were the three top institutions with the highest number of publications. Fuel, International Journal of Coal Geology, and Marine and Petroleum Geology are the journals with the highest number of published articles on shale gas. The keyword analysis indicated that shale gas, hydraulic fracturing, pore structure, permeability, adsorption, kinetics, pyrolysis, organic matter, thermal maturity, and numerical simulation are the predominant research topics. This showed the multi-dimensional and multi-faceted character of the shale gas field. Besides, it appeared to be an exciting topic for further study that is based on a detailed evaluation of the shale gas literature. In fact, shale gas, hydraulic fracturing (fracking), CO2 sequestration, kinetic, gas adsorption, diffusion, and simulation are becoming emerging research hotspots. The bibliometric analysis that was presented in this study has revealed valuable information about the most active institutions and countries, and the most influential authors in the field of shale gas which could form the basis for establishing future collaboration. Furthermore, it can help researchers to understand the global research trend in shale gas as well as provide references for establishing future research directions.

Effect of water behaviour on the oil transport in illite nanopores: Insights from a molecular dynamics study

Both of the water injected by hydraulic fracturing and connate water can coexist with oil inside shale nanopores, which leads to different oil/water mixtures behaviors compared to those with only oil and water. However, the behavior of oil/water mixtures in shale pores is not clear. In this study, molecular dynamics simulations are applied to investigate the behavior of oil/water mixtures in a rectangle-shaped illite nanopore that has a hydrophilic internal surface. The behavior of oil/water mixtures is much more complex than that of gas/water mixture because water can dissolve in oil at particular pressures and temperatures. The results of the calculation show that illite confinement has a strong impact on both oil distribution and water adsorption. A structure of the oil droplets being wrapped by water can be identified in the illite nanopores which may be contributed by the hydrophilic surfaces. Besides, water bridges may form due to the dispersion of unabsorbed water into the oil and could increase flow resistance in the pore. Viscosity and self-diffusion of fluids are increased and decreased separately in the nanopores compared to those without the illite confinement which is called the bulk condition in this study. In the bulk condition, increasing the water concentration will reduce the shear viscosity of fluids, while an opposite phenomenon appears in shale nanopores. The results of this study may help to deepen the understandings of water and oil transport in nanopores and provide some guidelines in extracting shale resources in an aqueous environment.

Experimental investigation into the permeability of water vapor in shales

The transport of water vapor in shale (mudrocks) plays an important role in many natural and engineering issues, such as the global water cycle and shale gas production. However, the permeability of water vapor in shale is not well understood. An experimental approach to investigate the water vapor permeability in shale is presented in this paper. Water vapor sorption was conducted under the dynamic relative humidity condition in which the vapor evaporation was generated from the liquid distilled water at different gas (helium) pressures. Three crushed samples of Carboniferous shale from the eastern Qaidam Basin, China, were obtained and tested. In the experiments, the adsorption process of water vapor into the crushed shale was observed, and the permeability of water vapor through shale was calculated with the data collected during the dynamic water vapor adsorption process. The results show that the permeability decreases with increasing water vapor adsorption. The relationship between permeability and water vapor adsorption amount fits an exponential equation well. The permeability at the equilibrium of water vapor adsorption is 3–4 orders of magnitude lower than that in the initial stage of water vapor adsorption. The decrease in pore size and resulting pore throat blockage cause this permeability reduction. The water film thickness and water saturation in the shale pores at adsorption equilibrium were estimated. The permeability reduction is closely related to the maximum water film thickness. The larger the range of pores blocked by the water film is, the more obvious the permeability reduction.

Molecular dynamics study of fluid-fluid and solid-fluid interactions in mixed-wet shale pores

Mixed wet pores are abundant in shales, yet there is little to no information on the behavior of fluids confined within pores characterized by one hydrophilic and one hydrophobic surface. This mixed wettability can impact fluid storage, distribution, capillary pressures and transport. In this study, we use molecular dynamics simulations to describe the initial distribution of reservoir fluids, such as multicomponent hydrocarbon mixtures and water, in mixed-wet pores. This is an essential pre-requisite to additional studies documenting fluid transport in such pores. The molecular model of the mixed wet pore used consists of kerogen separated by some distance from two clay surfaces. We evaluate spatial distribution of water and individual hydrocarbon species, at varying values of water concentration. Throughout the entire study, the results from the equilibrated system indicate a high affinity between the heavy components, such as the asphaltene/resin fraction and the kerogen surfaces. The more surprising result is the hydrogen bonding observed between the polar constituents in the asphaltene/resin fraction and water. This creates a situation where the asphaltene/resin fraction shows an affinity towards water. When this happens, the hydrophilic clay surface effectively becomes hydrophobic. A pore bounded by an asphaltene layer on one side and kerogen on the other is more oil-wetting than mixed-wet. The presence of asphaltenes can therefore expect to create conditions of modified wettability that will impact oil recovery, oil transport and distribution. Another surprising result in this work is that water forms structures that bridge between opposing surfaces of the model. These water bridges are seen to happen for water concentration values larger than 20%. In other words, water is not merely just adsorbed on to the clay surfaces, but also forms these bridge-like structures. Nevertheless, we still observe a strong affinity between the asphaltene/resin fraction and water leading to a lesser degree of mixed wettability. This study is the first, to the best of our knowledge, that considers water and multicomponent hydrocarbon mixtures in mixed-wet pores with realistic surface chemistry and constitutes a necessary first step towards additional studies related to water and hydrocarbon transport and EOR processes in shale nanopores.

Geological Characteristics and Controlling Factors of Enrichment of Deep Shale Gas in the East Weiyuan–North Rongchang Area, Sichuan Basin, China

The southern Sichuan Basin is the core area of China’s efficient development of deep shale gas (burial depth greater than 3,500 m). Reservoir geological characteristics determine whether shale gas can be preserved, enriched, and produced. Taking the Long 11 sub-member of the Wufeng Formation of the Upper Ordovician and the Longmaxi Formation of the Lower Silurian in the East Weiyuan–North Rongchang area as an example, we used the core, logging, production test, and other data, combining X-ray diffraction analysis, LECO Total Organic Carbon (TOC)-S analysis, optical microscopy, and argon ion polishing field-emission scanning electron microscopy, to study the shale mineral composition, geochemistry, reservoir space, pore structure characteristics, and reservoir physical properties. The following results were obtained: 1) The brittle mineral content, organic matter maturity, and TOC content are high, gradually increase from top to bottom, and reach their maxima at small layer 1 of Long 11. 2) Organic pores, inorganic pores, and fractures are important reservoir spaces, among which organic pores and fractures are important seepage channels for shale gas. 3) The shale pore structure revealed by electron microscopy shows that the pore structure in target layers can be divided into four types: unimodal type (mainly organic pores), bimodal type (both organic and inorganic pores), monoclinic type I (mainly organic pores), and monoclinic type II (mainly inorganic pores). The pore morphology is complex, and circular and oval shapes predominate. 4) Sedimentary facies are the main factor controlling the enrichment of shale gas, and the development of fractures is the key to obtaining high yields of shale gas. 5) The class I favorable target area is mainly distributed in wells W206, W206H1, R234H, and R233H and areas to its south, and some areas in the east of the study area.

Research on the Occurrence State of Methane Molecules in Postmature Marine shales—A Case Analysis of the Lower Silurian Longmaxi Formation Shales of the Upper Yangtze Region in Southern China

The Yangtze region in southern China is endowed with abundant marine shale gas. Methane molecules exist in either adsorption state or free state in postmature marine shales, depending on the components of shales. In this study, the core samples of the selected well in the Lower Silurian Longmaxi Fm. shales from the Sichuan Basin, upper Yangtze region, southern China, were taken as study objects. We carried out TOC content, organic matter maturity, mineral component, and core gas content analyses and isothermal adsorption, FIB-SEM, and FIB-HIM experiments to analyze the occurrence state of methane molecules in postmature marine shales. The conclusions are as follows: most methane molecules exist in the organic matter pores of the postmature marine shales, and only a small amount of them exist in clay mineral pores. The organic matter pores in organic-rich shales are large in number with excellent roundness and are well connected, with large pores covering small ones. Thus, abundant free gas can be stored in the organic matter pores and pore throats, making it possible to densely and continuously adsorb methane molecules with a relatively large adsorption space. The flake-shaped clay minerals have a small number of pores with low roundness. Among the three clay minerals in postmature marine shales of the Longmaxi Fm., the I/S mixed layer offers certain reservoir spaces for adsorbed and free gases and chlorite stores a little adsorbed gas and little free gas, while illite hardly stores the adsorbed gas but contains a little free gas.

Novel approach to improve shale stability using super-amphiphobic nanoscale materials in water-based drilling fluids and its field application

Abstract In this study, super-amphiphobic nano-silica nanoparticles (SA-NPs) were used to enhance the shale stabilization performance of water-based drilling fluids (WBDFs) by altering the surface wettability, preventing the capillary self-priming effect, and plugging the nano-micro pores of shale. The results of transmission electron microscopy, particle size distribution, and scanning electron microscopy characterization revealed that SA-NPs exhibited a nanoscale “coalesce” structure, which is composed of spherical particles joined together, and could form a nano-papillary structure on the shale surface. Due to the presence of nano-micro scale rough structures and ultra-low surface energy components, the shale treated by SA-NPS exhibited super-amphiphobic surface property in the contact angle test. Contact angles of water and hexadecane on the shale surface reached up to 154.13° and 151.34° after being treated with SA-NPs, respectively. Furthermore, the addition of 1% SA-NPs in WBDFs could reduce the linear swelling rate from 40.5 to 6.0%, increase the shale cuttings recovery percentages from 82.5 to 95.6%, increase the plugging rate of low permeability shale core from 81.25 to 94.00%, and raise the high-temperature and high-pressure uniaxial compressive strength from 3.45 to 4.87 MPa. Compared with the polyether amine and fumed nano-silica, the addition of SA-NPs produced the best performance. Based on the excellent shale stabilization performance of SA-NPs, a high-performance WBDF was developed and applied in Dagang Oilfield. During the drilling operation， no wellbore instability, sticking, and other complex situations occurred. The results indicate that SA-NPs could better address the issue of wellbore instability in shale formations and have a great application prospect in shale well drilling.

Origin of organic matter and organic pores in the overmature Ordovician-Silurian Wufeng-Longmaxi Shale of the Sichuan Basin, China

Organic matter (OM)-hosted pores play important roles in controlling the porosity and gas content of gas shales. However, the control of organic pore development and preservation remains poorly understood, partly because of the inability to distinguish OM types under the scanning electron microscope (SEM). In this study, seven over-mature Wufeng-Longmaxi Shale samples (equivalent vitrinite reflectance 1.93%–3.07%) were investigated with organic petrography and scanning electron microscope to study the origin of OM and development of organic pores in this black shale succession. Correlative light and electron microscopy was employed to examine pore development in individual macerals. Organic petrographic observations show that OM in these over-mature black shales is dominated by pyrobitumen and graptolites (> 90 vol% of total OM based on point counting). Pyrobitumen mainly occurs as matrix bitumen in the fine-grained matrix, and also as a mixture with clay minerals and fossil cavity infillings. Vitrinite-like particles are minor constituents of OM in the Wufeng-Longmaxi Shale, and their average reflectance, reflectance distribution, and morphology suggest that they may be derived from graptolite fragments lacking diagnostic features and acritarchs. OM type critically controls the development of organic pores. Organic pores primarily occur in pyrobitumen, whereas other macerals are mostly non-porous when examined under the SEM. Results of this study provided important insights into OM thermal evolution and organic pore development in source-rock reservoirs, calling for a critical appraisal of OM in black shales with organic petrography in addition to SEM.

Depositional Structures and Their Reservoir Characteristics in the Wufeng–Longmaxi Shale in Southern Sichuan Basin, China

This paper documents depositional structures and their reservoir characteristics in the Wufeng–Longmaxi shale from outcrops and cores using thin sections, X-ray powder diffraction (XRD) analysis, carbon–sulfur analyzer, helium porosimeter, decay permeameter, and focused ion beam scanning electron microscope (FIB-SEM). In the study area, clayey and silty laminae abound in the shale. Clayey laminae are rich in bedding parallel fractures, microfractures, and organic pore networks. Silty laminae are rich in isolated inorganic pores and limited amounts of bedding non-parallel fractures. Various inter-lamination of clayey and silty laminae form five depositional structure types which are closely related to the ancient hydrodynamics, paleoredox condition, and sedimentation rate and have significant impacts on shale fractures, microfractures, pore types, pore-size distribution, and porosity. For the paper lamination (PL) and grading lamination composed of siltstone and claystone (GL-SC), organic pores account for 71.6% and 61.4% of the total, and dense bedding parallel and non-parallel fractures intersect to form connective networks. In the interlaminated lamination composed of siltstone and claystone (IL), grading lamination composed of claystone (GL-C) and structureless beds (SB), organic pores merely account for 20% to 51.8% of the total and minor isolated bedding parallel fractures occur. Among five depositional structure types, the PL and GL-SC have the highest porosity, permeability, TOC content, siliceous content, organic pore proportions, and ratios of horizontal to vertical permeability, which help them become shale gas exploration and development targets.

Modified LB model for simulation of gas flow in shale pore systems by introducing end effects and local effective mean free path

Natural gas flow in shale pore systems determines the accumulation and production of shale gas. Under the conditions of reservoir, gas flow in such shale pores is significantly different from that in conventional reservoirs. Studies of gas flow under such conditions are usually limited to simple pore models with tube/slit geometries or bundle of tubes/slits, which constructs important theoretical basis, however, cannot represent the pore networks of shales. For directly simulating gas flow in complex media, we proposed a modified microscale lattice Boltzmann (MM-LB) model, in which the local effective mean free path (MFP) at any location of the pore system with complex geometry corrected by a custom two-dimensional (2D) eight-direction wall function was considered to capture the effective relaxation time for each lattice node in LB model. What's more, to consider slip velocity at solid boundaries, a combined bounce-back specular-reflection (BSR) scheme was adopted. The MM-LB model was firstly validated in 2D pore systems with simple slit/channel geometries and complex geometries (square and triangular cylinder flows) and in a 3D Sierpinski carpet, where good agreements with linearized Boltzmann solutions, molecular dynamics (MD) simulation and the direct simulation BGK (DSBGK) method results were found. Using the MM-LB model, we quantified the end effect on gas flow through pore throat and found that the end effect is caused by not only the streaming bending but also the variance of MFP (i.e., viscosity) throughout the pore throat. Finally, we applied this model to simulate shale gas flow in three digital reconstructions of kerogen pore systems and compared the results of apparent permeability prediction with Klinkenberg model and Beskok-Karniadakis (B–K) model. It is showed that the apparent permeability of gas flow in shales decreases with the decrease of temperature or the increase of pressure, and the pressure has a greater effect than temperature. For similar pore structures, the apparent permeability increases with the width of pore body and pore throat, especially the pore throat, which dominates the overall flow velocity of the entire flow field. According to the comparison and analysis of the results of MM-LB model with Klinkenberg and B–K model, it can be inferred that permeability prediction based on models of tube/slit (or bundle of tube/slit) pores misestimate the apparent permeability due to ignoring the connectivity and the end effect, especially for the conditions of lower pressures and nanoscale pore spaces.

Competitive adsorption characteristics based on partial pressure and adsorption mechanism of CO2/CH4 mixture in shale pores

• Gas partial pressure is the decisive factor under certain temperature and pore size. • Each adsorption layer of mixture gas can be explained by monolayer adsorption theory. • Appropriate timing and amount of CO 2 injection were proposed for CS-EGR technology. In the context that CS-EGR technology has received more and more attention, molecular dynamics simulation method was used to analyze the competitive adsorption characteristics and mechanism of CO 2 /CH 4 mixture in graphene-MMT heterogeneous surface pores. In the case of certain temperature and pore size, the gas partial pressure of mixture is found to be the decisive factor of the competitive adsorption behavior. It’s better to describe the competitive adsorption behavior by gas partial pressure. Langmuir equation was applied to fitting adsorption isotherm in the first adsorption layer and the second adsorption layer. The good fitting results indicate that although the competitive adsorption mechanism of CO 2 /CH 4 mixture can’t be considered as monolayer adsorption due to the existence of multiple adsorption layers, each adsorption layer can be explained by Langmuir adsorption theory. To enhance the CH 4 recovery and CO 2 storage, the appropriate timing and amount of CO 2 injection were proposed. The pressure should be reduced to as low as possible in the first pressure drawdown process, because the first pressure drawdown is obviously beneficial to CH 4 production. The Ratio should be controlled not to exceed 1.11 ∼ 1.21 when injecting CO 2 . The operation recommendations can effectively enhance the shale gas recovery and CO 2 storage and may help to optimize the design of CS-EGR technology.

Pore network modeling of oil and water transport in nanoporous shale with mixed wettability

Hydraulic fracturing is an effective means for the economic development of shale oil reservoirs. A large volume of water is introduced into the shale matrix during hydraulic fracturing, which leads to the subsequent oil-water two-phase flow in the shale reservoir. The fluid flow behaviors in shale are still ambiguous due to the nonnegligible nanoconfinement effect caused by the omnipresent nanoscale pores and the heterogeneities of mineral types, pore size and wettability of shale. In this study, both the single-phase and oil-water two-phase flow behaviors at pore-scale considering nanoconfinement effects, dual-wettability and pore space characteristic of shale reservoir were investigated using the pore network modeling (PNM) method. We constructed the three-dimension shale digital rock based on scanning electron microscope (SEM) images and extracted the pore network model. The modified single nanotube flow equations considering the adsorption and slip effects were incorporated with the shale pore network model to investigate the single-phase flow at different volumetric total organic content (TOC). Oil-water two-phase flow and relative permeability at different TOC in volume were computed by quasi-static method with consideration of nanoconfinement effect. Results indicated that the TOC and wettability are the primary factors affecting the single-phase flow in shale. Slip effect enhanced the flow capacities of both single-phase water and oil. The wettability effect on two-phase relative permeability curve was not as notable as that on single-phase flow. Oil-water two-phase relative permeability curves were significantly affected by TOC. The two-phase flow region narrows down with the increase of volume TOC, indicating more oil is trapped and thus cannot be displaced. This work provided important insights on pore-scale fluid transport behaviors in shale.