Shale Pore Research Articles

A FRACTAL-BASED OIL TRANSPORT MODEL WITH UNCERTAINTY REDUCTION FOR A MULTI-SCALE SHALE PORE SYSTEM

The challenges of modeling shale oil transport are numerous and include strong solid-fluid interactions, fluid rheology, the multi-scale nature of the pore structure problem, and the different pore types involved. Until now, theoretical studies have not fully considered shale oil transport mechanisms and multi-scale pore structure properties. In this study, we propose a fractal-based oil transport model with uncertainty reduction for a multi-scale shale pore system. The fractal properties of the shale pore system are obtained using high-resolution scanning electron microscope (SEM) imaging combined with laboratory core sample gas permeability measurements to reduce the model uncertainty. This fractal-based oil transport model accounts for boundary slippage, fluid rheology, the adsorption layer, and different pore types. We further pinpoint the effects of the fractal properties (pore fractal dimension, tortuosity fractal dimension), the shale pore properties (pore type, pore size, total organic carbon in volume), and the fluid properties (yield stress, liquid slippage, adsorption layer) on the shale oil permeability and mobile oil saturation using the proposed model. The results reveal that the size of the inorganic pores has the largest influence on the shale oil transport properties, followed by the yield stress, tortuosity fractal dimension, and the fractal dimension of the inorganic pores.

Molecular Dynamics Numerical Simulation of Adsorption Characteristics and Exploitation Limits in Shale Oil Microscopic Pore Spaces

Molecular Dynamics Numerical Simulation of Adsorption Characteristics and Exploitation Limits in Shale Oil Microscopic Pore Spaces

Diagenetic characteristics and microscopic pore evolution of deep shale gas reservoirs in Longmaxi Formation, Southeastern Sichuan basin, China

The Lower Silurian Longmaxi Formation is the favorable target area for deep shale gas exploration and development in southeastern Sichuan Basin. Based on whole-rock X-ray diffraction analysis, scanning electron microscope, reservoir evolution thermal simulation experiment and nitrogen adsorption experiment, the diagenetic characteristics of deep shale reservoir in Longmaxi Formation were analyzed, and the reservoir pore evolution law was clarified. The results show that: ①The diagenetic minerals of the deep shale in the Longmaxi Formation are mainly quartz and clay minerals, with a small amount of carbonate minerals and feldspar. The primary inorganic pores are mainly controlled by mechanical compaction and cementation (quartz, carbonate, clay, pyrite). The organic pores are mainly controlled by the thermal maturity of organic matter, dissolution and later compaction. ②In the process of thermal simulation experiment, the organic pores of shale show a process of change from scratch, from small to large and then from large to small. Later, the organic matter is affected by compaction and graphitization, and the volume of micropores and mesopores begins to decrease. ③The shale pores of Longmaxi Formation have undergone several evolutionary stages. In the early stage of diagenesis, compaction caused a large number of inorganic pores to disappear. In the middle stage of diagenesis, kerogen hydrocarbon generation occupied pores, dissolution and cementation transformed pores. In the late diagenetic period, liquid hydrocarbon cracking gas and pressurization promote the development of organic pores.

Evolution of pore systems in low-maturity oil shales during thermal upgrading—Quantified by dynamic SEM and machine learning

In-situ upgrading by heating is feasible for low-maturity shale oil, where the pore space dynamically evolves. We characterize this response for a heated substrate concurrently imaged by SEM. We systematically follow the evolution of pore quantity, size (length, width and cross-sectional area), orientation, shape (aspect ratio, roundness and solidity) and their anisotropy—interpreted by machine learning. Results indicate that heating generates new pores in both organic matter and inorganic minerals. However, the newly formed pores are smaller than the original pores and thus reduce average lengths and widths of the bedding-parallel pore system. Conversely, the average pore lengths and widths are increased in the bedding-perpendicular direction. Besides, heating increases the cross-sectional area of pores in low-maturity oil shales, where this growth tendency fluctuates at < 300 °C but becomes steady at > 300 °C. In addition, the orientation and shape of the newly-formed heating-induced pores follow the habit of the original pores and follow the initial probability distributions of pore orientation and shape. Herein, limited anisotropy is detected in pore direction and shape, indicating similar modes of evolution both bedding-parallel and bedding-normal. We propose a straightforward but robust model to describe evolution of pore system in low-maturity oil shales during heating.

Mobility of connate pore water in gas shales: A quantitative evaluation on the Longmaxi shales in the southern Sichuan basin, China

Flowback and produced water is causing water environment pollution and elevated disposal costs during the shale gas development. Due to high salinity and variously hazardous substances in the connate pore water (i.e., initial water storing in shale matrix pores), whether the connate pore water is produced in company with fracking water flowback has long been concerned. The key is to determine the mobility of connate pore water, which is closely associated with the occurrence of adsorbed and free water in shale pores. In this study, five fresh shale samples were obtained from the Longmaxi Formation shale gas reservoirs in the southern Sichuan basin of China to evaluate the mobility of connate pore water. Theoretical models of describing the non-equilibrium and equilibrium expulsion processes of connate pore water from shale matrix were proposed. On this of basis, the amounts and microscopic distributions of adsorbed and free water in the shales were determined by using centrifugation and nuclear magnetic resonance (NMR) tests under atmospheric pressure and 30 °C temperature condition. Results show that: (1) the amounts of adsorbed and free water in the shales varies from 5.9132 to 8.3442 mg/g (mean 7.3842 mg/g) and 2.1224–5.7931 mg/g (mean 3.9507 mg/g), respectively. The amount of free water (i.e., maximum mobile water amount) accounts for 23.69–41.37 wt% (mean 34.12 wt%) of total water, indicating that about one-third of the connate pore water in gas shales is potentially recoverable. (2) The connate pore water in the adsorbed and free states mainly distributes in the pores of 0.5–10 nm, of which the adsorbed water mainly distributes in the pores of 0.5–3 nm and the free water (i.e., mobile water) mainly stores in the pores of 3–10 nm. (3) The mobility index, that is the ratio of free water amount to mid-value pressure difference, was introduced to quantify the mobility of connate pore water by considering the equilibrium expulsion process of pore water. The mobility index of connate pore water in fresh shales is negatively related to the water-adsorbed ratio. This study contributes to identifying the source of flowback and produced water and is also significant to water environment.

Log-exponential transformation function for interpreting NMR relaxation measurements of hydrocarbon in organic porous media for enhancing absolute adsorption estimation

Assessing unconventional petroleum resources, particularly shale gas reserve estimation, is challenging due to the adsorption phenomenon. This study presents a new method combining experimental and mathematical procedures to determine the absolute adsorption amount in shale samples. In the experimental section of this study, a new behavior was observed in the NMR decay time series of hydrocarbons in organic porous media. The fast section has a linear relationship with time rather than an exponential one. As a result, a Log-Exponential fit to these decay curves was proposed. Then the logarithmic portion was then used to estimate the absolute adsorbed amount. The method was validated against literature data and conventional methods.Based on this newly developed method, absolute adsorption isotherms were obtained for a Duvernay shale sample and activated carbon packs at pressures ranging from 0.77 MPa to 7 MPa. The model proved to be applicable and consistent with pressure variations. Methane in Duvernay shale exhibited adsorbed isotherm type V, with a methane adsorption capacity of 0.08 g per gram of Total Organic Content (TOC) at 6.24 MPa.In addition to absolute adsorption, the competitive adsorption of methane and CO2 was explored, which is critical for evaluating CO2-enhanced shale gas recovery and storage techniques. The injected CO2 resulted in the displacement of methane from smaller shale pores to larger ones.Adsorption and desorption experiments were conducted to investigate hysteresis. The new method was able to better describe the physical behavior of gaseous hydrocarbons in organic porous media. It was able to capture phase transition and critical pressure specific to organic porous media, which differ from non-organic porous media. This innovative approach enables the accurate characterization of shale reservoirs.

Ultrahigh-Resolution Reconstruction of Shale Digital Rocks from FIB-SEM Images Using Deep Learning

Summary Accurate characterization of shale pore structures is of paramount importance in elucidating the distribution and migration mechanisms of fluids within shale rocks. However, the acquisition of high-resolution (HR) images of shale rocks is limited by the precision of the scanning equipment. Even with higher-precision devices, compromising the image field of view becomes inevitable, making it challenging to faithfully represent the actual conditions of shale. We propose a stepwise 3D super-resolution (SR) reconstruction method for shale digital rocks based on the widely used focused-ion-beam scanning electron microscope (FIB-SEM) technique. This method effectively addresses the issues of inconsistent horizontal and vertical resolutions as well as low 3D image resolution in FIB-SEM images. By adopting this approach, we significantly enhance image details and clarity, enabling successful observations of pores smaller than 10 nm within shale and laying a foundation for further pore-scale flow simulations. Furthermore, we extract the pore network model (PNM) from the SR reconstructed digital rock to analyze the pore size distribution, coordination number, and pore-throat ratio of shale samples from the Jiyang Depression. The results demonstrate a pore radius distribution in the range of 0 nm to 40 nm, which aligns with the results from nitrogen adsorption experiments. Notably, pores with radii smaller than 10 nm account for 50% of the total connected pores. The proportion of isolated pores in the SR reconstructed shale PNM is significantly reduced, with the coordination number mainly distributed between 1 and 4. The pore-throat ratio of shale ranges from 1 to 3, indicating a relatively uniform development of pores and throats. This study introduces a novel method for accurately characterizing the shale pore structure, which aids researchers in evaluating the pore size distribution and connectivity of shales.

Differential Development Mechanisms of Pore Types under the Sequence Stratigraphic Constraints of the Wufeng–Longmaxi Formation Shale from the Upper Yangtze Platform

Various types of pores, including organic and inorganic variations, exhibit distinct impacts on the storage capacity of shale gas reservoirs and play a significant role in shale gas occurrence. However, there is a limited number of studies that have quantitatively addressed the developmental characteristics of these diverse pore types and their primary controlling factors. This paper explores the development of inorganic pores, specifically interparticle pores and intraparticle pores, as well as organic matter (OM) pores within the shales of the Wufeng–Longmaxi Formation in the Upper Yangtze region. Parameters such as areal porosity, pore diameter, and pore number based on the FE-SEM and image digitization are discussed. Additionally, the influence of the sedimentary environment on the development of various pore types through integrated wavelet transform techniques and geochemical analysis are analyzed. This analysis reveals the distinctive mechanisms governing the development of pore types under the sequence stratigraphic constraints. The findings reveal that the Wufeng–Longmaxi Formation within the study area can be classified into four systems tracts (transgressive systems tracts TST1 and TST2, and highstand systems tracts HST1 and HST2). Within TST1+HST1, OM pores emerge as the predominant pore type, contributing to over 65% of the porosity. TST2 similarly displays OM pores as the dominant type, comprising over 45% of the total porosity, with an average OM areal porosity of 7.3%, notably lower than that of TST1+HST1 (12.7%). Differences in OM pore development between TST1+HST1 and TST2 shales are attributed to variations in OM abundance and type. In HST2, inorganic pores are the dominant pore type, primarily consisting of interparticle pores associated with clay minerals, contributing to more than 50% of the porosity, while OM pores remain almost undeveloped. The frequent sea level fluctuations during the sequence stratigraphic evolution caused variations in sedimentary environments across different depositional sequences. These differing depositional environments lead to varying OM content and types, mineral genesis, and content, ultimately resulting in disparities in the development of shale pore types within different sequences.

Shale primary porosimetry based on 2D nuclear magnetic resonance of T1-T2

Porosity, a key parameter in assessing the physical properties of shale reservoirs and the reserves, is of great significance to the selection and evaluation of shale sweet spots. There are many methods at present to characterize shale porosity, most of which are aimed at post-core cleaning shale, such as those involving helium and saturated fluid (namely liquid-involved porosimetry). However, due to the low efficiency of shale core cleaning and the possible damage to pore structure during the core cleaning process, it's hard to guarantee the accuracy of porosity measurement. In this regard, we resort to the two-dimensional (2D) nuclear magnetic resonance (NMR) technology of T1-T2 in characterizing the primary shale porosity with samples taken from pressure coring in the 4th member of Shahejie Formation (Sha 4 Member) in well Fanxie 184 in the Jiyang Depression. Moreover, comparative experiments of shale porosity measurement by three methods, namely the simultaneous distillation extraction (SDE), helium and fluid measurement, are carried out simultaneously. The results show that the values obtained by SDE, gas and liquid measurement are similar, which are about 0.6 times of 2D NMR porosimetry. Core cleaning efficiency tends to seriously affect the results involving gas and liquid. In addition, the core cleaning treatment is bound to change the shale pore structure, and this is especially true in clay which tends to swell; consequently, porosity results are to be distorted by gas and liquid methods. It is thereby recommended to utilize the 2D NMR technology to characterize the primary total porosity of shale samples without core cleaning. The effective porosity of samples from pressure coring is determined by T2 cutoff value of around 0.3 ms.

Experimental Water Activity Suppression and Numerical Simulation of Shale Pore Blocking

The nanoscale pores in shale oil and gas are often filled with external nanomaterials to enhance wellbore stability and improve energy production. And there has been considerable research on discrete element blocking models and simulations related to nanoparticles. In this paper, the pressure transmission experimental platform is used to systematically study the influence law of different water activity salt solutions on shale permeability and borehole stability. In addition, the force model of the particles in the pore space is reconstructed to study the blocking law of the particle parameters and fluid physical properties on the shale pore space based on the discrete element hydrodynamic model. However, the migration and sealing patterns of nanomaterials in shale pores are unknown, as are the effects of changes in particle parameters on nanoscale sealing. The results show that: (1) The salt solution adopts a formate system, and the salt solution is most capable of blocking the pressure transmission in the shale pores when the water activity is 0.092. The drilling fluid does not easily penetrate into the shale pore space, and it is more capable of maintaining the stability of the shale wellbore. (2) For the physical blocking numerical simulation, the nanoparticle concentration is the most critical factor affecting the shale pore blocking efficiency. Particle size has a large impact on the blocking efficiency of shale pores. The particle diameter increases by 30% and the pore-blocking efficiency increases by 13% when the maximum particle size is smaller than the pore exit. (3) Particle density has a small effect on the final sealing effect of pore space. The pore-plugging efficiency is only increased by 4% as the particle density is increased by 60%. (4) Fluid viscosity has a significant effect on shale pore plugging. The increase in viscosity at a nanoparticle concentration of 1 wt% significantly improves the sealing effectiveness, specifically, the sealing efficiency of the 5 mPa-s nanoparticle solution is 16% higher than that of the 1 mPa-s nanoparticle solution. Finally, we present a technical basis for the selection of a water-based drilling fluid system for long horizontal shale gas drilling.

Micropore Structure Characteristics and Recoverability Evaluation of Typical Shale Oil Reservoirs

Abstract In view of the weak research on the availability of typical shale oil reservoirs from the perspective of development, this study introduced a two-dimensional nuclear magnetic resonance (NMR) evaluation method on the basis of the previous one-dimensional NMR combined with centrifugal physical simulation experiments. Not only the production characteristics of typical shale oil reservoirs were studied but also the microscopic production laws of different occurrence states were studied. The results show that the pore distribution of Jilin shale is more concentrated than that of Qinghai shale. The oil of the two blocks mainly occurs in 0.01–10 ms pores, and the occurrence ratio of Jilin shale in the pores is higher, which is more than 90%. The oil production of the two blocks is mainly dominated by 0.01–10 ms pores, and the utilization efficiency contribution of these pores in Jilin shale is higher, accounting for about 80%. The utilization efficiency (UE) increases logarithmically with centrifugal force, and the growth rate of Jilin shale is greater than that of Qinghai shale. The proportion of free oil in Jilin block is less than that in Qinghai block. The shale oil in the two blocks is both at 15% final UE, and the UE of free oil in Jilin shale is about 9% and that of Qinghai shale is about 12%. The recoverability of Jilin shale is lower than that of Qinghai shale.

Synthesis and properties of a novel ionic liquid copolymer shale inhibitor

AbstractAs oil reserves in shallow wells continue to deplete, the drilling industry must shift its focus toward extracting oil from deeper and more complex formations. Water‐based drilling fluid inhibitors are currently limited in their ability to withstand high temperatures. In the current work, for the first time, the application of 1‐vinyl‐3‐ethylimidazolium bromide salt‐allyl alcohol polyoxyethylene ether‐2‐acrylamide‐2‐methylpropanesulfonic acid (PIAA) as the shale inhibitor is reported. The incorporation of ionic liquids has made PIAA promising to be an effective shale inhibitor for high‐temperature‐tolerant water‐based drilling fluids. The high‐temperature resistance (300°C) of PIAA was verified through thermogravimetric test. Through mud ball, shale rolling recovery, and linear swelling experiments, we found that PIAA yielded the lowest swelling rate (27.3%) in the 24‐h linear swelling rate test, as compared to HMA‐15 (46.1%) and FA‐367 (31.2%). This confirmed the superior corrosion inhibition performance of PIAA. In addition, we investigated the inhibition mechanism using Zeta potential and other tests. Bentonite inhibition can be achieved through the coating of bentonite particles by PIAA, which effectively plugs shale pores, neutralizes negative charges on the surface of bentonite particles, and adsorbs them onto particle surfaces. Overall, PIAA has excellent high‐temperature resistance and inhibition properties.

Pore structure and oil‐bearing property of laminated and massive shale of Lucaogou Formation in Malang Sag, Santanghu Basin

Exploration and development effects of Lucaogou Formation laminated shale are not ideal in the Santanghu Basin, and the reasons are not clear. Therefore, in this study, laminated and massive shales were systematically sampled, and experiments of cryogenic adsorption of nitrogen and multi‐dimensional nuclear magnetic resonance comparison were carried out. The results show that Lucaogou Formation shale is rich in volcanic ash and low content of clay, which can be divided into tuff, dolomite, tuffaceous dolomite, dolomitic tuff, and other lithologic types. The laminar structure is developed in tuffaceous dolomite and dolomitic tuff. The pores of Lucaogou Formation shale with a diameter of more than 10 nm can be used as an effective storage space for movable oil. The oil saturation and mobile oil ratio of laminated shale are lower than that of massive shale. Movable oil is controlled by carbonate content, and the higher the content, the higher the proportion of movable oil. Millimetre laminae are rich in organic matter and have poor interlaminar pore connectivity, which leads to strong adsorption capacity for oil. Therefore, the migration of oil between laminae is blocked, and oil mainly distributes or migrates in the bedding plane between laminae in laminated shale, which cannot be used as favourable reservoirs.

Evolution of organic pores in Permian low maturity shales from the Dalong Formation in the Sichuan Basin: Insights from a thermal simulation experiment

Shale oil and gas exploration is greatly impacted by the development and evolution of organic pore structures. In order to study the evolution of shale pore structures over maturities, we conducted thermal simulation experiments on low-mature organic-rich shale (Ro = 0.73%, TOC = 9.57%) obtained from the Dalong Formation. Various maturity stages were covered in these experiments, from low to over-maturity. By analyzing mineral composition, organic geochemistry, and characteristics of pore structures at various temperatures used for thermal simulation, we examined how organic matter pores generate and evolve during the formation of shale hydrocarbons. As a result, an integrated model of the evolution of pore structures in organic-rich shale was developed. Our study revealed the following insights: With increasing thermal simulation temperature, shale pore development exhibited three distinct stages: initial development, rapid development, and slow development. These stages correspond respectively to the three stages of organic matter thermal evolution. The distribution of pores in the shale transitioned from a unimodal structure dominated by larger pores to a bimodal structure with both micropores and macropores. Decomposition of organic matter and pressure compaction play a controlling role on organic porosity. Pore structure parameters and fractal dimensions of the pores were primarily influenced by organic matter decomposition, residual liquid hydrocarbons, and diagenetic processes. Additionally, kerogen type, morphology of organic matter debris, symbiosis of minerals-organic matter also impacted pore development.

Influence of Mineralogy, Organic Matter and Thermal Maturity on the Diagenetic Evolution of Pore Systems in the Shales of Cambay and Raniganj Basin, India

Abstract The mineral composition, organic matter, thermal maturity, and diagenesis control the shale reservoir properties, including the pore distribution, variable fluid distribution, microstructure, heterogeneity, etc. The shale layers of the Cambay Formation and the Raniganj Formation are considered prospective shale gas resources in India. This paper focuses on the detailed analysis of shale from the Cambay Formation (Eocene age) of the Cambay Basin and the Raniganj Formation (Permian age) of the Raniganj Basin, India. The whole rock X-ray diffraction data indicates that quartz is the dominant mineral in both the shales (Raniganj and Cambay shale) of the Raniganj and the Cambay Basin. The main clay minerals are clinochlore, smectite-kaolinite, illite, and kaolinite in the Raniganj shale, while kaolinite, montmorillonite, and illitesmectite are the dominant clay minerals in the Cambay shale. The total organic content (TOC) ranges from 4.97 to 17.88 wt.% and 1.16-7.6% in the Raniganj and Cambay shales respectively. For the studied shale section, the TOC shows a gradual decrease with respect to depth in both shale types. The Raniganj shale has 3.8 to 8.3 percent total porosity, and the Cambay shale contains 1.16 to 6.5% total porosity. The increasing thermal maturity with the higher TOC corresponds to the more developed organic pores in the Raniganj shale. In contrast, the secondary pores are developing in the Cambay shale due to dissolution activities and enhancing the storage capacity. The study infers that the mineral composition and diagenesis are playing a crucial role in the pore system evolution of the shale in both the basins.

Investigation of the Effect of Fracturing Fluids on Shale Pore Structure by Nuclear Magnetic Resonance

Hydraulic fracturing technology significantly enhances the productivity of shale oil and gas reservoirs. Nonetheless, the infiltration of fracturing fluid into shale formations can detrimentally affect the microscopic pore structure, thereby impairing the efficacy of hydraulic stimulation. In this study, nuclear magnetic resonance (NMR) technology was utilized to conduct high-pressure soaking tests on shale specimens treated with EM30+ + guar gum mixed water and CNI nano variable-viscosity slickwater, where various concentrations of a drag reducer were utilized. Additionally, the differences in porosity, permeability, mineral composition, and iron ion concentration before and after the measurements were compared, which were used to analyze the influence on the shale’s microscopic pore structure. It features a reduction in the total pore volume after the interaction with the fracturing fluid, with the pore-throat damage degree, porosity damage degree, and permeability damage degree ranging from 0.63% to 5.62%, 1.51% to 6.84%, and 4.17% to 19.61%, respectively. Notably, EM30+ + guar gum mixed water exhibits heightened adsorption retention, alkaline dissolution, and precipitation compared to CNI nano variable-viscosity slickwater, rendering it more deleterious to shale. Moreover, higher concentrations of drag reducers, such as EM30+ or CNI-B, predominantly result in damage to the shale’s micropores. Shale compositions characterized by lower content of quartz and elevated proportions of clay minerals and iron-bearing minerals showcase augmented mineral dissolution and precipitation, consequently intensifying the shale damage. The hydration expansion of mixed-layer illite/smectite profoundly diminishes the core permeability. Consequently, the mechanisms underpinning the damage inflicted on shale’s microscopic pore structure primarily involve fracturing fluid adsorption and retention, mineral dissolution, and precipitation, such as clay minerals and iron-containing minerals.

Impacts of Pore Structure on the Occurrence of Free Oil in Lacustrine Shale Pore Networks

The ultimate recovery of shale oil is mostly dependent upon the occurrence and content of free oil within the nano-scaled pore network of shale reservoirs. Due to the nanoporous nature of shale, quantitatively characterizing the occurrence and content of free oil in shale is a formidable undertaking. To tackle this challenge, 12 lacustrine shale samples with diverse organic matter content from the Chang7 Member in the southern Ordos Basin were selected, and the characteristics of free oil occurrence were indirectly characterized by comparing changes in pore structure before and after organic solvent extraction. The free oil enrichment in shale was assessed using the oil saturation index (OSI), corrected oil saturation index (OSIcorr), and percentage of saturated hydrocarbons. The results revealed that slit-like interparticle pores with diameters less than 30 nm are dominant in the Chang7 shale. Conceptual models for the pore structures containing free oil were established for shale with total organic carbon (TOC) content less than 9% and greater than 9%, respectively. Shale samples with TOC content less than 9% exhibit a well-developed pore network characterized by relatively larger pore volume, surface area, and heterogeneity. Conversely, shale samples with TOC content exceeding 9% display a less developed pore network characterized by relatively smaller pore volume, surface area, and heterogeneity. Larger pore volume and lower organic matter abundance favor the enrichment of free oil within the lacustrine shale pore network. This study may have significant implications for understanding oil transport in shales.

The Effect of Thermal Maturity on the Pore Structure Heterogeneity of Xiamaling Shale by Multifractal Analysis Theory: A Case from Pyrolysis Simulation Experiments

Shale oil and gas, as source-reservoir-type resources, result from organic matter hydrocarbon generation, diagenesis, and nanoscale pore during the evolution processes, which are essential aspects of shale gas enrichment and reservoir formation. To investigate the impact of diagenetic hydrocarbons on shale pore heterogeneity, a thermal simulation of hydrocarbon formation was conducted on immature shale from the Middle Proterozoic Xiamaling Formation in the Zhangjiakou area, covering stages from mature to overmature. Nuclear magnetic resonance (NMR) instruments analyzed the microstructure of the thermally simulated samples, and the multifractal model quantitatively assessed pore development and heterogeneity in the experimental samples. The results reveal that the quartz and clay mineral contents show alternating trends with increasing temperature. Organic matter dissolution intensifies while unstable mineral content decreases, promoting clay mineral content development. Pyrolysis intensity influences Total Organic Carbon (TOC), which reduces as hydrocarbons are generated and released during simulation. Porosity exhibits a decreasing–increasing–decreasing trend during thermal evolution, peaking at high maturity. At maturity, hydrocarbon generation obstructs pore space, resulting in higher levels of bound fluid porosity than those of movable fluid porosity. Conversely, high maturity leads to many organic matter micropores, elevating movable fluid porosity and facilitating seepage. Shale pore heterogeneity significantly increases before 450 °C due to the dissolution of pores and the generation of liquid and gas hydrocarbons. In the highly overmature stage, pore heterogeneity tends to increase slowly, correlated with the generation of numerous micro- and nano-organic matter pores.

Nanopore Structure and Multifractal Characteristics of Continental Shale Oil Reservoir: A Case Study from Ziliujing Shales in the Sichuan Basin

Thermal maturity of the shales from the Ziliujing Formation of the Jurassic age in the Sichuan Basin is in the hydrocarbon generation window, which makes it a candidate for shale oil and gas development. The meso- and macropore characteristics and heterogeneity of shales are important factors affecting the occurrence and development of oil and gas. However, the meso- and macropores of the Ziliujing shales have not been systematically studied. Thus, the mineral compositions and total organic carbon (TOC) of samples from this formation, as well as its pore structure, are analyzed by low-temperature N2 adsorption technique. Moreover, the heterogeneity of the pores was determined by multifractal analysis. The results show that the Ziliujing shales can be classified into three types according to the distributions of mineral compositions of carbonate and mixed and argillaceous shales. Results revealed that the smallest meso- and macropore volume (PV), the smallest specific surface area (SSA), and the largest average pore diameter (APD) occur in the carbonate shales. However, the largest PV and SSA and the smallest APD are observed in the argillaceous shales. The porosity of carbonate shales is mainly concentrated between 5 nm and 30 nm. Compared with carbonate shales, the porosity with pore sizes less than 30 nm of mixed and argillaceous shales shows a rapid increase. Furthermore, inorganic minerals are the main factors affecting the pore distributions, while TOC shows a weak effect. Herein, clay minerals significantly increase the mesopore volume and the pore number with a size of less than 30 nm. The Dq-q curves reveal that the meso- and macropore distributions of Ziliujing shales show multifractal behavior, but the multifractal characteristics of pores of various shales are distinctly different. The information dimension D1, the Hurst exponent H, and the width of the right side D0–D10 are key indicators to distinguish the local variations within the pore structure of different types of shales. The carbonate shales have the largest multifractal spectra width and the smallest D1 and H, while the opposite trend is found for the argillaceous shales. Clay minerals reduce the heterogeneity of the meso- and macropore distributions and increase the pore connectivity. Nevertheless, the carbonate minerals exhibit a reverse trend. Finally, it was found that TOC does not impact pore complexity as much. Collectively, this study supports our understanding of the occurrence of shale oil within various reservoir facies, thereby providing a guideline for future explorations in the Ziliujing Formation of the Jurassic age in the Sichuan Basin.

The impact of supercritical CO2 exposure time on the effective stress law for permeability in shale

Carbon dioxide (CO2) sequestration in shale formations is regarded as an effective approach for reducing CO2 emissions. Permeability is critical for CO2 geological sequestration as it impacts migration of CO2 in shale formations. The effective stress coefficient for permeability (χ) scales the relative influence of pore pressure on permeability compared to confining pressure. This study examined the changes in χ of dry and wet shale samples with different times of supercritical CO2 (ScCO2) exposure. The results suggest that, as ScCO2 exposure time increases from 0 to 40 days, the χ of dry shale increases from 0.8304 to 0.9563, and that of wet shale increases from 0.8379 to 1.0134. Wet shale exhibits a greater increase in χ than dry shale for the same exposure time. These changes in χ may result from CO2-shale interaction that converts smaller-sized pores in shale into larger-sized pores, based on nuclear magnetic resonance (NMR) measurements. Furthermore, the presence of water intensifies the response of shale to ScCO2, thereby enhancing this transformation. Our findings provide insights into the accurate prediction of shale permeability evolution during CO2 storage, and can assist in optimizing CO2 injection strategies as well as evaluating the potential for CO2 sequestration.