Shale Reservoir Characterization Research Articles

Experimental Study of Direct Shear Properties of Anisotropic Reservoir Shale

Understanding the shear mechanical properties of shale reservoirs is of great significance in the study of the formation stability around horizontal shale wells and the propagation and evolution of fractures for shale fracturing. However, the existing direct shear test results are limited due to small sample sizes and low shear rates. Based on previous experimental research results, the mechanical properties of anisotropic reservoir shale in direct shear tests with different experimental conditions were explored in this study. It was found that the shear mode, shear strain rate, and normal stress have a significant impact on the deformation and failure characteristics of shale. The peak shear displacement, peak shear strength, and shear stiffness of shale present an increasing trend of fluctuation, with an increase in the bedding angle. The peak shear strength of shale decreases with an increase in the shear strain rate, and this decrease trend descends with an increase in the shear strain rate. The shape of the shear fracture zone and the shear fracture mode of shale exhibit bedding effect characteristics. The fractal dimension of the shale shear fracture surface morphology shows a trend of fluctuation with the variation in the bedding angle. Further, the shear strain rate was found to play a dominant role in the fractal dimension of the shear fracture surface. The larger shear strain rate strengthens the bedding effect of the roughness for the shear fracture surface morphology. The results of this study provide a theoretical reference for determining the engineering geomechanics characteristics of shale reservoirs.

Research on the Influence of Shale Reservoir Depth on Fracture Characteristics Based on Xsite

The exploration and development of shale reservoir is faced with both opportunities and challenges, especially the mechanism of influence of shale reservoir depth on hydraulic fracture characteristics is unclear. In this paper, by means of Xsite simulation, four stress levels are set to reflect the depth change from the side, and the influence of depth change on the hydraulic fracture characteristics of shale reservoir is studied. The results reveal a phenomenon: in the low stress environment, the fracture network can be effectively constructed, showing a more spacious space structure; In high-stress environments, the propagation direction of hydraulic fractures is precisely controlled, and these fractures can communicate more closely with the bedding surface. It is worth noting that in the low stress environment, the tensile fracture has a large area and forms a broad fracture network. In contrast, in high-stress environments, shear fractures dominate and their area increases significantly. In addition, the fracture volume is larger under low stress environment, while the total fracture area is more significant under high stress environment. This discovery has far-reaching significance for the formation of complex fracture networks in shale reservoirs, emphasizes the importance of making full use of shale multilayer characteristics, and provides rich and profound theoretical guidance for engineering practice.

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.

Combining atomic force microscopy and nanoindentation helps characterizing in-situ mechanical properties of organic matter in shale

The quantification of mechanical properties of organic matter in shale is of significance for the fine prediction and characterization of shale reservoir's mechanical properties. Due to the micron-sized and dispersed distribution of organic matter particles in shale, the accurate evaluation of the actual mechanical response remains challenging. This work focuses on shale from Wufeng-Longmaxi Formation, which is the main shale gas exploration and development formation in China. A method based on atomic force microscopy (AFM) with an optical microscope (i.e., in-situ AFM technique) is presented to locate the organic matter in-situ and then visualize and quantify its mechanical properties using AFM Young's modulus mapping. The merits and limitations for determining the mechanical properties of organic matter in shale between the AFM and the more conventional nanoindentation technique are discussed. Results show that combining in-situ nanoindentation and in-situ AFM mapping provides more accurate description of the mechanical properties of organic matter in shale than traditional grid indentation methods with low spatial resolution. The Young's moduli of organic matter calculated from nanoindentation are around twice smaller than those obtained from AFM measurements mainly because the elasto-plastic deformation zone of organic matter in nanoindentation tests is larger and can be additionally affected by the presence of inorganic particles and/or larger micro-pores in organic matter. The Young's modulus and hardness of graptolite in the shale obtained by nanoindentation are slightly larger than those of solid bitumen at the same thermal maturity. Both in-situ AFM and in-situ nanoindentation results show that the mechanical strength of organic matter increases with increasing maturity. Overall, the presented approach shows a great potential for accurate and in-situ measurement of the mechanical properties of organic matter in shale at the nanoscale, which may be beneficial to the development of rock mechanical models for the accurate evaluation of the actual mechanical properties of shale.

Automatic pore structure analysis in organic-rich shale using FIB-SEM and attention U-Net

The pore structure is an important factor in determining the productivity of shale, which can help us make better operational decisions. Shale formations have an extremely complex pore structure with a wide range of pore sizes, shapes, orientations, and connectivity. Advanced imaging techniques, such as focused ion beam scanning electron microscopes (FIB-SEM), contribute significantly to the analysis and understanding of complex pore networks in shale, but they are time-consuming. Developing new methods and techniques to capture the spatial distribution and connectivity of pores at various scales is essential to understanding pore structure and its impact on fluid flow. This study aims to analyze the pore characteristics of shale reservoirs by using artificial intelligence (AI) and FIB-SEM. We applied a novel attention gate (AG) model to FIB-SEM images that automatically learns to focus on target structures of varying pores’ shape and size. AG can be fully incorporated into the U-Net model with minimal computational impact. The AG improved prediction accuracy by making the U-Net model more sensitive to essential features in the input images and achieved a precision of 97%, recall of 71%, and F1 score of 81% at a confidence threshold of 1. Experimental results show that Attention U-Net outperformed in predicting the pore structures in shale samples from Longmaxi Formation, Qingshankou Formation, Cambrian Niutitang Formation, Yanchang shale oil, and Bakken shale while obtaining optimal performance without requiring multiple convolutional neural network (CNN) models. Additionally, Attention U-Net addresses some of the limitations of the Edge-Threshold Automatic Processing (ETAP) method, including the limited ability to obtain a complete description of the pore space as well as the low segmentation accuracy and sensitivity. The proposed workflow offers a promising solution for optimizing the automatic processing of microscopic images for pores and microfractures identification. Researchers and industry professionals can improve their understanding of shale properties and applications in various fields by maximizing the benefits of our workflow.

DRAG: A Novel Method for Automatic Geological Boundary Recognition in Shale Strata Using Multi-Well Log Curves

Ascertaining the positions of geological boundaries serves as a cornerstone in the characterization of shale reservoirs. Existing methods heavily rely on labor-intensive manual well-to-well correlation, while automated techniques often suffer from limited efficiency and consistency due to their reliance on single well log data. To overcome these limitations, an innovative approach, termed DRAG, is introduced, which uses deep belief forest (DBF), principal component analysis (PCA), and an enhanced generative adversarial network (GAN) for automatic layering recognition in logging curves. The approach employed in this study involves the use of PCA for dimensionality reduction across multiple well log datasets, coupled with a sophisticated GAN to generate representative samples. The DBF algorithm is then applied for stratification, incorporating a confidence screening mechanism to improve computational efficiency. In order to improve both accuracy and stability, a coordinate system is introduced that adjusts for stratification variations among neighboring wells around the target well. Experimental comparisons demonstrate the superior performance of the proposed algorithm in reducing stratification fluctuations and improving precision.

Pore Structure and Geochemical Characteristics of Alkaline Lacustrine Shale: The Fengcheng Formation of Mahu Sag, Junggar Basin

Shale oil and gas are currently the major fields of unconventional hydrocarbon exploration and development. The Fengcheng Formation (FF) shale in the Mahu Sag of the Junggar Basin is an alkaline lacustrine organic-rich shale with an extremely prospective shale oil potential. However, its strong heterogeneity and complex pore structure greatly influence the development of shale oil. It is significant to investigate the pore and geochemical characteristics of shale reservoirs for shale oil extraction. In this study, the pore structure and geochemical characteristics of FF have been investigated using core analysis, Rock-Eval pyrolysis, X-ray diffraction (XRD), field-emission scanning electron microscopy (FE-SEM), mercury injection capillary pressure (MICP), low-temperature gas adsorption (LTGA), and X-ray computed tomography (X-ray CT). The results show that the shale of FF has moderate organic matter abundance, and the kerogen is mainly of Type II, which is now at the peak of oil generation. Shale minerals are mainly composed of carbonate (dolomite and calcite) and siliceous (quartz and feldspar) minerals, with extremely low clay mineral content. The pore types are mainly intergranular pores (inter-P), intragranular pores (intra-P), and microfractures associated with mineral particles. The pore space is contributed predominantly by micropores of 0.5–1.2 nm and mesopores of 10–50 nm, whereas macropores are underdeveloped. The pores are mostly ink bottle- and slit-shaped, and the pore connectivity is relatively poor. The pore development of shale in the FF is influenced by organic matter abundance, thermal maturity, mineral composition, etc. Organic matter content (TOC), thermal maturity (Ro), and carbonate minerals have a positive effect on pore development, and the pore volume (PV) increases with TOC, Ro, and carbonate minerals. While clay minerals show a negative effect, the PV decreases with clay minerals. Additionally, the influence of the clay mineral content on the pore morphology of shale should not be ignored. This study investigates the pore structure and geochemical characteristics of the alkaline lacustrine shale of FF in Mahu Sag, which is significant to deepen the understanding of alkaline lacustrine shale and to improve the production of shale oil.

Molecular dynamics simulation of surfactant induced wettability alteration of shale reservoirs

Shale oil has recently received considerable attention as a promising energy source due to its substantial reserves. However, the recovery of shale oil presents numerous challenges due to the low-porosity and low-permeability characteristics of shale reservoirs. To tackle this challenge, the introduction of surfactants capable of modifying wettability has been employed to enhance shale oil recovery. In this study, we perform molecular dynamics simulations to investigate the influence of surfactants on the alteration of wettability in shale reservoirs. Firstly, surfaces of kaolinite, graphene, and kerogen are constructed to represent the inorganic and organic constituents of shale reservoirs. The impact and underlying mechanisms of two types of ionic surfactants, namely, the anionic surfactant sodium dodecylbenzene sulfonate (SDBS) and cationic surfactant dodecyltrimethylammonium bromide (DTAB), on the wettability between oil droplets and surfaces are investigated. The wettability are analyzed from different aspects, including contact angle, centroid ordinates, and self-diffusion coefficient. Simulation results show that the presence of surfactants can modify the wetting characteristics of crude oil within shale reservoirs. Notably, a reversal of wettability has been observed for oil-wet kaolinite surfaces. As for kerogen surfaces, it is found that an optimal surfactant concentration exists, beyond which the further addition of surfactant may not enhance the efficiency of wettability alteration.

Research on Mathematical Model of Shale Oil Reservoir Flow

There are complex pore structures in shale reservoirs, and the nonlinear flow characteristics of shale reservoirs are complicated by stress sensitivity and boundary layer effects. In this research, a new flow mathematical model was established based on capillary model, stress sensitivity and boundary layer effect. The model was verified by the experimental results of Jilin shale oil reservoir, and the influencing factors of flow characteristics were analyzed. The results show that the new shale oil flow model has good fitting and high reliability with the experimental results. The boundary layer effect and stress sensitivity are the main factors affecting the seepage characteristics. With the increase in the pressure gradient, the influence of the boundary layer effect on the flow is gradually enhanced, and the influence of the stress sensitivity on the flow is gradually weakened. At the same time, this study developed a method for the evaluation of effective displacement distance of shale oil reservoir with CO2 injection through the limited injection-production well spacing method, and obtained the nonlinear flow curve of displacement distance with reservoir permeability under different injection and production pressure difference. This research deeply studies the flow characteristics of shale oil reservoir and provides a theoretical basis for the enhanced oil recovery of shale oil with CO2 injection.

Geological Characteristics of Shale Reservoir of Pingdiquan Formation in Huoshaoshan Area, Junggar Basin

Unconventional oil and gas, represented by shale gas and shale oil, have occupied an important position in global energy. The rapid growth of shale gas and shale oil production shows great potential for the exploration and development of shale resources. Junggar basin, the main oil-bearing basin in China, is rich in oil and gas resources, so it is of great practical significance to carry out systematic research on the geological characteristics of shale reservoirs in this region. To this end, this paper designates the shale reservoir of Pingdiquan Formation in Huoshaoshan area of the Jungar Basin as the research object, carries out a geological survey in that area, analyzes reservoir forming conditions using the geological interpretation method, analyzes different local trap reservoir types and their main control factors by dissecting the explored reservoir, optimizes and evaluates favorable traps using the source, fault, facies and circle coupling analysis method, establishes single good identification standard of sedimentary microfacies, and carries out well-connected sedimentary microfacies analysis. Using geochemical methods, such as rock pyrolysis, maceral analysis, vitrinite reflectance, kerogen carbon isotope, saturated hydrocarbon chromatography, etc., the abundance and types of organic matter of shale in different intervals are analyzed and the geological characteristics of shale reservoirs are evaluated. This paper aims to analyze the oil and gas content of the shale reservoir in Pingdiquan Formation in the Junggar Basin to provide reliable reservoir evaluation and guide better development of shale oil and gas resources in the future. The innovative expenditure of this paper lies in conducting the research from two aspects: the analysis of the main controlling factors of reservoir formation from the structural point of view and the analysis of the pore structure and geochemical characteristics of shale from the core experiment point of view, and also the classification of organic matter, so as to provide a basis for finding favorable traps. The results show that the shale sedimentary system in the study area is a small fluvial delta, which belongs to a compression structure, with developed NNE-oriented structural belts and faults; the structural form is a short-axis anticline as a whole, forming a structural coil closure at −900 m, with a trap area of 50 km2 and a closure height of 180 m. According to the geological interpretation method, 19 faults of all levels were found in the area and the vertical migration conditions of oil and gas were good. Pingdiquan Formation was oil-bearing, with many vertical oil-bearing strata and strong horizontal independence of the reservoir. The sedimentary thickness of the Permian Pingdiquan Formation in the study area is 300~1200 m and the oil-bearing strata are divided into 3 oil-bearing formations, 9 sublayers, and 22 monolayers from top to bottom. The abundance of organic matter in different strata is generally high, with an average total organic carbon content of 3.53%, an average hydrocarbon generation potential of 18.1 mg/g, an average chloroform asphalt content of 0.57%, and an average total hydrocarbon content of 3011 μg/g, all of which belong to the shale standard, especially Ping-2. The organic matter in different layers belongs to types I-II1, and the organic matter types are I-II1, I-II2, and II1-II2, respectively. The average carbon isotope of shale kerogen is −2.4%, which belongs to type II2 kerogen.

Effect of CO2 Huff-n-Puff Mode with a Horizontal Well on Shale Oil Recovery: A Three-Dimensional Experimental Study

After conventional development, there is still a significant amount of residual oil as a result of the poor porosity and permeability characteristics of shale reservoirs. Although CO2 flooding is one of the most reasonable recovery techniques, it is affected by a serious sweep efficiency issue. In this paper, six CO2 huff-n-puff cooperative combination methods were established with the aid of three-dimensional physical simulation equipment, including CO2 huff-n-puff (HNP), water-disturbance-assisted CO2 huff-n-puff (WD-HNP), surfactant- and water-disturbance-assisted CO2 huff-n-puff (SWD-HNP), pumping-production-assisted CO2 huff-n-puff (PP-HNP), water-disturbance-assisted CO2 huff-n-puff after pumping production (WDP-HNP), and surfactant- and water-disturbance-assisted CO2 huff-n-puff after pumping production (SWDP-HNP). The displacement characteristics, utilization law, and development effect were investigated. CO2 huff-n-puff requires more gas injection quickly, and low permeability and pressure difference can easily cause irregular gas channeling, showing the arc linear flooding pattern. Water disturbance can significantly delay the rapid breakthrough, so that the displacement edge shows the radial flooding pattern. The effect of pumping production on the displacement is not obvious, and the leading edge still shows an oval-shaped flooding pattern. Surfactant assistance improves the gas injection ability, eventually demonstrating a plane steady flooding pattern. In comparison to HNP, the average enhancement degree of water injection disturbance, pumping production, and surfactant assistance to the utilization extent is 6.61, 1.82, and 8.93% respectively. Meanwhile, SWDP-HNP had the highest oil recovery (33.35%) among all modes. By comparison of effective productivity, it revealed that about 12% of the lifting range is helped by surfactant assistance, followed by a water injection disturbance lifting amplitude of 5.5%, while pumping production only led to a 3% improvement. With the combination of all development effect evaluation indicators, SWD-HNP is a reasonable displacement method to improve shale reservoir recovery in this study.

Microscopic Production Characteristics of Pore Crude Oil and Influencing Factors during Enhanced Oil Recovery by Air Injection in Shale Oil Reservoirs.

High-pressure air injection (HPAI) is one of the effective methods to improve shale oil recovery after the primary depletion process. However, the seepage mechanisms and microscopic production characteristics between air and crude oil are complicated in porous media during the air flooding process. In this paper, an online nuclear magnetic resonance (NMR) dynamic physical simulation method for enhanced oil recovery (EOR) by air injection in shale oil was established by combining high-temperature and high-pressure physical simulation systems with NMR. The microscopic production characteristics of air flooding were investigated by quantifying fluid saturation, recovery, and residual oil distribution in different sizes of pores, and the air displacement mechanism of shale oil was discussed. On this basis, the effects of air oxygen concentration, permeability, injection pressure, and fracture on recovery were studied, and the migration mode of crude oil in fractures was explored. The results show that the shale oil is mainly found in <0.1 μm (small pores), followed by 0.1-1 μm (medium pores), and 1-10 μm (macropores); thus, it is critical to enhancing oil recovery in pores less than 0.1 and 0.1-1 μm. The low-temperature oxidation (LTO) reaction can occur by injecting air into depleted shale reservoirs, which has a certain effect on oil expansion, viscosity reduction, and thermal mixing phases, thereby greatly improving shale oil recovery. There is a positive relationship between air oxygen concentration and oil recovery; the recoveries of small pores and macropores can increase by 3.53 and 4.28%, respectively, and they contribute 45.87-53.68% of the produced oil. High permeability means good pore-throat connectivity and greater oil recovery, and the production degree of crude oil in three types of pores can be increased by 10.36-24.69%. Appropriate injection pressure is beneficial to increasing the oil-gas contact time and delaying gas breakthrough, but high injection pressure will result in early gas channeling, which causes the crude oil in small pores to be difficult to produce. Notably, the matrix can supply oil to fractures due to the mass exchange between matrix fractures and the increase of the oil drainage area, and the recoveries of medium pores and macropores in fractured cores increased by 9.01 and 18.39%, respectively; fractures can act as bridges for matrix crude oil migration, which means that proper fracturing before gas injection can make the EOR better. This study provides a new idea and a theoretical basis for improving shale oil recovery and clarifies the microscopic production characteristics of shale reservoirs.

Pore Structure Characterization of Shale Reservoir Using Nitrogen Adsorption-Desorption

This research paper aimed to quantitively characterize the pore structure of shale reservoirs. Six samples of Silurian shale from the Ahnet basin were selected for nitrogen adsorption-desorption analysis. Experimental findings showed that all the samples are mainly composed of mesopores with slit-like shaped pores, as well as the Barrett-Joyner-Halenda pore volume ranging from 0.014 to 0.046 cm3/ 100 g, where the lowest value has recorded in the AHTT-1 sample, whereas the highest one in AHTT-6, while the rest samples (AHTT-2, AHTT-3, AHTT-4, AHTT-5) have a similar average value of 0.03 cm3/ 100 g. Meanwhile, the surface area and pore size distribution were in the range of 3.8 to 11.1 m2 / g and 1.7 to 40 nm, respectively. Nanoparticle size was in the range of 540 to 1589.2 nm, this parameter showed a strong negative correlation with both the surface area and pore volume. Findings can contribute significantly to the pore structure evaluation and characterization of the Silurian shale reservoir in the Ahnet basin. .

Pore structure characteristics of different lithofacies of the Longmaxi shale, Western Hunan‐Hubei Region, China: Implications for reservoir quality prediction

Lithofacies and micropore characteristics of shale reservoir directly affect the exploration and development of natural gas. To determine the development potential of shales of the Longmaxi Formation in the Western Hunan‐Hubei Region, the lithofacies types and micropore structure characteristics of the Longmaxi Formation shales have been systematically studied in this paper, based on ordinary thin sections, argon ion polishing–scanning electron microscopy, physical property testing, x‐ray diffraction whole‐rock and clay mineral analysis, isothermal nitrogen, and carbon dioxide adsorptions. According to the principle of ‘laminar structure + total organic carbon (TOC) + mineral composition of felsic, clay, and carbonate minerals’, eight types of shale lithofacies were identified. The effective porosity of the Longmaxi shale ranges from 1.8% to 14.4%, with a peak range from 3% to 6%, while the permeability ranges from 0.001 to 1.27 mD, with an average of 0.106 mD. Combined with the isothermal adsorption experiments, the proportion of mesopores is the largest in the Longmaxi shale, followed by macropores and micropores. Moreover, the pore diameters of mesopores are concentrated between 3 and 10 nm, while those of micropores are concentrated between 0.4 and 0.9 nm. The pore volume of shale is most developed when the content of brittle felsic minerals is 50% ~ 75% and the content of clay minerals is 25% ~ 50%, and the TOC content is positively correlated with the pore volume and specific surface area. There are significant differences in the pore development characteristics of different lithofacies. The shale reservoir space analysis indicates that micropores are controlled by TOC content and clay minerals, while the macropores are controlled by depositional intergranular pores, TOC content, and felsic content, as well as diagenetic pyrite mould pores, microfractures pores, and intercrystalline pores. On the other hand, mesopores are related to a mix of depositional and diagenetic factors with dominant contribution of intergranular pores, intercrystalline pores, organic pores, and intergranular shrinkage fractures pores. It is found that the pore development of massive organic‐rich siliceous shale lithofacies has the best reservoir quality, including well‐connected intergranular pores, intercrystalline pores, organic pores, and shrinkage fractures. Therefore, the massive organic‐rich siliceous shale lithofacies is the dominant fine‐grained reservoir lithofacies in the studied area. Based on understating the pore characteristics of different lithofacies, this study can provide a scientific basis for the prediction of favourable sweet spots of shale gas reservoir in the Longmaxi Formation, western Hunan‐Hubei Region.

A Review of Molecular Models for Gas Adsorption in Shale Nanopores and Experimental Characterization of Shale Properties.

Shale gas, as a promising alternative energy source, has received considerable attention because of its broad resource base and wide distribution. The establishment of shale models that can accurately describe the composition and structure of shale is essential to perform molecular simulations of gas adsorption in shale reservoirs. This Review provides an overview of shale models, which include organic matter models, inorganic mineral models, and composite shale models. Molecular simulations of gas adsorption performed on these models are also reviewed to provide a more comprehensive understanding of the behaviors and mechanisms of gas adsorption on shales. To accurately understand the gas adsorption behaviors in shale reservoirs, it is necessary to be aware of the pore structure characteristics of shale reservoirs. Thus, we also present experimental studies on shale microstructure analysis, including direct imaging methods and indirect measurements. The advantages, disadvantages, and applications of these methods are also well summarized. This Review is useful for understanding molecular models of gas adsorption in shales and provides guidance for selecting experimental characterization of shale structure and composition.

Sequential Seismic Anisotropic Inversion for VTI Media with Simulated Annealing Algorithm Aided by Adaptive Setting of Optimization Parameters

As an important geophysical data processing technique, seismic inversion estimates subsurface rock properties with seismic observations. However, anisotropic inversion, intended for a vertical transverse isotropy (VTI) media that primarily describes shale gas/oil resources, suffers from high nonlinearity. Simulated annealing is a widely used global optimization algorithm for solving nonlinear seismic inverse problems, but it involves multiple optimization parameters (e.g., initial temperature, search limit, and perturbation range). The importance of such parameters has been proven whilst the relevant analysis is limited in seismic inversion studies. This work hereby proposes a sequential anisotropic inversion method for VTI media, wherein we combine Bayesian linear and simulated annealing nonlinear inversion schemes. The simulated annealing is featured by adaptive optimization parameters aided by the linear result. Rather than the conventional method, the adaptive setting can be implemented trace by trace for complex reservoirs, which endows the method with enhanced stability and extended applicability. Synthetic tests and practical application demonstrate the validity of the method, wherein the obtained stiffness parameters facilitate the characterization of potential shale reservoirs with an improved accuracy.

A Multi-medium and Multi-mechanism model for CO2 injection and storage in fractured shale gas reservoirs

Under the background of “dual-carbon”, it is strategically significant to use shale gas reservoirs for CO2 injection and storage. Injection of CO2 into shale formations can improve natural gas recovery and achieve effective storage of CO2. However, due to the complex characteristics of shale reservoirs, like complex fractures and a variety of flow mechanisms, few work has been done to comprehensively consider those complex characteristics for accurate reservoir simulation of CO2 injection and storage. Therefore, to improve this situation, this paper establishes a fully coupled model of the matrix, natural fracture and hydraulic fracture, which considers multiple mechanisms, including adsorption/desorption, diffusion, stress sensitivity of fracture and stimulated reservoir volume (SRV). The embedded discrete fracture model (EDFM) is applied to describe the transfer flow between matrix-fracture, fracture-fracture and fracture-well. The finite volume and quasi-Newton iterative methods are used to solve the model. The model's reliability and practicability are verified by matching the production history of commercial software in shale gas reservoirs. The effects of various factors on the production curve and CO2 storage characteristics are analyzed, including adsorption/desorption, diffusion, stress sensitivity, well production pressure, CO2 injection rate, CO2 injection opportunity and fracture parameters. The results show that the model is reliable and practical and can be used to study the dynamic performances of enhanced shale gas recovery and CO2 storage.

Digital-Rock Construction of Shale Oil Reservoir and Microscopic Flow Behavior Characterization

In shale oil reservoirs, nano-scale pores and micro-scale fractures serve as the primary fluid storage and migration space, while the associated flow mechanism remains vague and is hard to understand. In this research, a three-dimensional (3D) reconstruction of the shale core and micro-pore structure description technique is established; digital core technology for shale reservoirs was developed using X-ray computed tomography (X-CT), scanning electron microscope (SEM) and a focused ion beam scanning electron microscope (FIB-SEM). Microscopic oil–water two-phase flow is mimicked using the lattice Boltzmann method (LBM), a well-acknowledged approach to exploring nanoconfined fluid dynamics. In addition, coupled with digital cores, the flow characteristics of shale reservoirs are characterized. The total porosities of bedding fractures in shale and lamellar shale are 2.042% and 1.085%, respectively. The single-phase oil flow inside bedding fractures follows Darcy’s linear flow principle. This work can deepen the understanding of the microscopic flow characteristics of continental shale reservoirs and provide a reference for similar problems that may be encountered.

Effect of organic matter, thermal maturity and clay minerals on pore formation and evolution in the Gulong Shale, Songliao Basin, China

The successful exploration of shale oil in the clay-rich Gulong shale of Songliao Basin has got wide attention. While silica-rich and carbonate-rich shale reservoirs have been well documented, clay-rich shale reservoir characteristics and evolution are still ambiguous. In this study, a large number of Gulong shales from 34 wells across the basin were subjected to integrated analyses of total organic carbon (TOC), vitrinite reflectance (Ro), X-ray diffraction (XRD), field emission-scanning electron microscopy (FE-SEM), low-pressure N2 gas adsorption and helium porometry. The coupling evolution of organic matter, clay minerals and pores with increasing thermal maturity was investigated. The results show that (1) The Gulong shale is mainly clay-rich and argillaceous mudstone. In contrast with other oil producing lacustrine shales, silt and carbonate interbeds are thin in thickness with the least oil potential. (2) The primary pore type is organo-clay complex hosted pore (OMC-hosted pore), which is defined as pores between clay platelets or aggregates but previously was occupied by labile kerogen or migrated oils. In contrast to OM-hosted pores, OMC-hosted pores have less solid bitumen relics due to clay catalysis effect. (3) Pore evolution is coupled with thermal maturation stage and significant porosity build-up occurs in the oil window (Ro ∼0.9–1.3%). While most pores are associated with clay minerals, organic carbon content is the primary factor controlling porosity at each thermal maturation stage. (4) Oil generation overpressure is suggested as the most important factor controlling pore preservation, while phyllosilicate fabrics resulting from clay mineral transformation may provide rigid flakes resisting pores from collapse. (5) In contrary to sandstone or carbonate reservoirs, the excess chlorite (>5.0%) was observed to has a positive effect on pore formation in clay-rich shales. One genesis of chlorite was identified in this study, that the chlorite was formed in dissolved ferrodolomite particle, which possibly has provided both Fe and Mg needed for smectite-chlorite conversion.

Predicting shale mineralogical brittleness index from seismic and elastic property logs using interpretable deep learning

The mineralogical brittleness index (MBI) of organic-rich shale formations is one of the key parameters to identify the optimal production well locations and optimize hydraulic fracturing. Since we as a community don't understand the exact physical relationship between the MBI and seismic properties from well logs, we have used traditional approaches like the log-based brittleness index (LBI) and the elastic brittleness index (EBI) to quantify the rock brittleness from seismic data and well logs. The LBI method is easy to use but is empirically derived from the porosity and sonic logs. On the other hand, the EBI method is dependent on the average values of Young's modulus and Poisson's ratio but is not physically meaningful in practice. Therefore, we develop a deep learning approach to obtain a more reliable MBI model from seismic properties and enhance the interpretability with Shapley values. First, we analyze the statistical relationship between the MBI and eight seismic properties from well logs and distinguish the influential input variables for the MBI prediction, such as bulk density, Young's modulus, and Poisson's ratio. Second, we find a multivariate linear regression (MLR) model with three input properties and quantify the relative statistical contribution of each input based on Shapley values. Third, we use a deep neural network technique to derive the nonlinear estimation model with a better fit to the MBI data than the traditional methods. We test and verify our approach on field log and core data from the Wolfcamp shales in the Permian Basin, Texas. In conclusion, this workflow can provide a more interpretable and accurate MBI estimation from seismic properties to enhance unconventional shale reservoir characterization.