Reservoir Pore Structure Research Articles

A Review of Macroscopic Modeling for Shale Gas Production: Gas Flow Mechanisms, Multiscale Transport, and Solution Techniques

The boost of shale gas production in the last decade has reformed worldwide energy structure. The macroscale modeling of shale gas production becomes particularly important as the economic development of such resources relies on the deployment of expensive hydraulic fracturing and the reasonable planning of well schedules. A flood of literature was therefore published focused on accurately and efficiently simulating the production performance of shale gas and better accounting for the various geological features or flow mechanisms that control shale gas transport. In this regard, this paper presents a holistic review of the macroscopic modeling of gas transport in shale. The review is carried out from three important points of view, which are the modeling of the gas flow mechanisms, the representation of multiscale transport, and solution techniques for the mathematical models. Firstly, the importance of gas storage and flow mechanisms in shale is discussed, and the various theoretical models used to characterize these effects in the continuum scale are introduced. Then, based on the intricate pore structure and various pore types of shale gas reservoirs, this review summarizes the multiple-porosity models in the literature to represent multiscale gas transport, and discusses the applicability of each model. Finally, the numerical and analytical/semi-analytical approaches used to solve the macroscopic mathematical model governing shale gas production are reviewed, with a focus on the treatment of the complex fracture network formed after multistage hydraulic fracturing.

Classification and Quantitative Characterization of Archean Metamorphic Buried Hill Reservoirs in the Bohai Sea.

Based on productivity test data and physical property test results from multiple wells, a classification scheme of Archean metamorphic buried hill reservoirs in the Bohai Sea is established by means of mathematical function fitting. By combining data from cores, casting thin sections, scanning electron microscopy, imaging logging, and high-pressure mercury injection and nitrogen adsorption tests, we clarified the reservoir composition and pore structure characteristics of different types of reservoirs are clarified. Furthermore, taking the BZ19-6 and 13-2 wells in the Archean metamorphic buried hills as an example, the development sites of different types of reservoirs are analyzed and the reservoir development model is established. The results show that the Archean metamorphic buried hill reservoirs in the Bohai Sea can be divided into three categories and six subcategories, including type I reservoirs with porosities greater than 8% or permeabilities greater than 1 × 10-3 μm2 and type II reservoirs with porosities of 5-8% or permeabilities in the range of 0.1-1 × 10-3 μm2. Reservoirs with porosities of 2-5% and permeabilities of 0.01-0.1 × 10-3 μm2 are type III reservoirs. Each type of reservoir can be further divided into a fracture-pore type and a fracture type according to the relative contribution of the porosity and permeability to the reservoir. From type I to type III, the dissolution degree and fracture development gradually weaken, the pore size gradually decreases, and the pore volume gradually decreases. The distribution of favorable reservoirs is comprehensively controlled by weathering and tectonic transformation. The presence of a weathered glutenite zone, weathered leaching zone, or weathered disintegration zone is favorable for the development of type I reservoirs in the weathering crust. In the inner part of the buried hill, the presence of a fracture zone with a thickness of more than 10 m or a dense fracture zone with a thickness of more than 40 m is favorable for the formation of type I reservoirs.

Characteristics and controlling factors of pore structure of shale in the 7th member of Yanchang Formation in Huachi area, Ordos Basin, China

To clarify the influence of organic matter and mineral composition on the pore structure of shale reservoirs in the 7th member of the Yanchang Formation (Chang 7 Member) in the Ordos Basin, we characterized the pore structure of Chang 7 shale reservoirs using argon ion polishing-field emission scanning electron microscopy (FE-SEM) and low-pressure nitrogen adsorption (LP-N2A). This characterization was combined with whole-rock mineral composition and organic geochemical experiments to analyze the main controlling factors of the pore structure of Chang 7 Member shale. The results reveal the presence of various pore types in shale, including organic matter pores, intergranular pores, intercrystalline pores, dissolved pores, and micro-cracks. The LP-N2A isotherms of shale consistently exhibit type Ⅱ isotherms with H3 and H4 hysteresis loop characteristics, indicating the relatively developed nature of mesopores and a pore morphology characterized by parallel lamellar and “ink bottle” shapes. The primary determinants of shale pore structure are identified as organic matter, clay minerals, quartz, feldspar, and pyrite. Among these factors, clay mineral phase transformation generates a substantial number of micropores and mesopores within the mineral crystal layers, serving as the main source of shale pores in the study area. Additionally, liquid hydrocarbons generated, solid bitumen, and euhedral pyrite fill inorganic mineral pores, thereby reducing the pore space of Chang 7 shale to a certain extent. These results provide a new cognition into understanding the pore structure characteristics and controlling factors of Chang 7 shale.

Phase behavior and hydrocarbons distribution in shale oil during EOR with nano-confinement effect

The pore structure of shale reservoirs leads to the complex phase behavior of shale reservoir fluids, which is aggravated due to changes in fluid composition during reservoir development. Effective prediction of changes in the phase behavior of fluids in shale reservoirs is important. This paper proposes a pore-size-dependent Peng-Robinson equation of state (PR-EOS) to describe phase behavior in nanopores. The approach considers the shift of critical parameters and the gas-liquid capillary pressure and compiles by MATLAB. The verification of the model is satisfying by matching the result with Tnavigator PVTi using the published date. The results show that fluids in nanoscale pores are more likely to exhibit near-critical or condensate states. We also compare the changes in phase behavior when fluids dissolve CO2 and CH4 and observe the phase transition (from gaseous to liquid phase) of the lighter crude oil sample that dissolved more gas during the differential liberation experiment (DL). Finally, we use CO2 pre-pad energized fracturing of a shale oil reservoir in northern China as an example to explain abnormal production performances, such as a majority of light hydrocarbons in the produced fluid of the well during the flow back stage, single gas phase production in the early production stage, and stable gas/oil ratio (GOR) in the process of development. Our novel methodology and phase behavior change mechanism can enhance our understanding of the phase behavior of fluids in shale oil reservoirs during enhanced oil recovery.

Complexity and Heterogeneity Evaluation of Pore Structures in the Deep Marine Shale Reservoirs of the Longmaxi Formation, China

The structural evolution and sedimentary differentiation of the Sichuan Basin in China are complex, with intricate reservoir pore structures that significantly impact shale gas production. This study examines the complexity and heterogeneity of the microscopic pore structures in the deep marine shale reservoir in the Longmaxi Formation. Pore structure characterization techniques are used to compare deep and shallow–medium marine shales, and siliceous and silty shales. The results reveal the factors influencing pore structure and their impact on exploration and development. The key points are as follows: (1) The pore structure of deep siliceous shale is the most complex due to its diverse range of pore development patterns, pore types, and sizes. (2) The box dimension of full pore size is about 1.52 for deep marine shale and 1.46 for shallow–medium shale. Organic matter (OM) content, the degree of pore development, and inorganic mineral content all correlate positively with the complexity of the pore structure in deep marine shale, which affects the formation of high-quality reservoirs. (3) Lateral heterogeneity of pore structures shows strong regional variations in the study area. Heterogeneity is more pronounced in the deep marine shale than in the medium and shallow shale formations. OM mesopores significantly influence the overall heterogeneity of the shale pore system. The deep marine shale reservoir is situated in an area with strong regional variations. The pore structure of high-quality reservoirs is more complex than those of shallow–medium marine shales, displaying notable heterogeneity. Pore structures with fractal dimension values close to that of the shallow–medium formations (box dimensions within 1.5) offer promising targets for the exploration and development of deep marine shale gas.

Logging evaluation of pore structure and reservoir quality in shale oil reservoir: The Fengcheng Formation in Mahu Sag, Junggar Basin, China

The Permian Fengcheng Formation in the Mahu Sag of the Junggar Basin is characterized by frequent changes of mineral compositions and lamina structure. The alkali lacustrine shale reservoir shows strong heterogeneity and anisotropy, it is particularly important to clarify the relationship between pore structure and reservoir quality. The pore characteristics were investigated by using thin sections, Scanning Electron Microscope (SEM), and Nuclear Magnetic Resonance (NMR) analyses. The pore types are mainly composed of inorganic pores, organic pores, and microfractures. The storage space is dominated by inorganic pores and microfractures. The pore structure was divided into four types by NMR parameters including T2 spectral morphology, T2gm, total porosity, and movable fluid porosity. Combined with core NMR experiments and two-dimensional (2D) NMR logs, 21 ms was adopted as the T2cutoff value to represent the demarcation between movable and bound fluids. From Type I to Type IV, the energy clusters reflect the movable fluids including movable oil and movable water gradually decreasing in the upper right corner. The energy clusters reflect the bound fluids including clay-bound water and bitumen gradually increasing in the lower left corner in the T1-T2 map. The results show that the heterogeneity of mineral compositions and lamina structures are the key factors directly leading to the complexity and distribution of pore structure. Quartz with strong compaction resistance helps keep a large number of primary interparticle pores, and feldspar dissolution pores caused by organic acids are present. Dolomite intercrystalline pores and dissolution pores provide a large amount of storage space for the shale, while the cementation of calcite reduces pore spaces. The increase of felsic mineral content is conducive to improving the pore structure and oil-bearing potential of oil shale reservoir, while clay minerals and calcite are contrary. There are abundant primary interparticle pores and dissolution pores in the layered siliceous (felsic) shales, and they consist of the upper sweet spot in the Fengcheng Formation. The longitudinal time (T1) and transverse time (T2) spectra are bimodal with high total porosity and movable oil content, reflecting high reservoir quality and oil-bearing property. Laminated dolomite shales contain dolomite intercrystalline pores and dissolution pores, and they consist of the lower sweet spot in the Fengcheng Formation. The results above provide a new perspective on the evaluation of pore structure and reservoir quality of shales in the context of an alkaline lake.

Wettability alteration and dynamic wetting behavior of coal during geologic CO2 sequestration using LF-NMR technology

As CO2 has a strong affinity to coal surface, coal seams are considered as an attractive geological formation for CO2 sequestration. Naturally occurring coal seams are often saturated with free water in the cleats as well as moisture. Hence, the wetting behavior of coal by water is an important aspect in the study of coal properties. However, carbon dioxide, which replaces methane on the surface of coal, interacts with water and coal for a long time. Geochemical reactions of CO2-H2O-coal system can change the surface properties and pore structure of coal. Studies on wettability of coal altered by CO2-H2O-coal interaction are rare. This paper explored the wettability alteration and wetting dynamic behavior of two bituminous coals in Huainan and Huaibei coalfield using low-field nuclear magnetic resonance (LF-NMR) combined with CO2-H2O-coal interaction experiments. The results show that dynamic wetting of water in the coal mainly depends on the pores structure. The geochemical reaction changed the pore structure of coal reservoir, further promoted the hydrophobicity of coal surface, and thereby affected the dynamic wetting process of water. Moreover, the wetting of large pores in coal is not significantly affected by the weakening of hydrophilicity, whereas wetting in small pores is obviously affected by the enhanced hydrophobicity, which may be beneficial to the adsorption and storage of CO2 in the coal.

Characterizing multi-scale shale pore structure based on multi-experimental imaging and machine learning

An accurate and comprehensive understanding of shale pore structure is fundamental and critical for accurate reserves evaluation and efficient hydrocarbon development. Thus, by taking the shale of Paleogene Eocene Shahejie Formation in the Jiyang Depression, Bohai Bay Basin, as an example, the 2D and 3D multi-resolution images of the shale microstructure are obtained by multiple imaging technologies, including X-ray computed tomography, large-field scanning electron microscopy, scanning electron microscopy and focused ion beam scanning electron microscopy. By integrating image processing and machine learning algorithms, the shale pore structure is characterized at a single scale and multi scales. The results are obtained as follows. First, the shale pore space in the study area is mainly composed of microfractures, inorganic pores, organic matters and organic pores, and exclusively shows multi-scale characteristics. Second, there are various types of inorganic pores, and abundant dissolution pores; organic matters are distributed as strips and patches, and no organic pores are found in some organic matters. Third, pores with radius less than 20 nm account for 25%, those with radius between 20 and 50 nm account for 19%, those with radius between 50 and 100 nm account for 29%, those with radius between 100 and 500 nm account for 14%, those with radius between 500 nm and 20 μm account for 11%, and those with radius between 20 and 50 μm account for 2%. Fourth, the organic pores are less connected than the inorganic pores. The connectivity between organic pores and inorganic pores plays a crucial role in hydrocarbon migration, and microfractures control fluid flow channels. Fifth, pores with radius less than 50 nm are dominantly organic pores, those with radius between 50 and 500 nm are mainly organic and inorganic pores, and microfractures mainly contribute to the pores with radius more than 500 nm. It is concluded that a single imaging experiment cannot accurately and comprehensively reveal the multi-scale micro pore structure of a shale reservoir. Through integration of multiple imaging technologies and machine learning algorithms, the shale pore structure can be recognized and characterized at both single scale and multi scales. The proposed new method provides accurate and comprehensive information of multi-scale pore structures.

Formation Characterization and Type Prediction Based on Geophysical Well Log Data in Horizontal Well: A Case Study of Triassic Chang 8 Formation in Shunning Region, Central Ordos Basin

The role of the horizontal well in developing unconventional oil and gas reservoirs is particularly significant. Different from vertical wells, horizontal wells are greatly affected by many factors, e.g., well track, surrounding mudstone, resistivity, and pore structure heterogeneity in horizontal and vertical directions. These make it difficult to evaluate reservoir parameters and determine optimized test layers. In order to improve formation evaluation in horizontal wells, it is necessary to carry out the research of analyzing formation anisotropy, predict physical property parameters, and classify formation to determine high-quality intervals. In this study, taking Triassic Chang 8 Formation in Shunning Region, Central Ordos Basin as an example, 40 core samples were drilled and applied for nuclear magnetic resonance (NMR), mercury injection capillary pressure (MICP), and resistivity experiments. The porosity, permeability, resistivity, and pore structure anisotropy are analyzed. Results illustrate that the physical properties and pore structure in horizontal direction are superior to vertical direction. Meanwhile, NMR log loses its role in pore structure characterization in horizontal wells. Afterward, methods of correcting interval transit time (DT) and resistivity anisotropy are raised, and models of predicting formation physical property parameters, such as porosity, permeability, and water saturation, are established. A parameter, named as the formation type indicator (FTI), is proposed to reflect reservoir oil-bearing properties and pore structure. Finally, our target horizontal intervals are classified into four types, and the highest-quality “sweet spot” is determined.

Pore structure and fluid mobility of tight carbonate reservoirs in the Western Qaidam Basin, China

AbstractTight carbonate reservoirs in the Western Qaidam Basin have complex lithologies and pore structures. The oil–water mobility law in reservoirs has not yet been completely determined, restricting the formulation of rational reservoir development methods. To bridge this gap, in this study, we used several test methods, such as casting thin sections, mercury intrusion, and nuclear magnetic resonance, to obtain the pore structure and oil–water displacement characteristics of tight carbonate reservoirs in the Western Qaidam Basin. The pore structures of the reservoirs could be categorized into three types: microfractures + dissolved pores + micropores (MFD), microfractures + micropores (MF), and matrix (M). The characteristics of single‐phase oil seepage and water flooding in reservoirs with various pore structures differed evidently. For the MF‐ and M‐types, the water‐locking effect caused by the strong capillary force affected oil charging in the micropores. The effect of the pressure drop on the MFD‐type algal limestone was less than that on the MF‐type limestone (dolomite) because of the occurrence of a non‐Darcy flow. The MFD‐type, which contained microfractures, had preferential seepage channels, resulting in obvious fluid channeling and low water displacement efficiency. Oil−water displacement mainly occurred in the dissolved pores and microfractures, suggesting that starting oil accumulation in the micropores was crucial. This study will assist in efficient development of tight carbonate reservoirs in the Western Qaidam Basin.

Цеолитовая минерализация пород-коллекторов севера Западной Сибири: литолого-геофизические аспекты и особенности разработки

As the hydrocarbon production tends to decline, formations with a complex geological structure and various secondary mineral formation types of reservoir rocks gain a considerable attention. The importance of secondary minerals for formation of pore and void space structure in hydrocarbon reservoirs is extremely high. The physical and chemical properties of these minerals should be considered during exploration works, calculation of reserves, reservoir engineering, wellwork planning. This article highlights the methodological study approach of mountain rocks with zeolitization based on the results of modern lithological, analytical, and laboratory research. The implementation of the approach allowed for recommendations for rapid quantitative assessment of zeolite content in the Lower Cretaceous sediments of the Bolshekhetskaya Depression.

Characteristics and Factors Influencing Pore Structure in Shale Oil Reservoirs of Different Lithologies in the Jurassic Lianggaoshan Formation of the Yingshan Gas Field in Central Sichuan Basin

Shale in the Jurassic Lianggaoshan Formation in central Sichuan exhibits strong heterogeneity. The study of the pore structure characteristics of different lithologies is crucial to the selection of the target interval. Shale samples of the Lianggaoshan Formation from well YS5 in the central part of the Sichuan Basin were analyzed using scanning electron microscopy, low-temperature nitrogen adsorption, high-pressure mercury injection (HPMI), and large -field splicing method -based scanning electron microscopy (LFS-SEM) to elucidate the pore structure characteristics of shale and their influencing factors. The mineral composition of the reservoir in the study area was diverse, primarily consisting of clay minerals, followed by quartz and calcite. The reservoir space comprised intergranular, granular, and organic matter pores, and oil was observed to fill the reservoir space. Reservoir characteristics varied with the lithological properties. In clayey shale, intergranular pores located in clay mineral particles and pores between pyrite and natural fractures were mainly observed, with a bimodal distribution of pore size and peak distribution of 10–50 nm and >100 nm. The storage space of ash-bearing shale mainly consisted of intragranular pores and intergranular (crystalline) micropores, with pore sizes primarily concentrated in the 10–50 nm range. The storage space in silty shale mainly developed in clastic mineral particles such as quartz, followed by clay mineral intergranular pores with a relatively wide distribution of sizes. Pores were mainly inkbottle-shaped and slit-type/plate-type pores, with an average specific surface area of approximately 6.9046 m2·g−1 and an average pore volume of approximately 0.0150 cm3·g−1. The full-pore capillary pressure curve was established using a combination of gas adsorption–desorption tests and HPMI. The fractal dimension of the sample pore structure was calculated, and a significant linear correlation was found between clay mineral content and the fractal dimension. Thus, the pore structure characteristics were mainly controlled by the content and distribution of clay minerals.

How pore structure evolves in shale gas extraction: A new fractal model

The reservoir can be divided into four components with different properties: inorganic matrix, hydraulic fracture, natural fracture and kerogen according to the internal structure characteristics and the natural gas migration mode after hydraulic fracturing. Previous studies usually focus on the relationship between reservoir porosity and permeability, but ignore the influence of reservoir microstructure on gas production. The microstructure of different reservoir components can be described by corresponding fractal dimensions. The structure of fractures can be characterized by fractal dimension of fractures and the fractal dimension of pores can characterize the pore structure of inorganic matrix. Considering the complexity of mass transfer between components and structural deformation, in order to describe the evolution of reservoir microstructure and the influence of various factors on gas production, a fully coupled multi-scale fractal model is established. To verify that the model is reliable, the simulation results contrast with the conclusions of field tests. The effects of adsorption parameters, initial diffusion coefficient and compressibility coefficient on gas production and pore structure evolution were studied. The results show that:(1) when the adsorption constant decreases, the variation of the fractal dimension of pore structure becomes more obvious, and the shale reservoir's gas production and pore structure are most sensitive to the volume constant; (2) the deformation of pore structure increases with the increase of effective diffusion coefficient; (3) the change of compressibility of a single medium only has a major impact on the evolution of its own structure.

Reservoir Characteristics and Development Model of Subaqueous Pyroclastic Rocks in a Continental Lacustrine Basin: A Case Study of the Chaganhua Subsag in the Changling Fault Depression, Songliao Basin

Industrial oil and gas eruptions underwater have been found in the pyroclastic rocks of the Huoshiling Formation in the continental lacustrine basin of the Changling fault depression, Songliao Basin. This paper investigates the reservoir space characteristics, physical characteristics, and pore structure differences of subaqueous pyroclastic reservoirs in the Huoshiling Formation, and the causes of physical property differences of different types of reservoirs and their formation and evolution processes are analyzed. (1) The content of volcanic glass in tuff is higher, the reservoir space is dominated by devitrification pores and dissolution pores, and the coarser the grain size, the more favorable the physical properties, with larger pore sizes and higher porosities. The content of clay minerals in sedimentary tuff is high, the pores between clay minerals are the main pores, and the physical properties of sedimentary tuff are poor. The content of soluble components such as feldspar, debris, and laumontite is high in tuffaceous sandstone, which is dominated by dissolution pores. (2) Primary pores are not developed in the pyroclastic reservoirs in the study area, and the reservoirs are relatively dense, with an average porosity of 2.43% and an average permeability of 0.076 mD. The coarse-grained tuff has the highest porosity, followed by tuffaceous sandstone and fine-grained tuff, and the sedimentary tuff has the least favorable physical properties. (3) Devitrification was an important cause of the high-porosity and ultralow permeability of tuff reservoirs. Two oil and gas charges in the middle diagenetic stage led to the organic acid dissolution of rocks. In addition, fractures can provide migration channels for organic acids and deep hydrothermal fluids, leading to late dissolution, and can connect various scattered dissolution pores to improve the effectiveness of the reservoir space. (4) Coarse-grained tuff reservoirs that developed in the proximal facies are favorable targets for hydrocarbon exploration.

Pore Structure and Permeability Characterization of Tight Sandstone Reservoirs: From a Multiscale Perspective

Due to the influence of a sedimentary environment, sandstone characteristics, diagenesis, and geological structure, the complexity and heterogeneity of the pore structure in tight sandstone reservoirs act as key barriers for accurate characterization of the influence of different pore microparameters on reservoir physical properties. This paper obtained different scale microscopic pore–throat parameters through mercury intrusion porosimetry (MIP) and digital core reconstruction models. According to the connectivity of different scale pores, connected pore structure parameters, and pore fractal dimension, the pore structure characteristics of tight sandstone reservoirs were evaluated. Subsequently, through partial correlation analysis, the contribution rate of different scale connected pore parameters to permeability and porosity was clarified. Then, a multiparameter fitting equation for the absolute permeability and porosity of the rock was obtained through multiple regression analysis. The analysis results show that (1) the connected pores of tight sandstone reservoirs are mainly mesopores, with the pore radius distribution between 1 and 3 μm, and throat radius distribution between 0 and 2 μm. (2) The complexity of the pore structure in tight sandstone reservoirs is most strongly correlated with the fractal dimension of the pore structure at the mesoporous scale. (3) The pore radius and throat length at the mesoporous scale have the strongest correlation with the absolute permeability of the rock, and the pore radius at the mesoporous scale has the strongest correlation with the porosity of the rock. (4) The multiparameter fitting equation established by multiple regression analysis quantitatively and qualitatively analyzed the impact of microscopic parameters of the pore–throat structure at different scales on reservoir properties, achieving the purpose of predicting the absolute permeability and porosity of the tight sandstone reservoir. It provides guidance for the study of the pore structure and permeability characteristics of tight sandstones.

Stress sensitivity of multiscale pore structure of shale gas reservoir under fracturing fluid imbibition

Stress sensitivity of multiscale pore structure of shale gas reservoir under fracturing fluid imbibition

Joint Characterization and Fractal Laws of Pore Structure in Low-Rank Coal

The pore structure of low-rank coal reservoirs was highly complex. It was the basis for predicting the gas occurrence and outburst disasters. Different scale pores have different effects on adsorption–desorption, diffusion, and seepage in coalbed methane. To study the pore structure distribution characteristics, which are in different scales of low-rank coal with different metamorphism grade, the pore structure parameters of low-rank coal were obtained by using the mercury injection, N2 adsorption, and CO2 adsorption. These three methods were used to test the pore volume and specific surface area of low-rank coal in their test ranges. Then, the fractal dimension method was used to calculate the fractal characteristics of the pore structure of full aperture section to quantify the complexity of the pore structure. The experimental results showed that the pore volume and specific surface area of low-rank coal were mainly controlled by microporous. The pore fractal characteristics were obvious. With the influence of coalification process, as the degree of coal metamorphism increases, fluctuations in the comprehensive fractal dimension, specific surface area, and pore volume of the pore size range occur within the range of Rmax = 0.50% to 0.65%.

Characterization of reservoir properties and pore structure based on micro-resistivity imaging logging: Porosity spectrum, permeability spectrum, and equivalent capillary pressure curve

According to the capillary theory, an equivalent capillary model of micro-resistivity imaging logging was built. On this basis, the theoretical models of porosity spectrum (ϕi), permeability spectrum (Ki) and equivalent capillary pressure curve (pci) were established to reflect the reservoir heterogeneity. To promote the application of the theoretical models, the Archie's equation was introduced to establish a general model for quantitatively characterizing ϕi, Ki, and pci. Compared with the existing models, it is shown that: (1) the existing porosity spectrum model is the same as the general equation of ϕi; (2) the Ki model can display the permeability spectrum as compared with Purcell's permeability model; (3) the pci model is constructed on a theoretical basis and avoids the limitations of existing models that are built only based on the component of porosity spectrum, as compared with the empirical model of capillary pressure curve. The application in the Permian Maokou Formation of Well TSX in the Central Sichuan paleo-uplift shows that the ϕi, Ki, and pci models can be effectively applied to the identification of reservoir types, calculation of reservoir properties and pore structure parameters, and evaluation of reservoir heterogeneity.

A comprehensive mathematical model for spontaneous imbibition in oil-saturated fractured tight sandstones: Incorporating fracture distribution, displacement pressure, gravity, and buoyancy effects

This paper presents a generalized mathematical model that comprehensively characterizes the flow behavior of matrix nanopores and natural/hydraulic fractures in tight oil reservoirs during spontaneous imbibition. The model incorporates various influencing factors such as fracture distribution, displacement pressure gradient, gravity, and buoyancy. The complex pore structure of tight oil reservoirs, including nanopores and natural microfractures, presents a challenge in developing an accurate mathematical model for predicting flow behavior. The proposed model considers the fractal characteristics of pores and fractures and accounts for many factors to predict cumulative oil production, oil flow rate, and oil recovery factor during imbibition flow. Experimental data on fractured tight sandstones are used to validate the model, and sensitivity analyses are conducted to assess the influence of pore structure parameters, fracture distribution, and fluid properties on imbibition behavior. The findings reveal that gravity and buoyancy effects become more prominent under low interfacial tension. Fracture distribution significantly impacts imbibition behavior, with critical values for fractal dimensions, fracture numbers, and apertures determining the extent of their influence. Higher contact angles and increased oil phase viscosity result in reduced imbibition efficiency. In pressure-driven displacement processes, larger fractures preferentially produce crude oil, and the higher pressure gradients result in shorter imbibition processes. The proposed model offers insights into the imbibition oil recovery mechanism in tight oil reservoirs and can contribute to improved recovery factors.

Study on microscale pore structure and bedding fracture characteristics of shale oil reservoir

Accurately characterizing the cross-scale structure of pores and fractures in shale reservoirs is the theoretical basis for efficient exploration and development of shale oil and gas. In this paper, (a) Based on the research background of different shale maturity and sedimentary characteristics, a three-dimensional model of cross-scale pore-fracture structure is established; (b) Based on a large number of CT characterization data of core pore-fracture structure, the characteristics of pore-fracture development under different geometric dimensions (25 mm and 2 mm) are statistically analyzed; (c) Pore and fracture structures of mixed shale, felsic shale and laminated felsic shale is comparatively studied, and the pore structure and bedding fracture characteristics of shale oil reservoir is revealed. Results show that: (a) for the bedding fracture porosity, felsic shale in Group I is 0.36 %–0.89%; mixed shale in Group I is 0.34 %–0.47%; mixed shale in Group III is 0.12 %–0.86%; mixed shale gravelly dolomite in Group III is 0.13 %–0.15%. (b) Compared with block 1, the laminated felsic shale bedding in block 2 is more developed. (c) CT imaging is based on density difference. Different components of shale samples are distinguished by gray scale.