High-pressure Mercury Intrusion Porosimetry Research Articles

Evolution characteristic and mechanism of microstructure, hydraulic and mechanical behaviors of sandstone treated by acid-rock reaction: Application of in-situ leaching of uranium deposits

The main difficulty in understanding the effects of chemical-physical composite stimulation for low-permeability sandstone-type uranium deposits is clarifying the influence of acidification on pore response mechanism and permeability-mechanical properties evolution during loading-deformation-failure process. Therefore, the acid-rock reaction experiment was first performed, the multiple testing methods (X-ray Diffraction, thin-section identification, high-pressure mercury intrusion porosimetry, stress-seepage coupling experiment) were then conducted, the evolution laws and mechanisms of reservoir physical characteristics after acidification were finally clarified. Results show that after the acid-rock reaction, the contents of calcite, feldspar and kaolinite of samples are decreased and the quartz content is increased, the permeabilities of samples are all promoted, the peak strength, elastic modulus, and shear modulus of samples are reduced and the Poisson’s ratio is raised. The acid-rock reaction changes the energy storage performance and promotes the plasticization of samples. It is suggested to adopt a lower sulfuric acid concentration (2 g/L) and longer reaction time (>45 d) for the ISL of uranium deposits. This work has important theoretical and practical significance for an in-depth understanding of the enhanced mining of low-permeability sandstone-type uranium deposits.

Porosity Characteristics of Coal Seams and the Control Mechanisms of Coal Petrology in the Xishanyao Formation in the Western Part of the Southern Junggar Basin

The porosity characteristics of coal seams serve as a pivotal factor in assessing the development potential of coalbed methane (CBM) resources, significantly influencing the adsorption and permeability capabilities of coal reservoirs, as well as the accumulation, entrapment, and preservation of CBM. In this study, we focused on the coal seams of the Xishanyao Formation in the western part of the southern Junggar Basin (NW China). By leveraging the complementarity of nuclear magnetic resonance (NMR), low-temperature liquid nitrogen experiments, and high-pressure mercury intrusion porosimetry (MIP) in spatial exploration range and precision, we conducted a comprehensive analysis to achieve a fine description of porosity characteristics. Furthermore, we explored the coal petrology factors controlling the pore characteristics of the Xishanyao Formation, aiming to provide geological evidence for the selection of favorable areas and the development potential evaluation of CBM in the study area. The results indicate the following: (1) The total pore volume of the coal samples is 6.318 × 10−3 cm3/g on average, and the micropore volume accounts for a relatively high proportion (averaging 44.17%), followed by the fine pores (averaging 39.41%). The average porosity is approximately 3.87%, indicating good gas storage and connectivity of the coal seams, albeit with some heterogeneity. The coal reservoir is dominated by micropores and fine pores with diameters less than 100 nm, and the pore structure is characterized by low pore volume and high pore area. (2) The pore structure is influenced by both the coalification degree and the coal maceral. Within the range of low coalification, porosity increases with the increase in coalification degree. Building upon this, an increase in the vitrinite content promotes the development of micropores and fine pores, while an increase in the inertinite content promotes the development of meso–macropores. The clay mineral content exhibits a negative correlation with the adsorption pore volume ratio and a positive correlation with the seepage pore volume ratio.

Full-Scale Pore and Microfracture Characterization of Deep Coal Reservoirs: A Case Study of the Benxi Formation Coal in the Daning–Jixian Block, China

The pore-fracture structure of deep coal reservoirs is highly important for evaluating, exploring, and developing coalbed methane (CBM) resources. This study considers three coal samples from the DJ57 well in the Benxi Formation in the Daning–Jixian block on the eastern margin of the Ordos Basin as the research object. Based on the coal quality parameters of the coal samples, field emission scanning electron microscopy (FE-SEM), gas adsorption experiments, high-pressure mercury intrusion porosimetry (MIP), and microcomputed tomography (micro-CT) scanning were used to quantitatively characterize the nanoscale pores and microscale fractures in deep coal reservoirs and to evaluate the pore-fracture structure at different scales. The results reveal that the pore types in the Benxi Formation coal samples are diverse and include mainly organic matter (OM) pores, inorganic pores (intraparticle and interparticle pores), and microfractures. The organic pores are diverse in shape and mainly exhibit round, oval, and wedge shapes, while the microfractures exhibit slender stripes or serrated curves. The multiscale quantitative characterization of deep coal reservoir pores and fractures is based on a variety of pore characterization methods, and the pore and fracture volume distributions are mainly U-shaped, revealing the coexistence of micropores and microfractures. The volumes of micropores (0.3–2 nm), mesopores (2–50 nm), macropores (50 nm to 10 μm), and microfractures (>10 μm) account for 78.00%, 6.78%, 2.08%, and 13.14%, respectively, of the total pore volume (PV). Based on a full-scale pore-fracture splicing calculation, the total permeability of the Benxi Formation coal samples ranges from 5.77 to 28.22 mD. The observation results indicate that the microfractures are connected to each other, forming a network structure with strong connectivity. The microfractures are mainly associated with pore diameters>100 μm, accounting for approximately 95% of the total permeability. Moreover, micropores in deep coal reservoirs provide a large space for CBM adsorption, and microfractures enhance the seepage capacity of CBM.

Influences of lithofacies on fluid mobility in mixed sedimentary rocks: Insights from NMR analysis of the middle Permian Lucaogou Formation, Junggar Basin

The multi-source mixed sedimentation resulted in a unique series of mixed fine-grained sedimentary rocks evolved within the Permian Lucaogou Formation in the Jimusar Sag, located in the southeastern Junggar Basin, China. The variety of lithofacies within this series resulted in pronounced heterogeneity of pore structures, complicating the analysis of fluid occurrence space and state within reservoirs. As a result, the impact of lithofacies on fluid mobility remains ambiguous. In this study, we employed qualitative methods, such as field emission scanning electron microscopy (FE-SEM) and thin section observation, and quantitative analyses, including X-ray diffraction (XRD), total organic carbon (TOC), vitrinite reflectance (Ro), high-pressure mercury intrusion (HPMI) porosimetry, and nuclear magnetic resonance (NMR), along with linear and grey correlation analyses. This approach helped delineate the effective pore characteristics and principal factors influencing movable fluids in the fine-grained mixed rocks of the Lucaogou Formation in the Jimusar Sag, Junggar Basin. The findings indicate the development of three fundamental lithologies within the Lucaogou Formation: fine sandstone, siltstone, and mudstone. Siltstones exhibit the highest movable fluid saturation (MFS), followed by fine sandstones and mudstones sequentially. Fluid mobility is predominantly governed by the content of brittle minerals, the sorting coefficient (Sc), effective pore connectivity (EPC), and the fractal dimension (D2). High content of brittle minerals favors the preservation of intergranular pores and the generation of microcracks, thus offering more occurrence space for movable fluids. A moderate Sc indicates the presence of larger connecting throats between pores, enhancing fluid mobility. Elevated EPC suggests more interconnected pore throat spaces, facilitating fluid movement. A higher D2 implies a more intricate effective pore structure, increasing the surface area of the rough pores and thereby impeding fluid mobility. Ultimately, this study developed a conceptual model that illustrates fluid distribution patterns across different reservoirs in the Lucaogou Formation, incorporating sedimentary contexts. This model also serves as a theoretical framework for assessing fluid mobility and devising engineering strategies for hydrocarbon exploitation in mixed fine-grained sedimentary rocks.

Diagenetic evolution of tight sandstone and the formation of an effective reservoir in the lower member 3 of the Shahejie Formation, Bohai Bay Basin, East China

Heterogeneity in the physical properties of tight sandstones is mainly caused by complex diagenetic interactions in various combinations during the burial process. The tight sandstone oil in the Linnan Sag of Bohai Bay Basin has great development potential but it is unclear how effective reservoirs were formed, and this is a significant reason why exploration in the deep reservoir is so difficult. Here we studied the diagenetic evolution of the tight sandstone of Lower Member 3 of the Shahejie Formation, Linnan Sag, Bohai Bay Basin, by using cores, thin sections, XRD, SEM, grain-size analysis, high-pressure mercury intrusion porosimetry, fluid inclusions, and carbon and oxygen stable isotopes. Compaction, replacement, cementation and dissolution diagenesis are identified; all four processes mainly occur in the A phase of mesodiagenesis. The interaction of formation burial, thermal evolution of organic matter and dehydration of gypsum leads to the alternating presence of three stages of alkaline fluids and two stages of acidic fluids. The average dissolution porosity of the dissolution sandstone facies is greater than the lower limit of the porosity for the effective reservoir in the study area, which is key to the formation of effective reservoirs. By determining differential diagenetic evolution sequences of tight sandstone reservoirs under the constraints of different lithologies where sandstone is interbedded with mudstone, we are able to elucidate the formation of the effective reservoir as follows: (1) In the eodiagenetic stage, a large amount of early carbonate cement developed in the sandstone adjacent to the mudstone, filling the primary pores and forming a cementation sandstone facies. Smaller amounts of early carbonate cement developed in the interior of the sandstone, which “fixed” the primary pores, and has a positive effect on the formation of a large number of secondary pores in the dissolution stage. (2) In the early stage of mesodiagenesis (A1), due to the filling of primary pores, it is difficult for acidic fluids to enter the cementation sandstone facies adjacent to mudstone, and the dissolution is weak. But dissolution within the sand body was strong, producing a large number of dissolution pores and forming a dissolution sandstone facies that clearly enhanced the physical properties. (3) In a second early stage of mesodiagenesis (A2), dissolution still played a dominant role in the dissolution sandstone facies, due to the development of dissolution pores in the previous stage (it is easy for acidic fluids to enter the dissolution sandstone facies). The physical properties of the dissolution sandstone facies were once again enhanced and an effective reservoir gradually began to form. (4) At the end of mesodiagenesis stages A1 and A2 (26.2–24.6 Ma; 7.5–2.8 Ma), the reservoir experienced two phases of petroleum charging. The charging of the cementation sandstone facies developed at the margins of the sandstones was difficult due to the filling of primary pores. The dissolution sandstone facies are oil-bearing, with higher porosity, which indicates an effective reservoir. By coupling the thermal evolution of organic matter and the dehydration of gypsum with differential diagenetic evolution and the porosity evolution of reservoir, we are able to establish a reservoir genetic model that involves alternating seepage of organic acids and alkaline brines.

Influence of extractable organic components on shale wettability: Dongyuemiao member of Jurassic Ziliujing formation in the Fuxing area, Eastern Sichuan Basin

The wettability of reservoir rocks is a critical factor for the petroleum exploration and recovery, which plays an important role on relative permeability, capillary pressure, and ultimate recovery. This study aims to characterize the difference in wettability before and after soxhlet extraction, and reveal the influences of mineral composition, pore structure and extractable organic components on wettability of shales with different lithofacies. Several organic shale samples from the Dongyuemiao (DYM) section of the Jurassic Ziliujing (ZLJ) formation were collected to investigate the mineral composition, pore-size distribution, wettability characteristics and determine the main controlling factors on wettability alteration. Pore type and abundant are observed using argon ion polishing scanning electron microscopy. The pore volume (PV) and pore size distribution (PSD) characteristics before and after extraction were obtained using a combination of nitrogen physisorption and high-pressure mercury intrusion porosimetry (MIP). Spontaneous imbibition (SI) and nuclear magnetic resonance (NMR) experiments were used to investigate the wettability characteristics before and after extraction.Results show that clay, quartz and calcite are dominant minerals in the DYM shales, and three typical lithofacies are identified, including mixed shale (M), argillaceous shale (CM) and calcareous shale (C). Clay mineral interP pore is the dominant pore type in the DYM shales, followed by organic matter (OM) pore. Before the extraction, the DYM shale is more oil lipophilic, while its wettability alters slightly after the extraction. The M shales and C shales maintain lipophilic, while as the CM shales alters from oil wet to mixed wet. Samples with higher quartz have better connectivity of the hydrophilic and lipophilic pore networks, and carbonate minerals play an opposite role. During the extraction process, polar solvents could react with clay minerals to cause pore space expansion, which enhances the water wettability after extraction. Due to the low OM content and poor organic clay complex related pores in the study area, clay minerals have not significant correlation with oil wettability, but influence the water wettability. No correlation occurs between total organic carbon (TOC) content and oil/water wettability of shales before and after extraction. In comparison, macropore has a significant impact on water wettability, while micropore and mesopore play significant impact on oil wettability.

Paleo-Environment Induced Full-Scale Pore Variation in the Low Matured Shale: A Case Study of the Third Member of the Jiufotang Formation at the Lujiapu Rift Basin, Northeast China

Shale in the third member of the Jiufotang Formation at the Lujiapu Rift Basin is a new potential target for shale oil exploration and has rarely been studied before. In order to study pore structure and its controlling factors, shale compositions are mainly analyzed by X-ray Diffraction (XRD), and the characterization of full-scale pore structures is studied by the field-emission scanning electron microscope (FE-SEM), low-temperature N2 adsorption, and high-pressure mercury intrusion porosimetry (high-pressure MIP). According to composition and micro-texture, shale samples in the third member of the Jiufotang Formation are classified into three types: laminated organic matter-lean shale (TOC < 2%), unlaminated organic matter-intermediate shale (2% < TOC < 4%) and laminated organic matter-rich shale (TOC > 4%). Most shale samples are dominated by interparticle pores, with many of them filled by diagenetic minerals. All the shale samples are most developed in mesopores, whose development is mainly controlled by quartz content. And macropores with a diameter of 10,000 nm~100,000 nm are the secondary developed pores, which are influenced by both the paleoenvironment and diagenesis (especially clay transformation). Full-scale pore variations in laminated organic matter-lean shale, unlaminated organic matter-intermediate shale, and laminated organic matter-rich shale are ultimately related to their paleoenvironments.

Spatial characteristics and geological implications of shale reservoirs of different lithotypes in the third member of Shahejie Formation in Qikou Sag, Bohai Bay Basin

Mudstone and shale formations developed in the first sub-member of the third member of the Shahejie Formation (Es31 Member) in the Qikou Sag, Bohai Bay Basin due to continuous lacustrine sedimentation. Atomic force microscopy, nitrogen adsorption, high-pressure mercury intrusion porosimetry, and field emission scanning electron microscopy were used to quantify the pore structure of the three main lithofacies in the study area. The results show that the average porosity and permeability of the mudstone are 3.54% and 0.00087 md, respectively. The pore structure is complex, and only the laminated shale has a high correlation between porosity and permeability. The laminated shale contains intergranular and intercrystalline pores, whereas the bedded shale primarily has intergranular dissolution pores and intergranular pores. The pore diameters of the two shales are predominantly at the submicron level. The pores of the laminated shale are located in and between the felsic laminae, and the pore connectivity is high. This lithofacies type is believed to be the most promising location for continental shale oil exploration in desert regions. The bedded shale is dominated by isolated pores with a large pore radius and large fluctuation. In contrast, to the laminated shale, the bedded shale has a high content of brittle minerals and low bedding density and is more likely to produce high-angle hydraulic fractures. The rock facies should be the focus of future shale oil evaluations in desert regions.

Pore structure and pore size change for tight sandstone treated with supercritical CO2 fluid

The effects of ScCO2 on pore structure should be investigated in order to properly apply supercritical carbon dioxide (ScCO2) fracturing on tight sandstone. ScCO2 treatment was applied to three sets of tight sandstone samples. The pore structure was characterized using a combination of high-pressure mercury intrusion porosimetry and nuclear magnetic resonance. Furthermore, the pore size distribution’s multi-fractal dimensions were estimated. After SCCO2 treatment, the number of transitional pores decreased significantly, while the number of mesopores and macropores increased. At all scales, the fractal dimension characteristics indicate that pore structure gets more complicated and heterogeneous. Furthermore, due to their larger contact area, large pores have a higher fractal dimension than small pores. The accumulative pore volume of the calcite-rich group increases and a decreasing trend occurs for the calcite-rare group. The content of calcite sharply decreased while clay, feldspar, and plagioclase content have a slight drop after ScCO2 treatment, which affects the alternation of pore structure. Thus, the accumulative porosity volume and pore connectivity do not always increase after ScCO2 exposure because re-precipitation and fine migration can potentially clog pores and channels.

Geochemical reactions altering the mineralogical and multiscale pore characteristics of uranium-bearing reservoirs during CO2 + O2in situ leaching

CO2 + O2in situ leaching has been extensively applied in uranium recovery in sandstone-type uranium deposits of China. The geochemical processes impact and constrain the leaching reaction and leaching solution migration; thus, it is necessary to study the CO2 + O2–water–rock geochemical reaction process and its influence on the physical properties of uranium-bearing reservoirs. In this work, a CO2 + O2–water–rock geochemical reaction simulation experiment was carried out, and the mineralogical and multiscale pore characteristics of typical samples before and after this simulation experiment were compared by X-ray diffraction and high-pressure mercury intrusion porosimetry (HPMIP). The results show that the CO2 + O2–water–rock geochemical reaction has complicated effects on the mineral compositions due to the various reaction modes and types. After the CO2 + O2–water–rock geochemical reaction, the femic minerals decrease and the clay minerals in the coarse sandstone, medium sandstone, fine sandstone, and siltstone increase, while the femic minerals and clay minerals in sandy mudstone show a contrary changing trend. The CO2 + O2–water–rock geochemical reaction decreases the total pore volume of uranium-bearing reservoirs and then promotes pore transformation from small scale to large scale. The fractal dimensions of macropores are decreased, and the fractal dimensions of mesopores, transition pores, and micropores are increased. The effects of felsic mineral and carbonate dissolution, secondary mineral precipitate, clay mineral swelling, and mineral particle migration are simultaneously present in the CO2 + O2in situ leaching process, which exhibit the positive transformation and the negative transformation for the uranium-bearing reservoirs. The mineral dissolution may improve reservoir permeability to a certain degree, while the siltation effect will gradually reveal with the extension of CO2 + O2in situ leaching. This research will provide a deep understanding of the physical property response of uranium-bearing reservoirs during CO2 + O2in situ leaching and indicate the direction for the efficient recovery of uranium resources.

Differential effects of pore structure of mineral and maceral components on the methane adsorption capacity evolution of the lower jurassic Da'anzhai member of the Ziliujing Formation lacustrine shale, Sichuan Basin, China

Adsorbed gas makes a great contribution to shale gas reserves. During the geological evolution process, it is of prominent significance to clarify the dynamic evolution mechanism of methane adsorption capacity (MAC) of shale to enhance exploration. Variations of the pore structure and surface properties of shales lead to their different MAC. However, the pore structure characteristics and the evolution mechanism of different maceral and mineral components is different. The co-evolution modes and influence mechanism on the MAC of shale remains poorly understood. Therefore, in order to investigate the influential relationship between pore structure evolution and MAC of shales, methane adsorption experiments were conducted on a series of shale samples with the same composition at different thermal maturities. In addition, the original components of the shale sample were analyzed by measuring total organic carbon (TOC) content and mineral composition. Pore structures of the four shale samples were characterized by N2 adsorption, high-pressure mercury intrusion porosimetry (HPMIP), and digital analyses of field-emission scanning electron microscopy (FE-SEM). The results showed a good correlation between the APpore (apparent porosity of pore) of organic pores with the size ranging from 10 to 30 nm and MAC (R2 = 0.943), confirming the prominent influence of organic pores on the MAC of shale. In addition, the APpore of pores within 10–30 nm and aspect ratio of secondary organic matter with spongy pores are highly correlated with MAC (R2 are 0.833 and 0.811, respectively), which suggests that secondary organic matter with spongy pores have a crucial influence on MAC. Clay mineral pores with a pore size of 10–30 nm also effect the MAC of shale. A large number of clay mineral microfractures, with a scale of less than 200 nm, appear to effectively connect organic pores, providing a viable mechanism for hydrocarbon migration and enhancing the MAC of shale. Siliceous mineral dissolution pores and microfractures are not conducive to hydrocarbon migration due to their inability to form effective connections with organic pores and fractures and showing a weak correlation with MAC. The outcome of this study elucidates the main controlling mechanism affecting methane adsorption behavior of continental shale reservoirs and provides a path for the efficient exploration and evaluation of shale gas under actual geological conditions.

Shale Lithofacies and Its Effect on Reservoir Formation in Lower Permian Alkaline Lacustrine Fengcheng Formation, Junggar Basin, NW China

Lower Permian Fengcheng Formation is considered to be a high-quality alkaline lacustrine shale oil resource in the Junggar Basin, NW China. Based on core and thin section observation, X-ray diffraction, scanning electron microscope, low-pressure N2 adsorption, and high-pressure mercury intrusion porosimetry, different shale lithofacies, and pore structures were examined. According to the mineral composition, shales in well My 1 are divided into five types: dolomitic mudstone, calcareous mudstone, siliceous mudstone, tuffaceous mudstone, and argillaceous mudstone, each of which shows its pore structure distribution. Intragranular pores, inter-crystalline pores associated with clays and pyrites, dissolution pores, and microfractures were commonly observed. There are three segments of pore structures including <50 nm, 50 nm-4 μm, and >4 μm. Clay minerals mainly contribute to mesopores, especially in argillaceous mudstones. The dissolution of carbonate minerals and feldspars is significant for macropores predominantly in dolomitic mudstones and tuffaceous mudstones, respectively. Micron-scale microfractures associated with laminae dominate in dolomitic mudstones. Therefore, the dolomitic mudstones, especially with lamination, and tuffaceous mudstones are proposed to be favored shale lithofacies with great exploration potential in the Mahu Sag.

Classification and Evaluation of Shale Oil Reservoirs of the Chang 71-2 Sub-Member in the Longdong Area

Establishing a suitable classification and evaluation scheme is crucial for sweet spot prediction and efficient development of shale oil in the Chang 71-2 sub-member of the Longdong area. In this paper, a series of experiments, such as casting thin sections (CTS), scanning electron microscopy (SEM), low-temperature nitrogen adsorption (LTNA), high-pressure mercury intrusion porosimetry (HMIP), and nuclear magnetic resonance (NMR), were integrated to classify the pore throats and shale oil reservoirs in the study area. Moreover, the pore structure characteristics of different types of reservoirs and their contributions to productivity were revealed. The results show that the pore-throat system can be divided into four parts: large pore throats (>0.2 μm), medium pore throats (0.08~0.2 μm), small pore throats (0.03~0.08 μm), and micropore throats (<0.03 μm). Based on the development degree of various pore throats, the reservoir is divided into four types: type I (Φ ≥ 10%, K > 0.1 mD), type II (Φ ≥ 8%, 0.05 mD < K < 0.1 mD), type III (Φ ≥ 5%, 0.02 mD < K < 0.05 mD) and type IV (Φ < 5% or K < 0.02 mD). From type I to IV reservoirs, the proportion of dissolved pores and intergranular pores gradually decreases, and the proportion of intercrystalline pores increases. The proportion of large pore throats gradually decreases, and the proportions of medium pore throats and small pore throats increase initially and then decrease, while the proportion of micropore throats increases successively. The NMR pore size distribution changes from the right peak to the left peak. The developed section of the type I reservoir corresponds to the oil layer, and the developed section of the type I and II reservoirs corresponds to the poor oil layer. In contrast, the developed section of the type III and IV reservoirs corresponds to the dry layer. The daily production from single wells is primarily attributable to type I and II reservoirs.

Genetic mechanism of low resistivity in high-mature marine shale: Insights from the study on pore structure and organic matter graphitization

Low-resistance shale reservoirs have prospected in many high-mature shale gas plays with distinct yields. It is worth investigating the reasons for the difference in the production of low-resistance shale. And this needs to start from the genetic mechanism of shale low resistance. The genesis of shale low resistance is currently considered to be closely related to high-mature organic matter, which is the most important storage space for shale gas. Therefore, it is necessary to study the relationship among organic matter properties, pore structure of shale reservoir space, and shale resistivity. Herein, the typical low-resistivity shale in southern China was examined using X-ray photoelectron spectroscopy, gas adsorption, high-pressure mercury intrusion porosimetry. The results show that compared with conventional resistivity shale, low resistivity shale has smaller pore volume and specific surface area and higher organic matter graphitization degree. The high degree of graphitization significantly reduces the rock resistivity. In addition, graphitization changes the mechanical properties of organic matter. Under the action of compaction and tectonic movement, the macropores decrease sharply, the mesopores increase first and then decrease, and the micropores change little with the degree of graphitization. The change in the size and shape of the organic pores results in the collapse of the organic pores and the contact of the pore walls, which further increases the migration path of the electronic currency on the conductive organic matter and makes the rock resistivity lower. When the degree of graphitization exceeds 15%, poor pore development leads to lower resistivity, and due to poor reservoir space, such shales are extremely risky for exploration.

The comparative study of shale pore structure between outcrop and core samples of Ziliujing Formation shale from the northeastern Sichuan Basin in China

The pore structure controls the storage and migration of geofluids within shale and ultimately determines its reservoir quality. Therefore, the characterization of shale pore structure has become more and more meaningful in geological engineering research. Due to the complicate sampling procedure and relatively high cost, the shale core samples are usually less in quantity and quite precious. Consequently, the shale outcrop samples, which were deposited in the similar sedimentary environment with shale core samples in the same layer, are always used to indicate reservoir characteristics. However, the pore structure similarities and differences between shale outcrop and core samples in the same layer is still unknown, which restricts the effective use of outcrop samples in shale pore structure characterization and requires detailed investigation. In this study, the pore structure of the outcrop and core samples of Jurassic Ziliujing Formation shale with high clay content from the Northeastern Sichuan Basin in China is quantitatively characterized by N2 adsorption and high-pressure mercury intrusion porosimetry (HPMIP) experiment and is semi-quantitatively revealed by field emission scanning electron microscope (FE-SEM) experiment. The results show that there is an obvious pore structure parameter difference between outcrop and core samples: the average specific surface area of outcrop samples is 8.47 times that of core samples, the average pore volume of outcrop samples is 1.83 times that of core samples; the average microfracture development level of outcrop samples is 1.43 times that of core samples, which is mainly caused by the higher microfracture development level of clay minerals in outcrop samples; the microfracture development direction is chaos in outcrop samples but relatively in order in core samples. However, there are still some pore structure similarities between outcrop and core samples: the whole-aperture pore structure distribution of outcrop and core samples has two similar distribution peaks at 15 ∼22 nm and 25 ∼42 nm; outcrop samples and core samples have similar pore space contributors: clay minerals (CM) pores > organic matter (OM) pores + quartz and feldspar (QF) pores while microfractures are mainly provided by clay minerals; the pore size distribution of OM and QF pores in outcrop samples were also similar to core samples. Overall, the pore structure of outcrop samples has certain indicative significance in terms of main pore size distribution interval, the relative contribution of different types of pores and the pore characteristics of OM, which shows the limited applicability of outcrop samples in shale pore structure characterization.

Laminae characteristics of lacustrine shales from the Paleogene Kongdian Formation in the Cangdong Sag, Bohai Bay Basin, China: Why do laminated shales have better reservoir physical properties?

Laminae are the most typical and representive sedimentary feature in organic-rich shales, and revealing their influences on the reservoir physical properties is vital to understand the oil enrichment mechanisms of lacustrine shale. This study investigated the laminae characteristics and their effects on the physical properties of the shales from the Second Member of the Kongdian Formation (Ek2). The research presented in this study is based on core and thin section observations, XRD analysis, low-pressure nitrogen physisorption (LNP), high-pressure mercury intrusion porosimetry (MIP), nuclear magnetic resonance (NMR), and scanning electron microscopy (SEM). The results show that the Ek2 shales developed massive and laminated sedimentary structures. The laminae can be categorized as siliceous laminae, dolomite laminae, clay-rich siliceous laminae, organic matter laminae, and calcite laminae. Analysis of SEM, LNP, MIP, and NMR show that macropores and micro-fractures contribute significantly to the total pore volume of laminated samples, while micropores and mesopores are the dominant pore types in massive samples. The pore structure and connectivity of the laminated samples are better than that of the massive samples. Comparison of laminar and massive mudstones in the Ek2 showed that the development of laminae physical properties that are more conducive for reservoir formation as a result of interlaminated fractures, optimized arrangement of minerals, and improved organic-inorganic interactions.

Classifications of the Reservoir Space of Tight Sandstone Based on Pore Structure, Connectivity, and Fractal Character: A Case Study from the Chang 7 Member of the Triassic Yanchang Formation in the Ordos Basin, China.

Pore structure characteristics of tight sandstones, including pore types, connectivity, and morphological features, provides a basis for selecting the “sweet spot” in tight sandstone reservoirs. A variety of research methods, high-pressure mercury intrusion porosimetry, cast thin sections, scanning electron microscopy, and fractal theory were integrated to explore these parameters of tight sandstones from the Chang 7 member of the Triassic Yanchang Formation in the Ordos Basin, China. Results indicate that tight sandstones are defined by three pore types with distinct fractal dimensions and corresponding pore structure, which are combined pores, isolated grain pores, and clay-dominated pores. The pore spaces of the three types gradually evolve from the microscale to the nanoscale. Combined pores were formed by dissolution pores connected to the surrounding pores and have been distinguished by their irregular shape. Their connected paths are multidirectional, resulting in better connectivity. Isolated grain pores have a small number of poorly connected paths, which causes weak connectivity. Clay-dominated pores have narrow and complex connected paths, resulting in poor connectivity. From the combined pore to the clay-dominated pore, the fractal dimensions of pore spaces decrease, indicating that the heterogeneity of pore spaces is gradually weakened whereas the heterogeneity of the flow characteristics is gradually enhanced. On the basis of the proportions of the three pore types, the tight sandstones can be genetically classified into a combined pore type, an isolated grain pore type, and a clay-dominated pore type. The differences in pore space and heterogeneity affect the distribution of tight oil; therefore, sand bodies located near the source rock, characterized by strong dissolution and dominated by the combined pore type, are favorable zones for tight sandstone reservoirs.

Characterization of the Full-Sized Pore Structure and Controlling Factors of the Coal-Bearing Shale in the Wuxiang Block, South-Central Qinshui Basin, China

The characterization of the full-sized pore structure is important for the evaluation and prediction of the reservoir of shale gas with strong heterogeneity. It is of great scientific significance to explore the pore structure characteristics of overmature coal-bearing shale. Core descriptions, X-ray diffraction (XRD), vitrinite reflectance (Ro), field emission scanning electron microscopy (FE-SEM), high-pressure mercury intrusion porosimetry (MIP), and low-pressure N2/CO2 gas adsorption (N2-/CO2-GA) experiments were performed on overmature coal-bearing shale samples from the Wuxiang block, south-central Qinshui Basin, China. The results show that the total organic carbon (TOC) ranged from 0.29 to 8.36%, with an average of 3.84%, and the organic matter (OM) is dominated by type III kerogen. The minerals in the shale primarily consist of clay (43–85.5%, averaging 52.1%) and quartz (12.6–61.2%, averaging 43.5%). The major clay minerals are illite-smectite (I/S) and illite, ranging from 22.5 to 55.6% (mean 41.4%) and 8.7–52.7% (mean 32%), respectively. FE-SEM images reveal that intraparticle pores (IntraP pores) and interparticle pores (InterP pores) are widely developed in clay minerals, and organic pores are occasionally present. Mesopores make the greatest contribution to the total pore volume (PV), and micropores are the major contributors to the specific surface area (SSA). Clays are the main controllers of micropore development. Mesopores developed in the clay mineral layers are promoted by I/S but inhibited by illite. Macropores and microfractures are mainly developed in clays and quartz and do not correlate significantly with the TOC, or mineral composition, due to the influence of compaction and cementation. The TOC and minerals affect pore structure characteristics mainly by influencing micropores.

The upper and lower limits and grading evaluation of the Shahezi tight gas reservoirs in the Xujiaweizi Rift, northern Songliao Basin: Implications from microscopic pore structures

The upper and lower limits and grading evaluation scheme of tight gas reservoirs (TGRs) at a microscopic pore structure level were explored by conducting high-pressure mercury intrusion porosimetry (HMIP), rate-controlled mercury intrusion porosimetry, nuclear magnetic resonance (NMR), and wettability experiments on tight rock samples from the Lower Cretaceous Shahezi (SHZ) Formation in the Xujiaweizi Rift, northern Songliao Basin. The results showed that the upper throat radius limit of the SHZ TGRs corresponds to 1.86 μm, derived from the microscopic equilibrium state of buoyance and capillary forces. The above value is closely related to several geological factors, including a pore-to-throat radius ratio, the density difference between formation water and gas, formation dip angle, gas–water interfacial tension, and wettability. The SHZ Formation enters a tight reservoir stage when the burial depth is deeper than 3460 m. A new method integrating HMIP and NMR experiments was proposed to estimate the thickness of the adsorbed water film with a value of ∼21.56 nm. The theoretical lower throat radius limit of the SHZ TGRs was determined as ∼22 nm, considering the individual methane dimension. Natural gas can be scarcely injected into tight reservoirs below the theoretical lower limit, serving as theoretically invalid tight reservoirs in the study area. From the configuration relationship between pores and throats, two TGR types were identified in the SHZ Formation (types I and II). Type-I TGRs are characterized by relatively excellent seepage capacity, with the maximum connected throat radius and permeability of 0.4 μm–1.86 μm and (0.015–0.27) × 10−3 μm2, respectively, and their storage space mainly comprises abundant dissolution and residual intergranular pores. Furthermore, an adequate storage space (3.6% to more than 12%) and an appropriate burial depth (<5000 m) promote type-I TGRs to be the most favorable targets for current SHZ tight gas accumulation development in the Xujiaweizi Rift.

Comparative Study of Pore Structure Characteristics between Mudstone and Coal under Different Particle Size Conditions

In order to investigate the difference of pore structure characteristics between mudstone and coal under different particle size conditions, samples acquired from Henan province were smashed and screened into three different particle sizes (20–40, 80–100, and &gt;200 mesh) to conduct the experiments, using the high-pressure mercury intrusion porosimetry (MIP) and low-temperature N2 adsorption (LT-N2A) techniques. The results demonstrated that the proportion of open pores or semi-enclosed pores increased, and the pores became preferable contacted each other for both mudstone and coal during the crushing process. These variations of pore structure characteristics in the coal were beneficial to methane storage and migration. The total specific surface areas and pore volumes all showed a tendency of increasing continually for both mudstone and coal, as the particle sizes decreased from the LT-N2A test. The mudstone and coal were non-rigid aggregates with micropores, plate-shaped pores, and slit-shaped pores developed inside. The effect of the crushing process on the pore shape for the mudstone and coal was inappreciable. Moreover, the influence of the particle sizes on the mesopore was the most significant, followed by the macropore; and on the micropore, the influence was negligible for both mudstone and coal. The crushing process only had a significant impact on the pore structure of mudstone with a particle size of less than 100 mesh, while it could still alter the pore structure of coal with a particle size of larger than 100 mesh. It is believed that this work has a significant meaning to explore the diffusion and migration rules of coal-bed methane in coal.