Effect of pore structure on shale oil accumulation in the lower third member of the Shahejie formation,Zhanhua Sag,eastern China: Evidence from gas adsorption and nuclear magnetic resonance

As shale oil occurs primarily in micro–nano pores and fractures, research about the effect of pore structure on shale oil accumulation has great significance for shale oil exploration and development. The effect of pore structure on shale oil accumulation in the lower third member of the Shahejie formation (Es₃^l), Zhanhua Sag, eastern China was investigated using gas adsorption, soxhlet extraction, nuclear magnetic resonance (NMR) analysis, and field emission scanning electron microscope (FE-SEM) observation. The results indicated that the samples contained a larger amount of ink-bottle-shaped and slit-shaped pores after extraction than before extraction. The pore volume and specific surface area of the samples were approximately 2.5 times larger after extraction than before extraction. Residual hydrocarbon occurred primarily in the free-state form in pores with diameters of 10–1000 nm, which can provide sufficient pore volume for free hydrocarbon accumulation. Therefore, pores with diameters of 10–1000 nm were regarded as “oil-enriched pores”, which are effective pores for shale oil exploration, whereas pores with diameters smaller than 10 nm were regarded as “oil-ineffective pores”. Samples with only well-developed small pores with diameters smaller than 1000 nm showed high oil saturation, whereas samples with both small pores and also relatively large pores and micro-fractures presented low oil saturation. As the minimum pore size allowing fluid expulsion is 1000 nm, pores with diameters greater than 1000 nm were considered as “oil-percolated pores”. Large pores and micro-fractures are generally interconnected and may even form a complex fracture mesh, which greatly improves the permeability of shale reservoirs and is beneficial to fluid discharge.     

Qualitative and quantitative characterization of a transitional shale reservoir: A case study from the Upper Carboniferous Taiyuan shale in the eastern uplift of Liaohe Depression,China

The paper takes the Upper Carboniferous Taiyuan shale in eastern uplift of Liaohe depression as an example to qualitatively and quantitatively characterize the transitional (coal-associated coastal swamp) shale reservoir. Focused Ion Beam Scanning Electron Microscope (FIB-SEM), nano-CT, helium pycnometry, high-pressure mercury intrusion and low-pressure gas (N₂ & CO₂) adsorption for eight shale samples were taken to investigate the pore structures. Four types of pores, i.e., organic matter (OM) pores, interparticle (InterP) pores, intraparticle (IntraP) pores and micro-fractures are identified in the shale reservoir. Among them, intraP pores and micro-fractures are the major pore types. Slit-shaped pores are the major shape in the pore system, and the connectivity of the pore-throat system is interpreted to be moderate, which is subordinate to marine shale. The porosity from three dimension (3D) reconstruction of SEM images is lower than the porosity of helium pycnometry, while the porosity trend of the above two methods is the same. Combination of mercury intrusion and gas absorption reveals that nanometer-scale pores provide the main storage space, accounting for 87.16% of the pore volume and 99.85% of the surface area. Micropores contribute 34.74% of the total pore volume and 74.92% of the total pore surface area; and mesopores account for 48.27% of the total pore volume and 24.93% of the total pore surface area; and macropores contribute 16.99% of the total pore volume and 0.15% of the total pore surface area. Pores with a diameter of less than 10 nm contribute the most to the pore volume and the surface area, accounting for 70.29% and 97.70%, respectively. Based on single factor analysis, clay minerals are positively related to the volume and surface area of micropores, mesopores and macropores, which finally control the free gas in pores and adsorbed gas content on surface area. Unlike marine shale, TOC contributes little to the development of micropores. Brittle minerals inhibit pore development of Taiyuan shale, which proves the influence of clay minerals in the pore system.     

Nano-scale pore structure and fractal dimension of organic-rich Wufeng-Longmaxi shale from Jiaoshiba area,Sichuan Basin: Investigations using FE-SEM,gas adsorption and helium pycnometry

Much attention have been recently paid to the upper Ordovician Wufeng shale (O₃w) and lower Silurian Longmaxi shale (S₁l) in the Jiaoshiba area of Sichuan Basin, which is now the largest producing shale gas field in China. Field emission scanning electron microscopy (FE-SEM), low pressure gas (N₂ and CO₂) adsorption, helium pycnometry, X-ray diffraction and geochemical analyses were performed to investigate the pore structure and fractal dimension of the pores in O₃w-S₁l shale formation in the Jiaoshiba area. FE-SEM images show that organic matter (OM) pores are dominant in the organic-rich samples and these pores are often irregular, bubble-like, elliptical and faveolate in shape, while in organic-poor samples, limited and isolated interparticle (interP), intraparticle (intraP) and OM pores are observed. Reversed S-shaped isotherms obtained from nitrogen adsorption are type Ⅱ, and hysteresis loops indicate that the shape of micropore in the samples is slit-or plate-like. BET surface areas and total pore volume vary from 12.2 to 27.1 m²/g and from 1.8 × 10⁻² to 2.9 × 10⁻² cm³/g, with an average of 19.5 m²/g and 2.3 × 10⁻² cm³/g, respectively. Adsorption volume from both N₂ and CO₂ adsorption increases with respect to TOC contents. Porosities obtained from helium porosimetry are comparable with these from gas (CO₂ and N₂) adsorption in O₃w-S₁l shale. However, porosity determined by quantitative FE-SEM analysis is much smaller, which is mainly related to limited resolution and the small areas of investigation.Based on the Frenkel-Halsey-Hill (FHH) model of low-pressure N₂ adsorption, fractal dimensions of the pores varied from 2.737 to 2.823. Relationships between pore structure parameters and TOC content, mineral composition and fractal dimension reveal that the fractal dimension is mainly associated with micropores. Samples with higher TOC content, higher quartz content and lower clay content tend to contain more heterogeneous micropores, resulting in higher fractal dimensions and more complicated pore structure in shales. Therefore, fractal dimension is an effective parameter to reflect the complexity of pore structure and the degree of micropore development in O₃w-S₁l shale.     

Pore structure characteristics of tight sandstones in the northern Songliao Basin,China

Understanding the pore structure characteristics of tight gas sandstones is the primary purpose of reservoir evaluation and efforts to characterize tight gas transport and storage mechanisms and their controls. Due to the various pore types and multi-scale pore sizes in tight reservoirs, it is essential to combine several techniques to characterize pore structure. Scanning electron microscopy (SEM), nitrogen gas adsorption (N₂GA), mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) were conducted on tight sandstones from the Lower Cretaceous Shahezi Formation in the northern Songliao Basin to investigate pore structure characteristics systematically (e.g., type and size distribution of pores) and to establish how significant porosity and permeability are for different pore types. The studied tight sandstones are composed of intergranular pores, dissolution pores and intercrystalline pores. The integration of N₂GA and NMR can be used as an efficient method to uncover full pore size distribution (PSD) of tight sandstones, with pore sizes ranging from 2 nm to dozens of microns. The full PSDs indicate that the pore sizes of tight sandstones are primarily distributed within 1.0 μm. With an increase in porosity and permeability, pores with larger sizes contribute more to porosity. Intercrystalline pores and intergranular/dissolution pores can be clearly distinguished on the basis of mercury intrusion and surface fractal. The relative contribution of intercrystalline pores to porosity ranges from 58.43% to 91.74% with an average of 79.74%. The intercrystalline pores are the primary contributor to pore space, whereas intergranular/dissolution pores make a considerably greater contribution to permeability. A specific quantity of intergranular/dissolution pores is the key to producing high porosity and permeability in tight sandstone reservoirs. The new two permeability estimation models show an applicable estimation of permeability with R² values of 0.955 and 0.962 for models using D_max (pore diameter corresponding to displacement pressure) and D_f (pore diameter at inflection point), respectively. These results indicate that both D_max and D_f are key factors in determining permeability.     

Porous Structure of Tailings of Marine Manganese Nodules and Crusts as Deduced from the Adsorption of Nitrogen

Tailings of marine manganese nodules and crusts have many useful properties. One property in particular which could be of great significance is their high gas adsorption capacity. This capacity has a direct relationship with the pore structure of the tailings. The present investigation deals with the size, volume, surface area, and distribution of pores in the tailings via nitrogen adsorption-desorption techniques. The results show that the pore diameter of these tailings varies between 1.203 and 243.6 nm. The most frequent diameter of pores is 2 to 50 nm. These are classified as mesopores. The Barrett-Joyner-Halenda adsorption pore diameter is 1.203 to 14.078 nm. The small pores give the largest contribution to pore surface area. The large pores give the biggest contribution to pore volume. The pores could be derived from several sources. These include: (a) the amorphous fraction of the tailings which has been calcined, (b) the accumulative clearances between nanometer grains or crystals, and (c) the original porosity of the marine minerals.     

Characteristics and controlling factors of reservoir space of mudstone and shale in Es3x in the Zhanhua Sag

Zhanhua Sag is a widely accepted target zone with huge exploration and development potential for shale oil and shale gas resources. Many detailed studies have been undertaken around the geochemistry of the lower section of the third member of the Shahejie Formation (Es3x), while few studies have focused on the reservoir. In this study, based on the mineralogical features and geochemical characteristics, and by using statistical methods, the characteristics and controlling factors of reservoir space of mudstone and shale in Es3x in the Zhanhua Sag are explored through field-emission scanning electron microscopy (FE-SEM), high pressure mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR) techniques. Three major findings were obtained. ① There are micropores and microfractures in the reservoir space, which include intergranular pores, clay intercrystal pores, pyrite intercrystal pores, dissolved pores, structural microfractures, and bedding microfractures. ② According to the features of pore size distribution (PSD), the pore distribution can be divided into the following three categories: 0–50 nm, 50 nm–2 μm, and >2 μm; the average volumes of these components are 0.01079 mL g⁻¹, 0.00361 mL g⁻¹, and 0.00355 mL g⁻¹, respectively, thus showing that the pores whose radii are distributed at 0–50 nm form the most important reservoir space (though those with the 50 nm–2 μm and >2 μm radii are also important and cannot be ignored). ③ There are different controlling factors when it comes to different scale pores. Based on statistics and FE-SEM results, the dissolved pores in calcite were determined to be the controlling factor for the 0–50 nm portion, the intercrystalline pores in clay and pyrite, and intergranular pores between authigenic minerals (calcite, dolomite, and pyrite) and clastic minerals (calcite and dolomite) were determined to be the controlling factors for the 50 nm–2 μm portion, and the structural microfractures and bedding microfractures were determined to be the main factors for the >2 μm portion. Furthermore, it is the brittle minerals content and bedded structure that control the microfractures. This study thus clarifies the types and characteristics of reservoir space and identifies pore structure controlling factors of mudstone and shale in Es3x in the Zhanhua Sag; this information has important significance for future reservoir evaluations.     

Pore characteristic analysis of a lacustrine shale: A case study in the Ordos Basin,NW China

Organic shales deposited in a continental environment are well developed in the Ordos Basin, NW China, which is rich in hydrocarbons. However, previous research concerning shales has predominantly focused on marine shales and barely on continental shales. In this study, geochemical and mineralogical analyses, high-pressure mercury intrusion and low-pressure adsorption were performed on 18 continental shale samples obtained from a currently active shale gas play, the Chang 7 member of Yanchang Formation in the Ordos Basin. A comparison of all these techniques is provided for characterizing the complex pore structure of continental shales.Geochemical analysis reveals total organic carbon (TOC) values ranging from 0.47% to 11.44%, indicating that there is abundant organic matter (OM) in the study area. Kerogen analysis shows vitrinite reflectance (Ro) of 0.68%–1.02%, indicating that kerogen is at a mature oil generation stage. X-ray diffraction mineralogy (XRD) analysis indicates that the dominant mineral constituents of shale samples are clay minerals (which mainly consist of illite, chlorite, kaolinite, and negligible amounts of montmorillonite), quartz and feldspar, followed by low carbonate content. All-scale pore size analysis indicates that the pore size distribution (PSD) of shale pores is mainly from 0.3 to 60 nm. Note that accuracy of all-scale PSD analysis decreases for pores less than 0.3 nm and more than 10 μm. Experimental analysis indicates that mesopores (2–50 nm) are dominant in continental shales, followed by micropores (<2 nm) and macropores (50 nm–10 μm). Mesopores have the largest contribution to pore volume (PV) and specific surface area (SSA). In addition, plate- and sheet-shaped pores are dominant with poor connectivity, followed by hybrid pores. Results of research on factors controlling pore structure development show that it is principally controlled by clay mineral contents and Ro, and this is different from marine systems. This study has important significance in gaining a comprehensive understanding of continental shale pore structure and the shale gas storage–seepage mechanism.     

Experimental investigations on the geometry and connectivity of pore space in organic-rich Wufeng and Longmaxi shales

The nano-scale pore systems of organic-rich shale reservoirs were investigated from Upper Ordovician Wufeng and Lower Silurian Longmaxi Formations in southeast Sichuan Basin. These two formations are the most important target plays of shale gas development in China. The purpose of this article is to assess the geometry and connectivity of multi-scale pore systems, and to reveal the nature and complexity of pore structure for these over-mature gas shales. To achieve these objective, total organic carbon, mineralogy, image analyses by focused ion beam-SEM, low pressure nitrogen adsorption, mercury injection capillary pressure (MICP) and spontaneous fluid [deionized (DI) water and n-decane] imbibition were performed.Most of the visible pores from SEM work in Wufeng and Longmaxi shales are within nm- and μm-size regimes and belong to organic matter (OM) pores. The shapes of OM pore in Longmaxi samples are elliptical, bubble-like, irregular or rounded. Wufeng pores are mainly irregular, linear and faveolated, even though two shales have small depth difference, as well as similar thermal maturity, kerogen type and TOC content. Nano-scale pores in Longmaxi are mainly associated with narrow platelike or slitlike pores with pore size of 3–50 nm; while inkbottle pores are dominant in Wufeng samples and over 88% of the pore volume is contributed by pores with diameter <20 nm. Overall, porosity, pore volume and surface area values from Wufeng samples are much higher than those in Longmaxi, which is mainly correlated with the different TOC contents and mineral compositions. MICP tests show that a total of 5 inflection points (indicative of different connected pore networks) are identified in all pressure regions for Longmaxi, while only 2 for Wufeng in high pressure region with the associated permeability at nano-darcy range. Imbibition curves of n-decane are divided into three stages: the initial stage (Stage Ⅰ), linear imbibition stage (Stage Ⅱ) and late imbibition stage (Stage Ⅲ), and the slopes of linear imbibition stage are around 0.5, suggesting well-connected pore spaces for n-decane. In contrast, imbibition curves for DI water are divided in two stages with linear slopes of between 0.25 and 0.5, indicating moderately-connected pore networks for the movement of DI water. This is consistent with the mixed-wet nature of these shales, with observed weak wettability for hydrophilic, while complete wetting for hydrophobic fluids.     

Novel 3D centimetre-to nano-scale quantification of an organic-rich mudstone: The Carboniferous Bowland Shale,Northern England

X-ray computed tomography and serial block face scanning electron microscopy imaging techniques were used to produce 3D images with a resolution spanning three orders of magnitude from ∼7.7 μm to 7 nm for one typical Bowland Shale sample from Northern England, identified as the largest potential shale gas reservoir in the UK. These images were used to quantitatively assess the size, geometry and connectivity of pores and organic matter. The data revealed four types of porosity: intra-organic pores, organic interface pores, intra- and inter-mineral pores. Pore sizes are bimodal, with peaks at 0.2 μm and 0.04 μm corresponding to pores located at organic–mineral interfaces and within organic matter, respectively. These pore-size distributions were validated by nitrogen adsorption data. The multi-scale imaging of the four pore types shows that there is no connected visible porosity at these scales with equivalent diameter of 20 nm or larger in this sample. However, organic matter and clay minerals are connected and so the meso porosity (<20 nm) within these phases provides possible diffusion transport pathways for gas. This work confirms multi-scale 3D imaging as a powerful quantification method for shale reservoir characterisation allowing the representative volumes of pores, organic and mineral phases to be defined to model shale systems. The absence of connected porosity at scales greater than 20 nm indicates the likely importance of the organic matter network, and associated smaller-scale pores, in controlling hydrocarbon transport. . The application of these techniques to shale gas plays more widely should lead to a greater understanding of properties in the low permeability systems.     

Heterogeneous nanoporosity of the Silurian Longmaxi Formation shale gas reservoir in the Sichuan Basin using the QEMSCAN,FIB-SEM,and nano-CT methods

Nanoporosity of a shale gas reservoir provides essential information on the gas accumulation space and controls the gas reserves. The characteristics of heterogeneous nanoporosity of four shale samples are analyzed by combining quantitative evaluation of minerals by scanning electronic microscopy (QEMSCAN), focused ion beam-scanning electron microscopy (FIB-SEM), and nano-CT. The representative elementary area (REA) is proposed by QEMSCAN to detect the imaging area that can represent the overall contents of minerals and organic matter. Combined with the statistics of pores in minerals and organic matter by FIB-SEM, the quantitative nanoporosity is obtained. The nano-CT is used to compare the total nanoporosity that was obtained by FIB-SEM. The results show that shale has distinct characteristics in nanoporosities due to the variation in organic matter and mineral content. The major pore sizes of the organic matter and clay minerals are smaller than 400 nanometers (nm), and the pore sizes of feldspar and pyrite are mainly 200–600 nm. The pore sizes for pores developed in quartz and carbonate minerals range from a few nanometers to 1000 nm. Furthermore, pores smaller than 400 nm mainly provide the total nanoporosity. The nanoporosities in the organic matter are approximately 17%–21%. Since the organic matter content (0.54%–6.98%) is low, the organic matter contributes approximately 5%–33% of the total nanoporosity in shale. Conversely, the nanoporosities in quartz and clay are generally lower than 3%. Since the mineral content (93.02%–99.46%) is obviously higher than the organic matter content, the minerals contribute approximately 67%–95% of the total nanoporosity in shale.     

2D and 3D nanopore characterization of gas shale in Longmaxi formation based on FIB-SEM

Studying complex pore structures is the key to understanding the mechanism of shale gas accumulation. FIB-SEM (focused ion beam-scanning electron microscope) is the mainstream and effective instrument for imaging nanopores in gas shales. Based on this technology, 2D and 3D characteristics of shale samples from Lower Silurian Longmaxi formation in southern Sichuan Basin were investigated. 2D experimental results show that the pores in shale are nanometer-sized, and the structure of those nanopores can be classified into three types: organic pores, inorganic pores and micro fractures. Among the three types, organic pores are dominantly developed in the OM (organic matter) with three patterns such as continuous distributed OM, OM between clay minerals and OM between pyrite particles, and the size of organic pores range from 5 nm to 200 nm.Inveresly, inorganic pores and micro fractures are less developed in the Longmaxi shales. 3D digital rocks were reconstructed and segmented by 600 continuous images by FIB cutting and SEM imaging simultaneously. The pore size distribution and porosity can be calculated by this 3D digital core, showing that its average value is 32 nm and porosity is 3.62%.The 3D digital porosity is higher than its helium porosity, which can be regarded as one important parameter for evaluation of shale gas reserves. The 2D and 3D characterized results suggest that the nanometer-sized pores in organic matter take up the fundamental storage space for the Longmaxi shale. These characteristics have contributed to the preservation of shale gas in this complex tectonic area.     

Pore structure and fractal characteristics of organic-rich shales: A case study of the lower Silurian Longmaxi shales in the Sichuan Basin,SW China

Shales from the Lower Silurian Longmaxi Formation in the Sichuan Basin are among the most important shale gas reservoirs in China, and have been investigated because of their great shale gas potential. To understand the pore structure and fractal characteristics of the shales, a series of experiments was conducted on core samples from the Lower Silurian Longmaxi Formation in the Sichuan Basin of China, including X-ray diffraction (XRD), total organic carbon (TOC) content and vitrinite reflectance (Ro) analysis, field emission-environmental scanning electron microscope (FE-ESEM) observation, and low-pressure N₂ adsorption-desorption experiments. Frenkel-Halsey-Hill (FHH) method was applied to calculate fractal dimensions. In addition, the pore genesis, the relationships between composition and thermal maturity, the pore structure parameters, and the fractal dimensions are discussed. FE-ESEM observation results show that the Longmaxi Formation shales are dominated by organic-matter (OM) pores along with interparticle (interP) pores, intraparticle (intraP) pores and fracture pores. This study identified the fractal dimensions at relative pressures of 0–0.45 and 0.45–1 as D₁ and D₂ respectively. D₁ ranged from 2.60 to 2.71 and D₂ ranged from 2.71 to 2.82. D₁ was typically smaller than D₂, indicating that the smaller pores in shales were more homogeneous than the larger ones. The formation of these OM pores is owing to kerogen deformation during the thermal maturation, which results in a large number of nanopores. The pore structure of the Longmaxi Formation shales is primarily controlled by TOC content and thermal maturity. TOC content is a controlling factor on the fractal dimensions as it exhibited positive correlations with D₁ and D₂. Fractal dimensions are useful for the characterization of the pore structures complexity of the Longmaxi Formation shales because D₁ and D₂ correlate well with pore structure parameters as they both increase with the increase of surface area and the decrease of average pore diameter.     

Mineral types and organic matters of the Ordovician-Silurian Wufeng and Longmaxi Shale in the Sichuan Basin,China: Implications for pore systems,diagenetic pathways,and reservoir quality in fine-grained sedimentary rocks

Mineral types (detrital and authigenic) and organic-matter components of the Ordovician-Silurian Wufeng and Longmaxi Shale (siliceous, silty, argillaceous, and calcareous/dolomitic shales) in the Sichuan Basin, China are used as a case study to understand the control of grain assemblages and organic matter on pores systems, diagenetic pathway, and reservoir quality in fine-grained sedimentary rocks. This study has been achieved using a combination of petrographic, geochemical, and mercury intrusion methods. The results reveal that siliceous shale comprises an abundant amount of diagenetic quartz (40–60% by volume), and authigenic microcrystalline quartz aggregates inhibit compaction and preserve internal primary pores as rigid framework for oil filling during oil window. Although silty shale contains a large number of detrital silt-size grains (30–50% by volume), which is beneficial to preserve interparticle pores, the volumetric contribution of interparticle pores (mainly macropores) is small. Argillaceous shale with abundant extrabasinal clay minerals (>50% by volume) undergoes mechanical and chemical compactions during burial, leading to a near-absence of primary interparticle pores, while pores preserved between clay platelets are dominant with more than 10 nm in pore size. Pore-filling calcite and dolomite precipitated during early diagenesis inhibit later compaction in calcareous/dolomitic shale, but the cementation significantly reduces the primary interparticle pores. Pore-throat size distributions of dolomitic shale show a similar trend with silty shale. Besides argillaceous shale, all of the other lithofacies are dominated by OM pores, which contribute more micropores and mesopores and is positively related to TOC and quartz contents. The relationship between pore-throat size and pore volume shows that most pore volumes are provided by pore throats with diameters <50 nm, with a proportion in the order of siliceous (80.3%) > calcareous/dolomitic (78.4%) > silty (74.9%) > argillaceous (61.3%) shales. In addition, development degree and pore size of OM pores in different diagenetic pathway with the same OM type and maturity show an obvious difference. Therefore, we suggest that the development of OM pores should take OM occurrence into account, which is related to physical interaction between OM and inorganic minerals during burial diagenesis. Migrated OM in siliceous shale with its large connected networks is beneficial for forming more and larger pores during gas window. The result of the present work implies that the study of mineral types (detrital and authigenic) and organic matter-pores are better understanding the reservoir quality in fine-grained sedimentary rocks.     

Effects of composition and pore structure on the reservoir gas capacity of Carboniferous shale from Qaidam Basin,China

Shale adsorption and breakthrough pressure are important indicators of shale gas development and key factors in evaluating the reservoir capacities of shales. In this study, geochemical tests, pore-structure tests, methane adsorption tests, and breakthrough-pressure tests were conducted on shales from the Carboniferous Hurleg Formation in eastern Qaidam Basin. The effects of the shale compositions and pore structures on the adsorption and breakthrough pressures were studied, and the reservoir capacities of the shales were evaluated by analyzing the shale adsorptions and sealing effects. The results indicate that the organic carbon content was only one of factors in affecting the adsorption capacity of the shale samples while the effect of the clay minerals was limited. Based on the positive correlation between the adsorption capacity and specific surface area of the shale, the specific surface area of the micropores can be used as an indicator to determine the adsorption capacity of shale. The micro-fracturing of brittle minerals, such as quartz, create a primary path for shale gas breakthrough, whereas the expansion of clay minerals with water greatly increases the breakthrough pressure in the shale samples. Methane adsorption tests showed that maximum methane adsorption for shale samples Z045 and S039 WAS 0.107 and 0.09655 mmol/g, respectively. The breakthrough pressure was 39.36 MPa for sample S039, maintained for 13 days throughout the experiment; however, no breakthrough was observed in sample Z045 when subjected to an injected pressure of 40 MPa for 26 days. This indicates that sample Z045, corresponding to a depth of 846.24 m, exhibited higher adsorption capacity and a better reservoir-sealing effect than sample S039 (498.4 m depth). This study provides useful information for future studies of Qaidam Basin shale gas exploration and development and for evaluation of shale quality.     

In situ hydrocarbon concentrations from pressurized cores in surface sediments, Northern Gulf of Mexico

Two newly developed coring devices, the Multi-Autoclave-Corer and the Dynamic Autoclave Piston Corer were deployed in shallow gas hydrate-bearing sediments in the northern Gulf of Mexico during research cruise SO174 (Oct–Nov 2003). For the first time, they enable the retrieval of near-surface sediment cores under ambient pressure. This enables the determination of in situ methane concentrations and amounts of gas hydrate in sediment depths where bottom water temperature and pressure changes most strongly influence gas/hydrate relationships. At seep sites of GC185 (Bush Hill) and the newly discovered sites at GC415, we determined the volume of low-weight hydrocarbons (C₁ through C₅) from nine pressurized cores via controlled degassing. The resulting in situ methane concentrations vary by two orders of magnitudes between 0.031 and 0.985 mol kg^− 1 pore water below the zone of sulfate depletion. This includes dissolved, free, and hydrate-bound CH₄. Combined with results from conventional cores, this establishes a variability of methane concentrations in close proximity to seep sites of five orders of magnitude. In total four out of nine pressure cores had CH₄ concentrations above equilibrium with gas hydrates. Two of them contain gas hydrate volumes of 15% (GC185) and 18% (GC415) of pore space. The measurements prove that the highest methane concentrations are not necessarily related to the highest advection rates. Brine advection inhibits gas hydrate stability a few centimeters below the sediment surface at the depth of anaerobic oxidation of methane and thus inhibits the storage of enhanced methane volumes. Here, computerized tomography (CT) of the pressure cores detected small amounts of free gas. This finding has major implications for methane distribution, possible consumption, and escape into the bottom water in fluid flow systems related to halokinesis.     

Shale gas accumulation potential of the Upper Cretaceous Qingshankou Formation in the southeast Songliao Basin,NE China

The purpose of this paper is to provide both quantitative and qualitative visual analyses of the nanometer-scale pore systems of immature and early shales, as well as to discuss the biogenic shale gas accumulation potential of the Upper Cretaceous section of the Songliao Basin. To achieve these goals, mineralogical compositions were determined using transmitted and reflected light petrography, X-ray diffractometry and scanning electron microscopy (SEM), while the nanostructure morphology and pore size distributions (PSDs) were quantified using field emission scanning electron microscopy (FE-SEM) and low-pressure nitrogen gas adsorption (LP-N₂GA). The results of these analyses indicate that nanometer-scale pores are well developed in the immature and low-maturity shale, and that these shales contain many types of reservoir pores. The mudstone layer of the Qingshankou Formation (K₂qn) contains a high permeability characteristic and good rock fracturing conditions, while it is also thick (>9 m in thickness) and rich in fine organic matter. Overall, analysis of the entire formation using source rock and reservoir evaluations indicate that the first member of the Qingshankou Formation (K₂qn₁) has a greater shale gas accumulation potential than the second and third members of the Qingshankou Formation (K₂qn_2-3).     

Properties and shale oil potential of saline lacustrine shales in the Qianjiang Depression,Jianghan Basin,China

The geochemical and petrographic characteristics of saline lacustrine shales from the Qianjiang Formation, Jianghan Basin were investigated by organic geochemical analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM) and low pressure nitrogen adsorption analysis. The results indicate that: the saline lacustrine shales of Eq3 member with high oil content are characterized by type I and type II oil-prone kerogen, variable TOC contents (1.0–10.0 wt%) and an early-maturity stage (R_o ranges between 0.41 and 0.76%). The mineral compositions of Eq3 saline shale show strong heterogeneity: brittle intervals with high contents of quartz and carbonate are frequently alternated with ductile intervals with high glauberite and clay contents. This combination might be beneficial for oil accumulation, but may cause significant challenges for the hydraulic stimulation strategy and long-term production of shale oil. The interparticle pores and intraparticle pores dominate the pore system of Eq3 shale, and organic matter hosted pores are absent. Widely distributed fractures, especially tectonic fractures, might play a key role in hydrocarbon migration and accumulation. The pore network is contributed to by both large size inorganic pores and abundant micro-factures, leading to a relatively high porosity (2.8–30.6%) and permeability (0.045–6.27 md) within the saline shale reservoir, which could enhance the flow ability and storage capacity of oil. The oil content (S₁ × 100/TOC, mg HC/g TOC and S₁, mg HC/g rock) and brittleness data demonstrate that the Eq3^3x section has both great potential for being a producible oil resource and hydraulic fracturing. Considering the hydrocarbon generation efficiency and properties of oil, the mature shale of Eq3 in the subsidence center of the Qianjiang Depression would be the most favorable zone for shale oil exploitation.     

New insight into the microtexture of chalks from NMR analysis

An integrated petrographical and petrophysical study was carried out on a set of 35 outcrop chalk samples, covering a wide range of lithologies and textures. In this study various chalk rock-types have been characterized, in terms of microtextures and porous network, by integrating both geological, sediment-petrological and petrophysical data, including porosity, permeability, low-field NMR (Nuclear Magnetic Resonance), MICP and specific surface area (BET) measurements. The data allow an in depth understanding of the NMR signal of chalks, with a focus on tight chalks, including all low reservoir quality chalks independently of their sedimentological and/or diagenetic history. The study aims to develop an NMR-based approach to characterize a broad range of chalk samples. The provided laboratory low-field NMR chalk classification can be used as a guide to interpret NMR logging data.Based on the petrographical and petrophysical analysis, 6 groups of samples were identified, each of them characterized by a unique NMR signature: (1) micritic chalks, (2) grainy chalks, (3) cemented chalks, (4) marl-seam chalks, (5) argillaceous chalks and (6) silicified chalk. NMR T₂ distributions were linked to pore body size and T₂ logarithmic (T_2lm) was calculated. It is apparent that tight chalks, whether their characteristics are sedimentological or diagenetic, yield smaller pore body sizes (T_2lm < 20 ms), as well as narrower pore throats (average radius < 150 nm) and lower permeability values (typically below 0.2 mD). Grainy chalks possess T₂ distributions reflecting larger pore sizes (T_2lm > 60 ms) and pore throats (average radius > 290 nm) and higher permeabilities (up to 13 mD). The marl-seam chalk samples yield bimodal T₂ distributions, with a first peak related to the micritic matrix pores and a second peak related to intraparticle pores within fossils. For all samples, permeability was inferred from NMR spectra using SDR (Schlumberger Doll Research) model.     

Coalbed methane reservoirs’ pore-structure characterization of different macrolithotypes in the southern Junggar Basin of Northwest China

Coalbed methane (CBM) development in the southern Junggar Basin of Northwest China has aroused extensive attention owing to its significant resource potential. The accurate characterization of coal pore structure is important for CBM exploration and production. In order to explore the relationship between coal pore structure and macrolithotype, which has rarely been studied in the southern Junggar Basin, a series of laboratory experiments were performed on eight samples of different macrolithotypes. The results show that the porosity exhibits regularity with macrolithotype in the order bright < semibright < semidull < dull, and also shows an increase with the rise of the inertinite content. The pore-size distribution results show that the dominating pores of bright and semibright coals are usually greater than that of dull and semidull coals in size. The pore-type analysis indicates that the bottleneck pores (Type B) are well developed in dull and semidull coals, while bright and semibright coals mainly host two sides (Type A), namely opened pores and one-side-closed pores (Type C). The pore-type and -size distribution strongly affect pore connectivity refers to the facts that: 1) the proportion of effective porosity increases with an increasing proportion of pores greater than 100 nm in size; and 2) that the mercury withdrawal efficiency is always lower when the pores are mostly of Type B. So the pore connectivity of semibright and bright coals is higher than that of semidull and dull coals. Furthermore, pores are developed mainly in the inertinite, with pore-type being dominated by Type B and C, secondly in the vitrinite, with pore-type being dominated by Type A and C, and less developed in the liptinite with pore-type of B and C. The pore connectivity of each maceral is in the order vitrinite > inertinite > liptinite. Finally, according to the research results, the reservoir fracturing improvement should be more arranged on the dull or semi-dull coals, and the producing layers should be bright or semi-bright coals as much as possible on the premise that the gas contents of coal layers are not much different from each other.     

Characterization of shale pore system: A case study of Paleogene Xin'gouzui Formation in the Jianghan basin,China

The pore size classification (micropore <2 nm, mesopore 2–50 nm and macropore >50 nm) of IUPAC (1972) has been commonly used in chemical products and shale gas reservoirs; however, it may be insufficient for shale oil reservoirs. To establish a suitable pore size classification for shale oil reservoirs, the open pore systems of 142 Chinese shales (from Jianghan basin) were studied using mercury intrusion capillary pressure analyses. A quantitative evaluation method for I-micropores (0–25 nm in diameter), II-micropores (25–100 nm), mesopores (100–1000 nm) and macropores (>1000 nm) within shales was established from mercury intrusion curves. This method was verified using fractal geometry theory and argon-ion milling scanning electron microscopy images. Based on the combination of pore size distribution with permeability and average pore radius, six types (I-VI) shale open pore systems were analyzed. Moreover, six types open pore systems were graded as good, medium and poor reservoirs. The controlling factors of pore systems were also investigated according to shale compositions and scanning electron microscopy images. The results show that good reservoirs are composed of shales with type I, II and III pore systems characterized by dominant mesopores (mean 68.12 vol %), a few macropores (mean 7.20 vol %), large porosity (mean 16.83%), an average permeability of 0.823 mD and an average pore radius (r_a) of 88 nm. Type IV pore system shales are medium reservoirs, which have a low oil reservoir potential due to the developed II-micropores (mean 57.67 vol %) and a few of mesopores (mean 20.19 vol %). Poor reservoirs (composed of type V and VI pore systems) are inadequate reservoirs for shale oil due to the high percentage of I-micropores (mean 69.16 vol %), which is unfavorable for the flow of oil in shale. Pore size is controlled by shale compositions (including minerals and organic matter), and arrangement and morphology of mineral particles, resulting in the developments of shale pore systems. High content of siliceous mineral and dolomite with regular morphology are advantage for the development of macro- and mesopores, while high content of clay minerals results in a high content of micropores.