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.     

Modeling free gas content of the Lower Paleozoic shales in the Weiyuan area of the Sichuan Basin,China

Two sets of Lower Paleozoic organic-rich shales develop well in the Weiyuan area of the Sichuan Basin: the Lower Cambrian Jiulaodong shale and the Lower Silurian Longmaxi shale. The Weiyuan area underwent a strong subsidence during the Triassic to Early Cretaceous and followed by an extensive uplifting and erosion after the Late Cretaceous. This has brought about great changes to the temperature and pressure conditions of the shales, which is vitally important for the accumulation and preservation of shale gas. Based on the burial and thermal history, averaged TOC and porosity data, geological and geochemical models for the two sets of shales were established. Within each of the shale units, gas generation was modeled and the evolution of the free gas content was calculated using the PVTSim software. Results show that the free gas content in the Lower Cambrian and Lower Silurian shales in the studied area reached the maxima of 1.98–2.93 m³/t and 3.29–4.91 m³/t, respectively (under a pressure coefficient of 1.0–2.0) at their maximum burial. Subsequently, the free gas content continuously decreased as the shale was uplifted. At present, the free gas content in the two sets of shales is 1.52–2.43 m³/t and 1.94–3.42 m³/t, respectively (under a current pressure coefficient of 1.0–2.0). The results are roughly coincident with the gas content data obtained from in situ measurements in the Weiyuan area. We proposed that the Lower Cambrian and Lower Silurian shales have a shale gas potential, even though they have experienced a strong uplifting.     

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.     

Pore structure of Cambrian shales from the Sichuan Basin in China and implications to gas storage

The microstructure of black siliceous shale from the lower Cambrian Niutitang Formation, Sichuan Basin in China was investigated by the combination of field emission scanning electron microscope (FE-SEM) and argon ion beam milling. The nanometer-to micrometer-scale pore systems of shales are an important control on gas storage and fluid migration. In this paper, the organic porosity in shale samples within oil and gas window has been investigated, and the formation mechanism and diagenetic evolution of nanopores have been researched.FE-SEM reveals five pore types that are classified as follows: organic nanopores, pores in clay minerals, nanopores of framework minerals, intragranular pores in microfossils, and microfractures. Numerous organic nanopores are observed in shales in the gas window, whereas microfractures can be seen within the organic matter of shales in the oil window. Microfractures in oil window shales could be attributed to pressure buildup in the organic matter when incompressible liquid hydrocarbon are generated, and the orientation of microfractures is probably parallel to the bedding and strength anisotropy of the formation. Pores in clay minerals are always associated with the framework of clay flakes, and develop around rigid mineral grains because the pressure shadows of mineral grains protect pores from collapse, and the increasing of silt content would lead to an increase in pressure shadows and improve porosity. Nanopores of rock framework are probably related to dissolution by acidic fluids from hydrocarbon generation, and the dissolution-related pores promote permeability of shales. Porosity in the low-TOC, low-thermal-maturity shales contrast greatly with those of high-TOC, high-thermal-maturity shales. While the high-TOC shales contain abundant organic microporosity, the inorganic pores can contribute a lot to the porosity of the low-TOC shales.     

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.     

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.     

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.     

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.     

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.     

Geochemistry,reservoir characterization and hydrocarbon generation potential of lacustrine shales: A case of YQ-1 well in the Yuqia Coalfield,northern Qaidam Basin,NW China

Ever since a breakthrough of marine shales in China, lacustrine shales have been attracting by the policy makers and scientists. Organic-rich shales of the Middle Jurassic strata are widely distributed in the Yuqia Coalfield of northern Qaidam Basin. In this paper, a total of 42 shale samples with a burial depth ranging from 475.5 m to 658.5 m were collected from the Shimengou Formation in the YQ-1 shale gas borehole of the study area, including 16 samples from the Lower Member and 26 samples from the Upper Member. Geochemistry, reservoir characteristics and hydrocarbon generation potential of the lacustrine shales in YQ-1 well were preliminarily investigated using the experiments of vitrinite reflectance measurement, maceral identification, mineralogical composition, carbon stable isotope, low-temperature nitrogen adsorption, methane isothermal adsorption and rock eval pyrolysis. The results show that the Shimengou shales have rich organic carbon (averaged 3.83%), which belong to a low thermal maturity stage with a mean vitrinite reflectance (R_o) of 0.49% and an average pyrolytic temperature of the generated maximum remaining hydrocarbon (T_max) of 432.8 °C. Relative to marine shales, the lacustrine shales show low brittleness index (averaged 34.9) but high clay contents (averaged 55.1%), high total porosities (averaged 13.71%) and great Langmuir volumes (averaged 4.73 cm⁻³ g). Unlike the marine and marine-transitional shales, the quartz contents and brittleness index (BI) values of the lacustrine shales first decrease then increase with the rising TOC contents. The kerogens from the Upper Member shales are dominant by the oil-prone types, whereas the kerogens from the Lower Member shales by the gas-prone types. The sedimentary environment of the shales influences the TOC contents, thus has a close connection with the hydrocarbon potential, mineralogical composition, kerogen types and pore structure. Additionally, in terms of the hydrocarbon generation potential, the Upper Member shales are regarded as very good and excellent rocks whereas the Lower Member shales mainly as poor and fair rocks. In overall, the shales in the top of the Upper Member can be explored for shale oil due to the higher free hydrocarbon amount (S₁), whereas the shales in the Lower Member and the Upper Member, with the depths greater than 1000 m, can be suggested to explore shale gas.     

Multiple controls on the paleoenvironment of the Early Cambrian marine black shales in the Sichuan Basin,SW China: Geochemical and organic carbon isotopic evidence

In order to understand the paleoenvironment of the Early Cambrian black shale deposition in the western part of the Yangtze Block, geochemical and organic carbon isotopic studies have been performed on two wells that have drilled through the Qiongzhusi Formation in the central and southeastern parts of Sichuan Basin. It shows that the lowest part of the Qiongzhusi Formation has high TOC abundance, while the middle and upper parts display relative low TOC content. Redox-sensitive element (Mo) and trace elemental redox indices (e.g., Ni/Co, V/Cr, U/Th and V/(V + Ni)) suggest that the high-TOC layers were deposited under anoxic conditions, whereas the low-TOC layers under relatively dysoxic/oxic conditions. The relationship of the enrichment factors of Mo and U further shows a transition from suboxic low-TOC layers to euxinic high-TOC layers. On the basis of the Mo-TOC relationship, the Qiongzhusi Formation black shales were deposited in a basin under moderately restricted conditions. Organic carbon isotopes display temporal variations in the Qiongzhusi Formation, with a positive excursion of δ¹³C_org values in the lower part and a continuous positive shift in the middle and upper parts. All these geochemical and isotopic criteria indicate a paleoenvironmental change from bottom anoxic to middle and upper dysoxic/oxic conditions for the Qiongzhusi Formation black shales. The correlation of organic carbon isotopic data for the Lower Cambrian black shales in different regions of the Yangtze Block shows consistent positive excursion of δ¹³C_org values in the lower part for each section. This excursion can be ascribed to the widespread Early Cambrian transgression in the Yangtze Block, under which black shales were deposited.     

Sedimentary and residual gas geochemical characteristics of the Lower Cambrian organic-rich shales in Southeastern Chongqing,China

To study the sedimentary environment of the Lower Cambrian organic-rich shales and isotopic geochemical characteristics of the residual shale gas, 20 black shale samples from the Niutitang Formation were collected from the Youyang section, located in southeastern Chongqing, China. A combination of geochemical, mineralogical, and trace element studies has been performed on the shale samples from the Lower Cambrian Niutitang Formation, and the results were used to determine the paleoceanic sedimentary environment of this organic-rich shale. The relationships between total organic carbon (TOC) and total sulfur (TS) content, carbon isotope value (δ¹³C_org), trace element enrichment, and mineral composition suggest that the high-TOC Niutitang shale was deposited in an anoxic environment and that the organic matter was well preserved after burial. Stable carbon isotopes and biomarkers both indicate that the organic matter in the Niutitang black shales was mainly derived from both lower aquatic organisms and algaes and belong to type I kerogen. The oil-prone Niutitang black shales have limited residual hydrocarbons, with low values of S₂, I_H, and bitumen A. The carbon isotopic distribution of the residual gas indicate that the shale gas stored in the Niutitang black shale was mostly generated from the cracking of residual bitumen and wet gas during a stage of significantly high maturity. One of the more significant observations in this work involves the carbon isotope compositions of the residual gas (C₁, C₂, and C₃) released by rock crushing. A conventional δ¹³C₁–δ¹³C₂ trend was observed, and most δ¹³C₂ values of the residual gases are heavier than those of the organic matter (OM) in the corresponding samples, indicating the splitting of ethane bonds and the release of smaller molecules, leading to ¹³C enrichment in the residual ethane.     

Pore characterization and methane sorption capacity of over-mature organic-rich Wufeng and Longmaxi shales in the southeast Sichuan Basin,China

Currently, the Upper Ordovician Wufeng (O₃w) and Lower Silurian Longmaxi (S₁l) Formations in southeast Sichuan Basin have been regarded as one of the most important target plays of shale gas in China. In this work, using a combination of low-pressure gas adsorption (N₂ and CO₂), mercury injection porosimetry (MIP) and high-pressure CH₄ adsorption, we investigate the pore characteristics and methane sorption capacity of the over-mature shales, and discuss the main controlling factors for methane sorption capacity and distribution of methane gas in pore spaces.Low pressure CO₂ gas adsorption shows that micropore volumes are characterized by three volumetric maxima (at about 0.35, 0.5 and 0.85 nm). The reversed S-shaped N₂ adsorption isotherms are type Ⅱ with hysteresis being noticeable in all the samples. The shapes of hysteresis loop are similar to the H3 type, indicating the pores are slit- or plate-like. Mesopore size distributions are unimodal and pores with diameters of 2–16 nm account for the majority of mesopore volume, which is generally consistent with MIP results. The methane sorption capacities of O₃w-S₁l shales are in a range of 1.63–3.66 m³/t at 30 °C and 10 MPa. Methane sorption capacity increase with the TOC content, surface area and micropore volume, suggesting organic matter might provide abundant adsorption site and enhance the strong methane sorption capacity. Samples with higher quartz content and lower clay content have larger sorption capacity. Our data confirmed that the effects of temperature and pressure on methane sorption capacity of shale formation are opposite to some extent, suggesting that, during the burial or uplift stage, the gas sorption capacity of hydrocarbon reservoirs can be expressed as a function of burial depth. Based on the adsorption energy theory, when the pore diameter is larger than 2 nm, much methane molecular will be adsorbed in pores space with distance to pore wall less than 2 nm; while free gas is mainly stored in the pore space with distance to pore wall larger than 2 nm. Distributions of adsorption space decrease with the increasing pore size, while free gas volume increase gradually, assuming the pore are cylindrical or sphere. Particularly, when the pore size is larger than 30 nm, the content of adsorbed gas space volume is very low and its contribution to the all gas content is negligible.     

Jurassic source rocks in the Vienna Basin (Austria): Assessment of conventional and unconventional petroleum potential

The Upper Jurassic marlstones (Mikulov Fm.) and marly limestones (Falkenstein Fm.) are the main source rocks for conventional hydrocarbons in the Vienna Basin in Austria. In addition, the Mikulov Formation has been considered a potential shale gas play. In this paper, organic geochemical, petrographical and mineralogical data from both formations in borehole Staatz 1 are used to determine the source potential and its vertical variability. Additional samples from other boreholes are used to evaluate lateral trends. Deltaic sediments (Lower Quarzarenite Member) and prodelta shales (Lower Shale Member) of the Middle Jurassic Gresten Formation have been discussed as secondary sources for hydrocarbons in the Vienna Basin area and are therefore included in the present study.The Falkenstein and Mikulov formations in Staatz 1 contain up to 2.5 wt%TOC. The organic matter is dominated by algal material. Nevertheless, HI values are relative low (<400 mgHC/gTOC), a result of organic matter degradation in a dysoxic environment. Both formations hold a fair to good petroleum potential. Because of its great thickness (∼1500 m), the source potential index of the Upper Jurrasic interval is high (7.5 tHC/m²). Within the oil window, the Falkenstein and Mikulov formations will produce paraffinic-naphtenic-aromatic low wax oil with low sulfur content. Whereas vertical variations are minor, limited data from the deep overmature samples suggest that original TOC contents may have increased basinwards. Based on TOC contents (typically <2.0 wt%) and the very deep position of the maturity cut-off values for shale oil/gas production (∼4000 and 5000 m, respectively), the potential for economic recovery of unconventional petroleum is limited. The Lower Quarzarenite Member of the Middle Jurassic Gresten Formation hosts a moderate oil potential, while the Lower Shale Member is are poor source rock.     

Black shales in Ukraine – A review

As a result of a long-lasting and complex geological history, organic-matter-rich fine-grained rocks (black shales) with widely varying ages can be found on Ukrainian territory. Several of them are proven hydrocarbon source rocks and may hold a significant shale gas potential.Thick Silurian black shales accumulated along the western margin of the East European Craton in a foreland-type basin. By analogy with coeval organic-matter-rich rocks in Poland, high TOC contents and gas window maturity can be expected. However, to date information on organic richness is largely missing and maturity patterns remain to be refined.Visean black shales with TOC contents as high as 8% and a Type III-II kerogen accumulated along the axis of the Dniepr-Donets rift basin (DDB). They are the likely source for conventional oil and gas. Oil-prone Serpukhovian black shales accumulated in the shallow northwestern part of the DDB. Similar black shales probably may be present in the Lviv-Volyn Basin (western Ukraine).Middle Jurassic black shales up to 500 m thick occur beneath the Carpathian Foredeep. They are the likely source for some heavy oil deposits. TOC contents up to 12% (Type II) have been recorded, but additional investigations are needed to study the vertical and lateral variability of organic matter richness and maturity.Lower Cretaceous black shales with a Type III(-II) kerogen (TOC > 2%) are widespread at the base of the Carpathian flysch nappes, but Oligocene black shales (Menilite Fm.) rich in organic matter (4–8% TOC) and containing a Type II kerogen are the main source rock for oil in the Carpathians. Their thermal maturity increases from the external to the internal nappes.Oligocene black shales are also present in Crimea (Maykop Fm.). These rocks typically contain high TOC contents, but data from Ukraine are missing.     

Experimental investigation of thermal maturation on shale reservoir properties from hydrous pyrolysis of Chang 7 shale,Ordos Basin

Thermal maturity has a significant impact on hydrocarbon generation and the storage capacity within shales, but explicit and quantitative characterization of that impact on continental shales is scarce. To better understand how thermal maturation affects the organic and inorganic changes of the continental shale reservoirs, hydrous pyrolysis was performed to simulate the maturation process. TOC, Rock-Eval and adsorption isotherms tests were used to obtain various geochemical parameters of the shale solid residues. The results indicate that with pyrolysis temperature increasing from ambient temperature to 550 °C, the vitrinite reflectance increases from 0.5% to 2.5% Ro and the TOC (total organic carbon) loss weight reaches 25%. Regarding porosity, the fraction of micro-to meso-pores in the shale increases with an increase in the pyrolysis temperature, whereas the macro-pores do not change significantly. The total amount of gas adsorption does not necessarily increase as the TOC is consumed, but the gas adsorption capacity per unit of TOC increases with increasing thermal maturity. Our finding provides theoretical modelling for identifying shale gas development prospective zones according to thermal maturity mapping and for predicting quantitatively the geochemical and inorganic changes that occur with thermal evolution.     

Evolution of porosity and pore types in organic-rich,calcareous, Lower Toarcian Posidonia Shale

Low and high resolution petrographic studies have been combined with mineralogical, TOC, RockEval and porosity data to investigate controls on the evolution of porosity in stratigraphically equivalent immature, oil-window and gas-window samples from the Lower Toarcian Posidonia Shale formation. A series of 26 samples from three boreholes (Wickensen, Harderode and Haddessen) in the Hils syncline was investigated. The main primary components of the shales are microfossiferous calcite (30–50%), clay minerals (20–30%) and Type II organic matter (TOC = 7–15%, HI = 630–720 mg/gC in immature samples). Characteristic sub-centimetric light and dark lamination reflects rapid changes in the relative supply of these components. Total porosities decrease from 10 to 14% at Ro = 0.5% to 3–5% at Ro = 0.9% and then increase to 9–12% at Ro = 1.45%. These maturity-related porosity changes can be explained by (a) the primary composition of the shales, (b) carbonate diagenesis, (c) compaction and (d) the maturation, micro-migration, local trapping and gasification of heterogeneous organic phases. Calcite undergoes dissolution and reprecipitation reactions throughout the maturation sequence. Pores quantifiable in SEM (>ca. 50 nm) account for 14–25% of total porosity. At Ro = 0.5%, SEM-visible macropores¹ are associated mainly with biogenic calcite. At this maturity, clays and organic matter are not visibly porous but nevertheless hold most of the shale porosity. Porosity loss into the oil window reflects (a) compaction, (b) carbonate cementation and (c) perhaps the swelling of kerogen by retained oil. In addition, porosity is occluded by a range of bituminous phases, especially in microfossil macropores and microfractures. In the gas window, mineral-hosted porosity is still the primary form of macroporosity, most commonly observed at the organic-inorganic interface. Increasing porosity into the gas window also coincides with the formation of isolated, spongy and complex meso- and macropores within organic particles, related to thermal cracking and gas generation. This intraorganic porosity is highly heterogeneous: point-counted macroporosity of individual organic particles ranges from 0 to 40%, with 65% of organic particles containing no macropores. We suggest that this reflects the physicochemical heterogeneity of the organic phases plus the variable mechanical protection afforded by the mineral matrix to allow macroporosity to be retained. The development of organic macroporosity cannot alone account for the porosity increase observed from oil to gas window; major contributions also come from the increased volume of organic micro- and meso-porosity, and perhaps by kerogen shrinkage.     

Enrichment and distribution of shale oil in the Cretaceous Qingshankou Formation,Songliao Basin,Northeast China

The Songliao Basin is a large-scale petroliferous basin in China. With a gradual decline in conventional oil production, the exploration and development of replacement resources in the basin is becoming increasingly important. Previous studies have shown that the Cretaceous Qingshankou Formation (K₂qn) has favorable geological conditions for the formation of shale oil. Thus, shale oil in the Qingshankou Formation represents a promising and practical replacement resource for conventional oil. In this study, geological field surveys, core observation, sample tests, and the analysis of well logs were applied to study the geochemical and reservoir characteristics of shales, identify shale oil beds, build shale oil enrichment models, and classify favorable exploration areas of shale oil from the Cretaceous Qingshankou Formation. The organic matter content is high in shales from the first member of the Cretaceous Qingshankou Formation (K₂qn¹), with average total organic carbon (TOC) content exceeding 2%. The organic matter is mainly derived from lower aquatic organisms in a reducing brackish to fresh water environment, resulting in mostly type I kerogen. The vitrinite reflectance (Ro) and the temperature at which the maximum is release of hydrocarbons from cracking of kerogen occurred during pyrolysis (T_max) respectively range from 0.5% to 1.1% and from 430 °C to 450 °C, indicating that the K₂qn¹ shales are in the low-mature to mature stage (Ro ranges from 0.5% to 1.2%) and currently generating a large amount of oil. The favorable depth for oil generation and expulsion is 1800–2200 m and 1900–2500 m, respectively as determined by basin modeling. The reserving space of the K₂qn¹ shale oil includes micropores and mircofractures. The micropore reservoirs are developed in shales interbedded with siltstones exhibiting high gamma ray (GR), high resistivity (Rt), low density (DEN), and slightly abnormal spontaneous potential (SP) in the well-logging curves. The microfracture reservoirs are mainly thick shales with high Rt, high AC (acoustic transit time), high GR, low DEN, and abnormal SP. Based on the shale distribution, geochemical characteristics, reservoir types, fracture development, and the process of shale oil generation and enrichment, the southern Taikang and northern Da'an are classified as two favorable shale oil exploration areas in the Songliao Basin.     

Pore structure of the graptolite-derived OM in the Longmaxi Shale,southeastern Upper Yangtze Region,China

The Lower Silurian Longmaxi Shale in the southeastern Upper Yangtze Region, which has been the main target for shale gas exploration and production in China, is black marine organic-rich shale and rich in graptolites. Graptolites, usually only periderms preserved in shales, are important organic component of the Longmaxi Shale. However, the pore structure of graptolite periderms and its contribution to gas storage has not yet been studied before. A combination of optical microscopy for identification and “mark” of graptolite and scanning electron microscope (SEM) for pore observations were conducted for the Longamxi Shale samples. Results show that pores are anisotropic developed in the Longmaxi graptolite periderms and greatly associated with their fine structure. Micrometer-sized fractures and spindle-shaped pores between cortical fibrils in the cortical bandage are greatly developed at section parallel to the bedding, while they are rare at section perpendicular to the bedding. Besides, numerous sapropel detritus rich in nanometer-sized pores are discretely distributed in the shale. Though graptolite periderms are low porosity from SEM image analysis, microfractures and elongated pores along the graptolite periderm wall may still make the graptolite an interconnected system. Together with the discrete porous sapropel detritus in shale, these graptolite-derived Organic Matter (OM) may form an interconnected organic pore system in the shale. The difference of pore development observed in graptolite periderms and sapropel detritus also give us new insight for the organic pore heterogeneity study. The OM composition, their fine structure and orientation in the rock may be important factors controlling OM pore development. The combination of identifying OM type under optical microscopy and pores observation under SEM for may be an effective method to study the OM pore development especially in shale that contain more OM.