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Kolm refers to uraniferous (1280–7100 ppm) and organic-rich (25–71 wt%) lenses occurring exclusively within the Furongian part of the Alum Shale Formation in south-central Sweden. It typically less than 7 cm thick and forms thin discontinuous layers. This study investigates the geochemical and organic petrological characteristics of kolm, and it is shown that the organic matter likely represents secondarily formed solid bitumen rather than a primary organic-rich component. The high uranium content is concentrated in specific uranium‑yttrium‑zinc-rich (U-Y-Zn-rich) particles. A model for kolm formation is presented, suggesting that during sedimentation, initial uranium-enriched particles were formed and then became concentrated, probably by winnowing at the sea floor under euxinic conditions. This lag deposit rich in uranium particle subsequently formed the radioactive nuclei (U-Y-Zn-rich particles) for the kolm nodules that grew during the early diagenesis. Initial kolm was apparently formed by in-situ accumulation of diagenetically formed solid bitumen (R o < 0.5 %) onto these strongly radioactive U-Y-Zn-rich particles. The more abundant development of kolm in the Billingen area of Västergötland, compared to other regions in south-central Sweden where kolm occurs, is likely due to increased generation of solid bitumen associated with localized heating from Permo-Carboniferous intrusions. • Kolm occurs as secondarily formed solid bitumen lenses that stratabound within the Alum Shale Formation. • Comparation of organic petrological and geochemical characteristics between kolm and its host Alum Shale. • A model for kolm formation and its implications for distribution. [ABSTRACT FROM AUTHOR]

The Wufeng-Longmaxi (WL) shale is widely distributed in the Sichuan Basin and adjacent areas in southwest China. The basin experienced multiple-stage complex tectonic movements, whose influences on burial, thermal maturation and gas generation histories in different areas are poorly understood. Based on a detailed study of the denudation stages, strata thickness, and thermal history of the basin, burial and thermal maturation histories of seven wells in different areas were modelled using PetroMod software. Due to the high maturity of the WL shale, a low-maturity Silurian Polish Llandovery shale was used for gold tube closed-system pyrolysis experiments to obtain kinetic parameters for evaluating methane generation history. The Polish shale was selected due to its depositional age, sedimentary environment and organic type, which are similar to the WL shale. The burial history of the WL shale can be divided into five stages: I. Early to Middle Silurian rapid burial; II. Caledonian uplift and denudation; III. Permian to Triassic sustained burial and denudation; IV. sustained burial since the Late Triassic; and V. Late Cretaceous to present sustained uplift and denudation. The thermal maturity of the WL shale in all wells increased with burial depth during stage IV. In addition, high calculated reflectance increments in wells JY1 and N201 during stage III occurred due to the relatively high basal heat flow and deep burial depth, resulting in higher current thermal maturities than in the other wells. The late Permian–Early Triassic and the Middle Jurassic–Early (or Late) Cretaceous were the key methane generation periods for wells JY1 and N201. In contrast, the other five wells had a single methane generation stage, mainly determined by burial and thermal maturation processes. The time of uplift and the amount of denudation during stage V, the current burial depth, the development of faults and fractures, high proportion of retention and the seal capacity of the overlying caprock are key factors for shale gas preservation. Hence, this study will help guide future shale gas development in the Sichuan Basin. • Burial, thermal maturation and gas generation histories of seven wells in different areas of the Sichuan Basin were modelled. • Methane generation histories were reconstructed by kinetic parameters from the Lower Silurian Llandovery shale. • Influences of tectonic evolution processes on burial, thermal maturation and gas generation histories were evaluated. • Main controls on shale gas preservation, such as timing of uplift, denudation and burial depth, were studied. [ABSTRACT FROM AUTHOR]

The substantial gas enrichment in shales of the Ordovician–Silurian transition is associated with the development of the organic matter (OM)-rich source rock. While organic matter enrichment has been linked to intensive volcanism, it remains a challenge to precisely evaluate the impact of the volcanism on substantial gas enrichment containing the largest gas storage capacity. This study focused on consecutive borehole shale samples from the Wufeng–Longmaxi formations during the Ordovician–Silurian transition in southern China. We conducted a comprehensive analysis, integrating the major geological volcanism with high-resolution analysis, including QEMSCAN, argon-ion SEM, thin-section examination, XRD mineralogy, TOC, Hg concentration, petrophysical properties and nanopore structure analysis (low-pressure CO 2 /N 2 gas adsorption, helium porosity and permeability). The results link the significant shale gas enrichment in Wufeng–Longmaxi formations to intensive volcanism across the Ordovician–Silurian transition. We identified the most favorable shale intervals in the lower Longmaxi Formation, aligning with the peak period of volcanism. This period showed synchronous spikes in Hg, Hg/TOC, and TOC contents. Shale deposited during this favorable paleoenvironment exhibited the highest values of TOC, porosity, permeability, specific surface area, pore volume, and maximum gas adsorption capacity, leading to the largest amount of gas content and substantial gas enrichment. Our work, therefore, provides new insights into identifying the most favorable shale gas resources. This knowledge assists in accurate predictions of the stratigraphic 'sweet spot' intervals for large shale gas storage capacity, providing crucial information for engineering explorations and developments in shale formations. [ABSTRACT FROM AUTHOR]

A comparative analysis of the factors controlling organic matter (OM) enrichment between marine-continental transitional (transitional hereafter) and marine or lacustrine shales is lacking. The early Permian Taiyuan Formation in the Ordos Basin, deposited during a shift from marine to continental settings in northern China, provides a unique opportunity to unravel the differences in OM enrichment mechanisms among these shales. The Taiyuan Formation is characterized by high TOC content (average 4.50%) and kerogen type II 2 -III. Most samples are thermally mature with a few high to post-mature samples relating to the Late Jurassic–Early Cretaceous Yanshanian magmatism. Rare earth elements and yttrium (REY) are dominated by light- and medium-types enrichments, with distinctly positive Gd anomaly, likely due to seawater incursion. A warm and humid climate prevailed during deposition of the Taiyuan Formation, consistent with the tropical-subtropical location of the North China Plate in the early Permian. The climatic conditions promoted intense continental weathering as reflected by high Th/Sc ratios, chemical index of alteration values, and feldspar alteration to scaly kaolinite. The V/(V + Ni) ratio is inconsistent with the other redox proxies, presumably due to variations in the redox buffer supply in the transitional facies (e.g., OM and pyrite), varying burial rates and dissimilar redox potential of different elements. Hence, this proxy should be interpreted with caution in such settings. Most redox proxies indicate oxic bottom water during deposition of the Taiyuan Formation transitional shale, in contrast to typical OM enriched marine and lacustrine shales where redox stratification or euxinic conditions are common. Instead, the dominant factor for OM enrichment in transitional shales appears to have been a high influx of terrestrial weathering products, including abundant higher-plants OM, associated with preservation of OM due to rapid burial. This process minimizes the detrimental effects of oxic conditions on OM accumulation in the transitional shale facies. This mechanism may hold relevance for analogous basins elsewhere. [ABSTRACT FROM AUTHOR]

This study investigates the geochemical and petrological characteristics of solid bitumen in the DBH15/73 core from the Furongian (upper Cambrian) and Miaolingian (middle Cambrian) Alum Shale in Billingen, south central Sweden. At Billingen a > 30 m thick Permian diabase (dolerite sill) intruded approximately 100 m above the Alum Shale that promoting the formation of solid bitumen in the uppermost half of the Alum Shale due to enhanced heat flow. The bitumen has been classified into bituminite/diagenetic solid bitumen (DSB), initial-oil solid bitumen (IOSB), and primary-oil solid bitumen (POSB) based on their genesis, morphology and random solid bitumen reflectance (BR o). The Miaolingian shale, constituting the lower part of the Alum Shale, is immature and contains solely bituminite and DSB, with measured BR o ranging from 0.40% to 0.48%. In contrast, the Furongian shale exhibits enrichment in IOSB and POSB and range from marginally mature to peak oil generation with towards the top of the section. Characteristics of uneven heating is seen in the IOSB (BR o : 0.97–1.08%) including oxidation rims and abnormally high maturity surrounding fractures. The POSB (BR o : 0.63–2.01%) is present not only in the Alum Shale but also in the overlying Ordovician Latorp limestone and the underlying Kakeled Limestone Bed, and shows flow structures which is further evidence for migration. The abundance of POSB and IOSB is determined through maceral point counting, revealing POSB as the dominant bitumen type (1.54–7.13 vol%), while IOSB constitutes the minority (0.05–0.31 vol%) within the Furongian shale. This distribution suggests rapid thermal evolution of organic matter within the oil generation window. Additionally, a reduction in free hydrocarbons (Rock-Eval S1), potential hydrocarbons (Rock-Eval S2), and unexpectedly low T max was observed in the Furongian shale. Results indicate that hydrocarbon generation resulting from thermal intrusion contributes to the relatively low S2. Migration of POSB and generated oil to adjacent layers leads to the loss of S1, while the reduced Tmax may be attributed to high uranium content which weakens carbon chain bond energy. These anomalies result in an underestimation when evaluating thermal maturity and kerogen type conversion based on Rock Eval data alone. • Introduce multiphases of solid bitumen in Alum Shale from central Sweden. • Report the solid bitumen migration and its implication on geochemical parameters. • Propose a genetic model describing the genesis of solid bitumen that exposed to heat of diabase intrusion. [ABSTRACT FROM AUTHOR]

This paper addresses challenges in characterizing unconventional shale reservoirs. For the first time, the nuclear magnetic resonance (NMR) and dielectric responses are integrated to characterize intact, saturated, and kerogen-rich subsurface shale samples at various maturation stages. The NMR and dielectric were measured separately using independent pieces of equipment, and all NMR and dielectric measurements were carried out at surface conditions. A comprehensive assessment is provided to address the changes induced by maturation through combined geochemical and petrophysical analyses. Shale samples from the Upper Cretaceous sequence of Jordan were characterized using Rock-Eval analysis, before and after maturation treatments. The total organic carbon (TOC) was decreased from 17.4 to 13.8 and 11.3 wt% and the pyrolyzed sulfur content was decreased from 3.32 to 0.25 and 0.15 3.18%, after maturing the samples at 250 °C for 1 and 5 days, respectively. The study employed NMR to track changes in pore structure via T 2 relaxation time and measured dielectric properties and conductivity dispersion across frequencies from 10 MHz to 1 GHz using a wideband open-ended coaxial probe. After the maturation treatments, the dielectric constant of saturated shale samples doubled, and the conductivity increased by over three times. These changes in dielectric properties can be attributed to increased fluid-rock interfacial polarization and the formation of new pore spaces during maturation. NMR findings also indicated the emergence of a new pore system within the organic matter and the development of new fractures, resulting in a 6 to 12% increase in total porosity. The results obtained indicate that maturation-induced microstructural changes have a more significant influence on the dielectric responses than alterations on total organic carbon. • Dielectric and NMR are used for the first time on intact, saturated, and kerogen-rich subsurface shale samples at various maturation stages. • The use of rock samples instead of crushed powder provides a better representation of the shale complex microstructure. • The kerogen distribution plays a significant role; scattered organic matter causes greater TOC reduction than accumulated. • · The changes in dielectric properties induced by maturation are more significant than those reported in the literature. • The changes in dielectric response upon maturation are primarily due to changes in geometry and pore connectivity. [ABSTRACT FROM AUTHOR]

Understanding mechanical behaviour of shale is essential for efficient shale gas extraction, which can vary in different depositional settings. The impact of sedimentary environment on shale characteristics, such as mineralogical composition, total organic carbon content (TOC), and petrophysical properties, has been extensively researched. However, its influence on shale mechanical properties, especially in defining mechanical stratigraphy for targeting specific fracturing intervals, remains less explored. In this study, the influence of depositional environment on the mechanical properties of shale samples from the Rajmahal Basin is evaluated. Tensile strength of the samples was measured by the Brazilian splitting tensile strength and the brittleness index was calculated as a measure of mechanical properties. In addition, inductively coupled plasma optical emission spectroscopy (ICP-OES), X-ray fluorescence spectroscopy (XRF), Rock-Eval 6, and X-ray diffraction (XRD) analysis were carried out to assess geochemical characteristics of the samples from different perspectives. The results revealed that such geochemical variations that are generally controlled by the depositional environment, would impact the mechanical properties of the samples. Based on major and trace elements proxies, the depositional environment was determined to be passive continental margin, with hot and humid paleoclimatic conditions and freshwater anoxic settings. Tensile strength and brittleness index of the shale samples was observed to vary between 0.93 and 4.12 MPa and 0.71 to 3.40, respectively, while samples with the TOC exceeding 15 wt% had a strong negative correlation with tensile strength, as reasonably expected, due to weakening impact of the sedimentary organic matter on the shale matrix. Tensile strength and brittleness index correlated positively with clay mineral content, particularly their type, but negatively with the quartz content. Furthermore, samples abundant in biogenic silica exhibited reduced brittleness compared to those with lithogenic silica. Nevertheless, the variation in mechanical properties with burial depth was not substantial, and the examination of stress-strain curves indicated an overall brittle nature of the layer where the samples were retrieved from. Overall, achieving more robust conclusions regarding mechanical stratigraphy within the studied section of the Rajmahal Basin, would necessitate additional vertical sampling. [ABSTRACT FROM AUTHOR]

Although artificial maturation of hydrocarbon source rocks by laboratory pyrolysis is far from representing natural maturation, it is a useful tool to investigate the process. In this study, we used routine open system pyrolysis for powder samples and Restricted System anhydrous Pyrolysis (RSP) for cm-sized Silurian shale source rock fragments to artificially mature the samples to different end-temperatures in the presence of a flowing carrier gas. Maturation experiments on rock fragments enable the simulation of physical barriers for the generated hydrocarbons that need to be overcome before expulsion from the source rock can occur. Based on the artificial maturation results in this study, oil expulsion efficiency from the Silurian shale source rock was 46% at the early oil generation stage and increased to 74% at approximately the peak oil generation stage. Furthermore, we have compared artificial maturation results from powder-form and fragment-form samples with natural-maturation series and found that artificial maturation of fragment-form samples sufficiently resembles natural maturation of the Silurian shales. It is therefore possible to simulate the early, middle and peak oil generation stages of natural maturation and expulsion efficiencies. This implies that, lab-based oil expulsion efficiencies from increasing maturity and hydrocarbon generation can be incorporated into the basin modeling. Basic analytical protocols for open-system and restricted-system pyrolysis employed to determine oil expulsion efficiency. [Display omitted] • Powder- and fragment-form Silurian shale samples were artificially matured. • Artificial maturation of fragment-form samples is more comparable to natural maturation. • Oil expulsion efficiency can be estimated at varying artificial maturation stages. • Artificial maturation-based oil expulsion efficiency estimates can be used to calibrate basin models. [ABSTRACT FROM AUTHOR]

The burial and thermal history of sedimentary basins within oblique-slip mobile zones are unique and multifaceted, with irregular periods of subsidence that are closely related to compressional and shear stress. Modern basin modeling techniques can constrain the timing of tectonic events and thermal history as well as determine rates and magnitudes of basin subsidence, which in turn, helps guide exploration for hydrocarbons. The work presented here is the first modern basin modeling effort in the Ardmore Basin in southern Oklahoma. The study uses 12 one-dimensional burial history models to evaluate the thermal maturity of the Late Devonian (Famennian)–Early Mississippian (Tournaisian) Woodford Shale and the Early–Late Mississippian (Tournaisian–Serpukhovian) Caney Shale hydrocarbon source rocks. All models display a similar tectonic evolution with subsidence during and following Cambrian Iapetan rifting, tectonic stability during a Silurian–Late Mississippian passive margin phase, Pennsylvanian synorogenic subsidence, Permian post-orogenic subsidence, Late Permian–Early Cretaceous regional uplift and unroofing, and Early Cretaceous–Paleogene subsidence of the Gulf of Mexico Basin. Episodic Pennsylvanian subsidence appears to have been synchronous with sequential uplift of the Wichita Uplift and the Arbuckle Uplift in response to major left-lateral transpression. Rapid and high magnitude Late Mississippian–Permian subsidence (>250 m/m.y.; 820 ft/m.y. in basin synclines) suggests the Ardmore Basin functioned episodically as an elevator basin, which is typical of sedimentary basins in oblique-slip mobile zones. The Devonian–Mississippian shale section has a broad range of thermal maturity (vitrinite reflectance, 0.40–2.00% R o), which is strongly dependent on structural position. Isoreflectance lines are subhorizontal and cross-cut structure, indicating post-kinematic thermal maturation in which strata are thermally immature in uplifts and thermally overmature in the deepest synclines. The post-kinematic pattern is a product of a rapid, early phase of synkinematic thermal maturation that has been obscured by a prolonged period of post-kinematic thermal maturation. Variations in basal heat flow, structural history, and general variability of hydrocarbon source rock organic composition, particularly at low thermal maturity levels, have resulted in a modest degree of scatter in the vitrinite reflectance-depth data. • Subsidence events within oblique-slip mobile zones occur quickly (hundreds of meters per million years). • Hydrocarbon source rock thermal maturity is related to structural position in convergent oblique-slip mobile zones. • Significant subsidence can occur far from collisional margins. • Rapid burial correlates with high rates of hydrocarbon generation driven by synorogenic subsidence. • Structural geometries within convergent oblique-slip mobile zones are mostly thick-skinned. • Modern basin modeling techniques can be used to predict hydrocarbon source rock maturity. [ABSTRACT FROM AUTHOR]

For the first time, a cutin-like, highly chemically resistant macropolymer has been isolated from rachises of Karinopteris sp. (lyginopteridalean pteridosperm, Middle Pennsylvanian). Samples are obtained from a cuticular or "paper" coal-shale, i.e., an organic-rich and highly clastic rock associated with the Upper Block Coal Member of the Brazil Formation, Parke County, west-central Indiana, U.S.A. Karinopteris specimens are preserved as naturally oxidized compressions, termed "fossilized cuticles", and possibly represent vegetation of mineral substrate environments. Employing laboratory oxidation reactions, the fossilized cuticle of Karinopteris rachises is used to obtain the cuticle. After additional and long-term oxidation treatment, the cuticle yields the cutin-like macropolymer, here referred to as "cutin" for simplicity. The fossilized cuticle, cuticle, and cutin samples of Karinopteris sp. are chemically analyzed using semi-quantitative Fourier transform infrared (FTIR) spectroscopy. Cutin IR spectra of Karinopteris rachises are characterized by (a) a predominantly aliphatic composition as indicated by intense aliphatic (CH al) C H stretching peaks at 3000–2700 cm−1, which are assigned to methylene (CH 2) and methyl (CH 3) groups; (b) carbonyl (C=O) groups at 1730–1640 cm−1, and aromatic carbon (C=C) absorption bands at 1600–1500 cm−1. A comparison with the cuticle, the cutin stands out due to relatively higher values of CH 2 /CH 3 and C=O/C=C, while displaying notably low values of CH al /C=O and C C contribution. Specifically, the relatively low value of CH al /C=O ratio obtained for the cutin of Karinopteris rachises is consistent with those found in the cutin of extant and fossil leaves. This lower CH al /C=O ratio indicates the important role likely played by C O groups in creating a deformable and flexible structure in both the cutin and the cuticle. Such a reduced rigidity suggests a high level of rachis flexibility of the once-living Karinopteris plant, supporting the interpretation of a climbing or liana habit. Cutin isolation and its chemical characterization shed light on the probable biomechanical (flexibility) properties of Karinopteris rachises, thereby enhancing our understanding of the plant growth habit. [Display omitted] • First-time spectroscopic study of Indiana "paper" coal (Pennsylvanian, U.S.A.). • Cutin polymer is obtained from fossilized cuticles of Karinopteris rachises. • Fourier transform infrared spectroscopy supplies chemical data. • Cutin is mainly aliphatic with highly crossed-linked ester carbonyl (C=O) bonds. • High C O contents suggest a liana-like Karinopteris plant with flexible rachises. [ABSTRACT FROM AUTHOR]

The lacustrine shales in the Lodève Basin, southern France, serve as excellent archives of paleo-lake development as well as climatic evolution during the Early Permian. In this study, an extensive dataset is presented encompassing organic petrographic data, major and trace element quantification, bulk and molecular organic geochemical proxies, as well as compound-specific stable carbon isotope data derived from the analysis of 36 black shale outcrop samples originating from the Usclas-St. Privat Formation (USPF), Tuilières-Loiras Formation (TLF), and Viala Formation (VF). All sample are thermally oil-mature, as evident from a vitrinite reflectance (VR r) of around 0.8%. The lower section of the USPF, characterized by notably higher total sulfur (TS) concentrations, displays total organic carbon (TOC) and TS contents spanning from 2.69 to 7.83 (avg. 4.28) wt% and 0.42–1.55 (avg. 1.09) wt%, respectively. In contrast, the upper section of the USPF (average TOC of 2.59 wt%), TLF (average TOC of 2.66 wt%), and VF (average TOC of 3.17 wt%) exhibit considerably lower TS contents of 0.26 wt%, 0.22 wt%, and 0.17 wt%, respectively. The lower section of the USPF, characterized by the lowest pristane/phytane (Pr/Ph) ratio and the highest TS/TOC ratios and chemical index of alteration (CIA) values, was deposited in oxygen-depleted and saline lacustrine environments. These conditions prevailed under more humid climatic conditions and were probably related to marine incursions. In contrast, the upper section of the USPF, the TLF, and the VF display elevated Pr/Ph ratios but reduced TS/TOC and CIA values, signifying deposition within oxic-dysoxic and freshwater-brackish bottom water conditions with a significant change towards arid conditions. All samples are characterized by low vitrinite and inertinite contents together with consistently similar average values of Al 2 O 3 and TiO 2. The biomarker analysis suggests that the organic matter (OM) in most samples mainly originates from planktonic/algal biomass with additional microbial OM. Only the lower section of the USPF displays a slightly enhanced contribution of terrestrial OM input and also more detrital elements. It is concluded that the structural evolution of the basin from narrow deep towards wider and shallower settings as well as the postulated marine transgressive events during early stages played a crucial role in shaping the deposition environments of the two distinct sets of lacustrine shales, thereby influencing the OM accumulation mechanisms. In contrast, the substantial climatic aridification seems to have a relatively minor impact on the sources of OM and the conditions prevailing within the water column. • First detailed geochemical characterization of Early Permian lacustrine shales in the Lodève Basin • Geochemical proxies indicate marine incursion in the early lake stage with episodic photic zone euxinia. • Climatic evolution from more humid to more arid during the Early Permian • Deposition of organic matter controlled by tectonic activity and primary productivity. [ABSTRACT FROM AUTHOR]

Semi-closed hydrous pyrolysis (HP) of whole-rock cuboids is a relatively novel technique aimed at improving the knowledge of the geochemical and petrographic alteration of petroleum source rocks. This study evaluates the comparability of observations on petroleum generation and migration in a natural maturation sequence and after HP in the same source rock. Two artificially matured samples of the Lower Jurassic (Toarcian) Posidonia Shale from the Hils Syncline (Lower Saxony Basin) were subjected to 24 h-HP experiments at 280 °C, 300 °C, 320 °C, 330 °C and 340 °C. The samples were subsequently analyzed with respect to changes in Rock-Eval pyrolysis parameters, molecular organic geochemistry, and organic petrography. After HP at 280 °C and 300 °C, organic geochemical composition and organic petrographic characterization show only minor changes. Significant geochemical and petrological changes occur at 320 °C: Tasmanales and Leiosperidales phytoclasts show weakened fluorescence and volume loss, accompanied by a pronounced decrease in the Rock-Eval S2 yield of the sample, indicating conversion of kerogen to petroleum products. Optical changes are even more pronounced at 330 °C and 340 °C, when very high transformation ratios are reached, exceeding those under natural conditions. The majority of aliphatic molecular geochemical proxies for thermal maturation show systematic changes with increasing vitrinite reflectance, similar to maturation trends observed in the natural maturation sequence. However, some hopanoid thermal maturity proxies (e.g. moretane/C 30 hopane) show unexpected inverse trends, whereas aromatic hydrocarbon ratios hardly change with increasing HP temperatures. These observations suggest that the reactions leading to changes in these parameters require considerably more time than C C bond breaking (cracking) within the kerogen structure. A large part of the organic carbon remaining in the cuboids after HP at 330 °C and 340 °C is soluble in dichloromethane and should, therefore, be classified as bitumen rather than kerogen. [ABSTRACT FROM AUTHOR]

Abstract With increasing global energy demands, unconventional formations, such as shale rocks, are becoming an important source of natural gas. Extensive efforts focus on understanding the complex behavior of fluids (including their transport in the sub-surface) to maximize natural gas yields. Shale rocks are mudstones made up of organic and inorganic constituents of varying pore sizes (1-500 nm). With cutting-edge imaging technologies, detailed structural and chemical description of shale rocks can be obtained at different length scales. Using this knowledge to assess macroscopic properties, such as fluid permeability, remains challenging. Direct experimental measurements of permeability supply answers, but at elevated costs of time and resources. To complement these, computer simulations are widely available; however, they employ significant approximations, and a reliable methodology to estimate permeability in heterogeneous pore networks remains elusive. For this study, permeability predictions obtained by implementing two deterministic methods and one stochastic approach, using a kinetic Monte Carlo algorithm, are compared. This analysis focuses on the effects resulting from pore size distribution, the impact of micro- and macropores, and the effects of anisotropy (induced or naturally occurring) on the predicted matrix permeability. While considering multiple case studies, recommendations are provided on the optimal conditions under which each method can be used. Finally, a stochastic analysis is performed to estimate the permeability of an Eagle Ford shale sample using the kinetic Monte Carlo algorithm. Successful comparisons against experimental data demonstrate the appeal of the stochastic approach proposed. Highlights • We propose a 2D KMC algorithm to calculate pore network permeability. • KMC is a sensitive and reliable method to modeling anisotropy. • KMC's shale permeability prediction is in reasonable agreement with experiments. • Deterministic methods in their original form are ideal for narrow log-normal PSDs. • Deterministic methods are sensitive to high-permeability pores variations. [ABSTRACT FROM AUTHOR]

Abstract The presence of solid bitumen strongly affects hydrocarbon storage and expulsion from a source rock as it might either cause blockage of pore throats leading to lower effective gas permeability, or contribute to hydrocarbon storage and provide migration pathways when a continuous network of hydrocarbon-wet organic matter (OM) pores is formed. Furthermore, organic matter transformation reactions are suggested to influence mineral diagenesis as well. In an attempt to characterize different solid bitumen types and transformation stages over a broad maturity interval (0.5–2.7%Ro) and for varying primary kerogen compositions, we reviewed optical and scanning electron microscopy (SEM) data of 35 solid bitumen-rich shale samples with a Cambrian to Triassic age. We were able to identify in-situ pre-oil solid bitumen, as well as remobilized post-oil solid bitumen at various maturity stages from the early oil window onwards. Solid bitumen is the main host for SEM-visible organic matter porosity; onset of porosity development in solid bitumen differs considerably between predominantly oil-prone (e.g., alginites, amorphous OM from algal and bacterial precursors) and gas-prone (vitrinite-rich) kerogen compositions. Furthermore, solid bitumen (pyrobitumen) in rocks with a terrestrially dominated OM composition seems to be considerably less mobile within the source rock compared to pre- and post-oil solid bitumen in oil-prone rocks, and less reactive in terms of porosity generation. In most samples, several solid bitumen populations with varying fluorescence properties and bitumen reflectance were observed, complicating the use of these petrographic maturity indicators. The apparently different solid bitumen populations often form continuous networks at the SEM-scale. Microstructural features such as irregularly distributed sponge-like porosity or detrital and authigenic mineral inclusions in the sub-micrometer scale were found to have a great influence on texture and reflectance under reflected light microscopy. The formation of authigenic minerals (quartz, various carbonate phases with different Ca/Mg/Fe proportions, magnetite in Cambrian samples) was observed frequently in post-oil solid bitumen of oil-prone rocks, indicating a close genetic relationship between transformation products formed during hydrocarbon generation (e.g., acetate, carbon dioxide and methane) and the dissolution and precipitation of minerals during diagenesis. In some cases, stylolite-like features in the sub-micrometer scale were found, showing that processes well-known from reservoir characterization at core-scale also play a role at the micrometer-scale. Furthermore, the observed strong interaction between organic matter transformation and mineral authigenesis indicates a substantial aqueous component even in pores filled apparently exclusively with solid bitumen. Highlights • Combined optical and scanning electron microscopy was applied to 35 Cambrian to Triassic solid bitumen-rich shales. • Solid bitumen shows complex textural features at microscale. • A pore evolution model was established for oil- and gas-prone organofacies. • Solid bitumen reflectance varies considerably within one sample. • Mineral authigenesis is strongly influenced by solid bitumen transformation. [ABSTRACT FROM AUTHOR]

Abstract Sedimentary environment and redox conditions play a significant role in the formation of organic-rich shale. The vertical variations of major/trace elements, TOC (total organic carbon) and mineral compositions were investigated for the Lower Silurian Longmaxi typical marine shale in the Upper Yangtze Platform, South China, to decipher sedimentary environment (redox conditions, detrital input, sedimentation rate (SR), paleoproductivity and watermass restriction). This gives insight to the effects of variations in sedimentary environment on the formation of organic-rich shale. The results show that the Lower Longmaxi Formation is composed of three systems tracts: TST (transgressive systems tract), EHST (early highstand systems tract) and LHST (late highstand systems tract). From TST to LHST, the contents of TOC, quartz and pyrite decline steadily, whereas clay minerals and carbonate show an increasing trend. Thus, organic-rich siliceous (ORSS), organic-moderate mixed (OMMS) and organic-lean argillaceous (OLAS) shales are dominant for TST, EHST and LHST, respectively. Due to a continues fall of the relative sea-level, a deep-water shelf environment with anoxic condition, high paleoproductivity and low detrital input in TST gradually evolves into a semi-deep-water environment with dysoxic-oxic conditions, moderate paleoproductivity, and moderate detrital influx in EHST, further to an environment of oxic condition, low paleoproductivity, and high detrital flux in LHST. As evidenced by Mo-TOC and Mo U patterns, ORSS was deposited in a moderately restricted watermass, weaker than Black Sea, which progressively evolved into an enhanced restriction degree during the deposition of OMMS and OLAS due to a fall of relative sea-level. Major/trace elements and excess silica (EX-SiO 2) concentrations illustrate that origins of quartz in the Lower Longmaxi shale are primarily terrigenous, biogenic and authigenic (smectite illitization). The average proportions of EX-SiO 2 (biogenic and authigenic quartz) are 52.34%, 24.86% and 6.57% for ORSS, OMMS and OLAS, respectively. Biogenic quartz is the dominant contributor to EX-SiO 2 , while the contribution of authigenic quartz is limited, and the formation of the former is earlier than the latter according to the diagenetic transformation temperature. As both biogenic quartz and organic matter are firmly related to the abundance and preservation of paleoorganisms, anoxic condition, high paleoproductivity, low detrital flux and moderate restriction collectively control the high enrichment and preservation of organic matter and biogenic quartz, while oxic condition, low paleoproductivity, high detrital flux and stronger watermass restriction are unfavorable for the enrichment of biogenic quartz and organic matter. Highlights • Watermass restriction levels based on Mo-TOC and Mo-U patterns during the deposition of the Lower Longmaxi shale; • Origins and enrichment mechanisms of quartz and organic matter under various sedimentary environments; • Evolution model of sedimentary environments and their effects on the formation of organic-rich shale. [ABSTRACT FROM AUTHOR]

This study conducted comprehensive bulk and molecular geochemical analyses, as well as elemental investigations, on seventeen black shale samples collected from the Upper Cretaceous sediments on the western margin of the Red Sea. The primary objective is to assess the hydrocarbon generation potential, maturity, source input, biodegradation levels, and depositional environment characteristics within the Lower Maastrichtian interval near the Safaga area. Lower Maastrichtian black shales demonstrate very good to excellent source rock generative potential based on pyrolysis data. The prevalent kerogen type in the older black shale at the Heweitat mine is Type II, whereas within the younger units at the Queih mine, it predominantly exhibits Type II/III kerogen. These Maastrichtian black shales remain thermally immature, as evidenced by vitrinite reflectance (VRr < 0.5%), pyrolysis data, and biomarker proxies. The studied black shales show that the organic matter input comprises bacterial and algal biomass with minor terrigenous contributions. Additionally, there is no evidence of significant biodegradation in the studied samples based on molecular fossils data. Microscopic analysis and various bulk and molecular characteristics, in conjunction with major and trace element profiles, collectively indicate a marine depositional environment with oxygen-deficient bottom water conditions during source rock deposition. The presence of isorenieratene and aryl isoprenoids suggests persistent and episodic photic zone anoxia during the Maastrichtian period. Elevated nutrient inputs and paleobioproductivity were recorded in the older black shale at the Heweitat mine compared to the younger one at the Queih mine. Paleoproductivity and oxygen depletion emerge as pivotal factors influencing the accumulation and preservation of organic matter within the black shales. These findings provide valuable insights into the environmental conditions prevailing during the deposition of Maastrichtian sediments in the Eastern Desert. • Lower Maastrichtian black shales exhibit excellent source rock potential. • Organic input primarily consists of bacterial and algal biomass. • Marine reducing settings are evaluated for the studied samples. • Productivity and nutrients are crucial for sediment accumulation and preservation. [ABSTRACT FROM AUTHOR]

In-situ conversion processes (ICP) represents an effective approach for the commercial exploitation of low- to medium-maturity shale oil. The thermodynamic and microstructural properties of kerogen, as the primary organic matter in shale, have important implications for the design and optimization of ICP. However, the thermodynamic and microstructural properties of the lacustrine Chang-7 shale remain unclear, and conducting ICP pilot tests continues to pose challenges. By employing elemental analysis, pyrolysis-gas chromatography/mass spectrometry (Py-GCMS), solid-state carbon nuclear magnetic resonance (13C NMR), X-ray photoelectron spectroscopy (XPS), and Fourier transform infrared spectroscopy (FTIR), the representative models for lacustrine Chang-7 shale kerogens with different organic matter types and maturity levels were established. Semiempirical quantum mechanics and molecular dynamics were leveraged to study thermodynamic and microstructural properties of kerogen. Subsequently, by integrating cluster analysis and partial least squares methods, quantitative correlations among kerogen structural parameters and thermodynamic, kinetic, and volumetric properties were identified. The findings suggest that low-maturity type I kerogen is predominantly consisted of long-chain aliphatic hydrocarbons, whereas the degree of aliphatic chain branching increases in type II 1 kerogen. Medium-maturity type II 1 kerogen exhibits the highest degree of condensation, but the length and degree of branching of its aliphatic chains are closely analogous to low-maturity type I kerogen. Between 273 K and 473 K, the ideal heat capacity of Chang-7 shale kerogen increases linearly by approximately 51%. The enthalpy of formation and ideal heat capacity of medium-maturity type II 1 kerogen are the highest. With increasing maturity and declining H/C ratio, the density of Chang-7 kerogen increases. Its matrix pore sizes are primarily concentrated at 0.1–0.2 nm, constituting >80% of all pores. Kerogen with long and abundant aliphatic chains, a moderate degree of condensation, high porosity, low activation energy, and moderate heat capacity is considered the preferred target. The findings offer substantial guidance for the ICP of lacustrine shale. • Three lacustrine Chang-7 shale kerogen models with different organic matter types and maturities were established. • The thermodynamic and microstructural properties of lacustrine Chang-7 shale kerogen were studied. • The relationship between kerogen structural parameters and its thermodynamic and volumetric properties were identified. [ABSTRACT FROM AUTHOR]

The potential of China's saline lacustrine shale oil resources is enormous. Currently, the storage space of saline lacustrine shale oil remains unclear, posing significant challenges for commercial development. In this study, we selected the samples from the typical saline lacustrine shale strata of the Lucaogou Formation, Jimusar Sag, Junggar Basin and investigated the pore systems and their relationship with oil content S 1 of different lithofacies. The pore structures were quantified by using the combination of low-pressure N 2 adsorption and mercury intrusion. TOC assessment, rock pyrolysis, and XRD were utilized for characterizing the organic geochemical and mineralogical parameters. The results showed that the organic matter comprising type III mainly appears in the clay-enriched lithofacies (types I 2 , II 1 and III 2), while the organic matter types I, II 1 and II 2 can be found in other lithofacies. Regarding the nine lithofacies, siltstone has the highest oil content S 1 , followed by the felsic-enriched lithofacies (types III 3 and III 1). The enrichment of oil in siltstone, carbonate rocks, and felsic-enriched lithofacies (types III 3 and III 1) is primarily attributed to macropores. Conversely, in clay-enriched lithofacies (types I 2 , II 1 and III 2), the oil content S 1 is attributed to both the mesopore fractal dimensions (D 1 and D 2) and the TOC content. Moreover, the higher the complexity of the mesoporous structure (D 2) and the larger the macropore surface area in clayey carbonate felsic shale (II 3), the greater the oil content S 1. It is further observed that, macropores with size range between approximately 60 nm and 3000 nm are abundant in siltstone and felsic mineral-enriched lithofacies (i.e., carbonate felsic shale III 3 and felsic shale III 1). Furthermore, the siltstone shows the widest oil-rich macropore size range (range of 70–1000 nm), followed by felsic shale (III 1) (range of 150–1000) and carbonate felsic shale (III 3) (range of 100–110 nm). Siltstones and felsic-enriched shales are optimal for exploiting saline lacustrine shale deposits. • Siltstone has the highest S 1 , followed by felsic minerals-enriched shale. • S 1 in siltstone, carbonate rocks, felsic-enriched shale is related to macropores. • S 1 in clay-enriched shale is attributed to both mesopore fractal dimension and TOC. • Siltstone shows the widest oil S 1 -rich macropore size range among lithofacies. [ABSTRACT FROM AUTHOR]

Shale gas exploration in the Dingshan plunging anticline of the Sichuan Basin, China, has uncovered substantial Wufeng–Longmaxi shale reserves. However, substantial variations exist in shale gas content and production among the wells in this region. We investigated the geological factors and mechanisms influencing shale pore structure heterogeneity and shale gas content and production in the area. We conducted comprehensive analyses of mineralogy, geochemical characteristics, and petrophysical properties on the Late Ordovician Wufeng Formation–Early Silurian Longmaxi Formation shales. Shale samples were collected from a shallow well, Anwen-1, located in proximity to the Qiyueshan thrust fault within the Dingshan plunging anticline. Additionally, samples from Dingye (DY) 1 and DY 3 wells, located at varying distances from the thrust fault, were examined. We also integrated previously published data from two correlative sections in the southeastern margin of the Sichuan Basin, each at different distances from the thrust fault. The pore volume, specific surface area, and porosity of the shales were positively correlated with their total organic content (TOC). However, strong lateral compressive stress, often occurring near the regional thrust fault, attenuated the linear relationship between TOC and pore volume/porosity. Lateral compressive stress did not significant affect shale porosity and pore structure when the distance from the regional thrust fault exceeded approximately 15 km. The specific surface area of the shale was less affected by compressive stress. Moreover, carbonate cementation reduced porosity by sealing shale matrix pores and natural microfractures, reducing nanopore connectivity. Consequently, shale gas production is not solely influenced by shale gas content but is also significantly affected by carbonate cementation. Therefore, shale reservoirs located at relatively long tectonic distances from regional thrust faults (approximately 15 km) within the Dingshan plunging anticline exhibit high pore volume, porosity, and shale gas content, rendering them favorable for shale gas exploration. • Mineral compositions and mechanical compaction influence shale pore structure. • Differences in shale gas content and shale gas production from different wells in the Dingshan area were discussed. • Tectonic location relative to thrust faults (< 15 km) influences shale properties. • Carbonate content (> 10%) can significantly reduce shale gas production. • Both compressive stress and carbonate cementation influence heterogeneity of shale pore structure and shale gas production. [ABSTRACT FROM AUTHOR]

The Devonian–Mississippian (D–M) black shales of the Bakken Formation are of interest as a hydrocarbon source due to their high total organic carbon (TOC; 2.2–17.4%) content. The Upper and Lower Members of the Bakken Fm. are shallow marine (100–150 m) sequences. Thirty samples were selected for maceral identification, kerogen typing, and solid bitumen reflectance (SBR o) based on TOC content and down-core spacing. The shales contain alginite, bituminite, abundant solid bitumen (SB), and minor amounts of inertinite. Solid bitumen increases in quantity with increasing thermal maturity. Pyrolysis (85 samples) provided S1 (avg. 8.0 mg HC/g rock), S2 (avg. 24.3 mg HC/g rock), hydrogen index (HI; avg. 201 mg HC/g TOC), oxygen index (OI; avg. 7 mg CO 2 /g TOC), and R o (0.60–1.03%) calculated from T max. Plots of HI vs. OI and HI vs. T max (°C) were used to assess kerogen type but are not consistently in agreement with the petrographic assessment. Some samples from more thermally mature cores plot as Type III (vitrinite) kerogen instead of Type II (alginite and bituminite) kerogen, the latter confirmed through petrographic observations of lower maturation samples. This is largely due to increased SB in more thermally mature samples (R o = 0.83–1.03%), as SB is known to have a lower HI content than Type II kerogen. Petrographic data show more alginite and bituminite (19–55%) in the thermally less mature samples (R o = 0.60–0.83%) compared to more dispersed SB (67–86%) and less alginite and bituminite (<1%) in the more thermally mature samples (R o = 0.89–1.01%). Early research on the Bakken Fm. reported lower than expected vitrinite reflectance values and attributed them to vitrinite "suppression". The scarcity of vitrinite and abundance of SB suggest that early work likely reported reflectance on SB. Recent attempts to assess the thermal maturity of the Bakken black shales have converted SBR o to vitrinite reflectance equivalence (V RE). However, there are multiple SB populations present in these shales and it is not always clear which SB populations were included, possibly contributing to error. In the current study, only smooth, homogenous SB was measured (0.68–1.14% SBR o) and V RE values calculated (0.54–1.49%) to assess thermal maturity from the basin margin to the depocenter; inclusion of measurements on granular, heterogeneous SB (14–21 vol%), which are ∼53% lower than those for smooth, homogenous SB (3–12 vol%), results in lower mean reflectances, especially in more mature samples. Vitrinite reflectance equivalent data calculated using the D–M New Albany Shale equation of Liu et al. (2019) agrees with liptinite fluorescence and Rock-Eval R o , whereas V RE based on the D–M Woodford Shale equation of Cardott and Comer (2021) does not. This suggests the importance of applying V RE equations from similar formations both in terms of thermal history, as well as kerogen type and age. Results from SBR o , Rock-Eval R o , V RE , and observations of alginite fluorescence indicate that samples from the current study range from the early oil window into the condensate, wet gas zone. • Bakken Shale contains multiple solid bitumen populations but scarce vitrinite. • Alginite and bituminite decrease while solid bitumen increases at higher maturity. • New Albany Shale V RE equations work better than one from the Woodford Shale. • Combining V RE , fluorescence, and Rock-Eval data provides more accurate maturity. • Increases in solid bitumen affect Rock-Eval kerogen typing. [ABSTRACT FROM AUTHOR]

Oil mobility is essential for the evaluation of shale oil resources, yet there has been limited research conducted on the oil mobility of low- to medium-maturity lacustrine shale. This study integrates multiple methodologies such as organic geochemistry, mineralogy, oil-kerogen adsorption-swelling experiments, and in-situ conversion process (ICP) models to evaluate the mobility and potential for shale oil in the lacustrine shale of the Yanchang Formation in the Yaoqu 1 (YQ1) well situated in the southeastern region of the Ordos Basin. The Chang 7 shales are categorized as highly favorable source rocks, nonetheless, the oil contained within these layers predominantly exists in an adsorbed-swelling state, resulting in limited mobility as indicated by the oil saturation index, a modified oversaturation index, and production index. Therefore, the utilization of existing conventional techniques for shale oil exploitation is not viable for the Chang 7 shale characterized by low to medium maturity in the study area. Nevertheless, during the ICP, the quantity and mobility of oil within the Chang 7 shales exhibit a substantial increase as temperature rises. Moreover, once the Chang 7 type II shales reach a maturity level of around 0.91%R o , they demonstrate noteworthy prospects for shale oil production. The findings of this study serve as a valuable reference for guiding the advancement of in-situ conversion process technology in the study area, while also offering substantial evidence for addressing the intricate challenge of crude oil mobility in low- to medium-maturity lacustrine shale reservoirs. • The characteristics of the Yanchang Formation shale were introduced in the Southeast Ordos Basin, China. • The potential and mobility of shale oil in low- to medium-maturity lacustrine shales were assessed. • The exploration potential of low- to medium-maturity lacustrine shale was evaluated by simulated in-situ conversion process. [ABSTRACT FROM AUTHOR]

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

Abstract The evolutionary characteristics of pore structure from Permian marine-continental transitional shale were examined based on a suite of natural shale samples from the Ningwu and Qinshui Basins in northern China, which ranged in maturity from immature (vitrinite reflectance, Ro = 0.44%) to over-mature (Ro = 1.85%). Experiments included mercury intrusion, nitrogen adsorption, and carbon dioxide adsorption, and were conducted to quantify pore volume and pore size distributions. Samples with different thermal maturity had large differences in micropore, mesopore, and macropore volume and pore size distributions. Mesopore and macropore volumes were the largest in immature shale and declined with increasing maturity to intermittent minima in the mature shale, continuing to increase to the over-mature shale. However, micropore volume gradually increased during maturation. The pore-related variances may be primarily controlled by maturity, whose effect was stronger than other factors (total organic carbon and mineral composition). During maturation, changes in pore size distribution and relative proportions of micropores, mesopores, and macropores were related to both chemical (transformation of organic matter into hydrocarbons) and mechanical (compaction) processes. Pore volume was reduced during the transition from immature to mature stage, likely mainly due to compaction instead of liquid hydrocarbon filling the pores, whereas the increase in pore volume during the transition from the mature to over-mature stage was mainly associated with the transformation of organic matter. Highlights • The pore evolution process of transitional shale was studied by natural samples. • Pore volume reducing may be mainly due to compaction instead of bitumen filling. • The development of pore structure may be associated with organic matter evolution. • Marine shale and transitional shale may have a different pore evolution pattern. [ABSTRACT FROM AUTHOR]

Abstract Exploration in the Beetaloo Sub-basin in Australia's Northern Territory has indicated gas-saturated, quartz-rich source rocks that are gas mature and laterally continuous over large areas. In the Sub-basin shale targets have been identified within the Velkerri Formation and the Kyalla Formation. These shales are of Mesoproterozoic age and thus significantly older than any of the North American shale plays and most other shales currently under investigation for their gas production potential. In this work, we characterise two sets of drill cutting samples from the Beetaloo Sub-basin for their composition, pore structure, and CH 4 adsorption capacity. The objective of this study is to assess the adsorption potential of these shales and investigate the properties controlling this. Measurements from other researchers are included in the analysis to determine to what degree commonly characterised properties such as bulk clay and total organic carbon (TOC) content control gas adsorption capacity on a larger scale and thus provide an indication of the range of adsorption behaviours that may be expected. The adsorption measurements are carried out at reservoir conditions - that is high pressures (up to 30 MPa) and high temperatures (up to 110 °C). The results show that the organic-rich (TOC: 3.7–6.2%) middle Velkerri shale samples have a significantly higher adsorption capacity (expressed by the Langmuir volume) than the clay-rich, organic-lean (TOC: 0.85–1.8%) lower Kyalla shale samples: 2.89–3.38 m3/t compared to 1.88–2.81 m3/t. This is in agreement with the higher average micropore volume of the middle Velkerri shale samples. Results of our analysis demonstrate that, depending on a shale's composition, different properties control gas adsorption in shale, though in the organic-rich middle Velkerri B shale samples the controlling paramters cannot be clearly determined. A positive correlation between TOC and CH 4 adsorption capacity is observed, but only up to a TOC of 4.5%. Above this point the adsorption capacity appears to decrease again. The lack of a strictly positive correlation between TOC and adsorption capacity is likely caused by other parameters affecting sorption behaviour, in particular variations in organic matter type and thermal maturity. However, analysis of a global adsorption data set of marine shales of non-differentiated maturity nevertheless indicates that, on a larger scale, the TOC content can provide a reasonable first estimate of a shale's CH 4 adsorption capacity. In the organic-lean lower Kyalla shale samples clay minerals control microporosity and CH 4 adsorption. It is the high illite/muscovite content (30–40%) in particular that is indicated to be the main contributor to microporosity and gas adsorption capacity. Results from the analysis of the global shale adsorption data set are in agreement with these findings, showing that for organic-lean shales with a TOC < 2% clay may be the primary control on CH 4 adsorption. Highlights • Beetaloo Sub-basin drill cuttings were characterised for their composition, pore structure, and CH 4 adsorption capacity • A positive correlation between TOC and CH 4 adsorption is observed for the middle Velkerri B shale up to a TOC of 4.5%. • For a set of marine shales the TOC content provides an initial indication of a shale's expected CH 4 adsorption capacity. • In the lower Kyalla shale samples clay minerals (in particular illite/muscovite) control microporosity and CH 4 adsorption. • The global shale data set indicates that in shales with a TOC < 2% clay may be the primary control on CH 4 adsorption. • Beetaloo Sub-basin drill cuttings were characterised for their composition, pore structure, and CH4 adsorption capacity • A positive correlation between TOC and CH4 adsorption is observed for the middle Velkerri B shale up to a TOC of 4.5%. • For a set of marine shales the TOC content provides an initial indication of a shale's expected CH4 adsorption capacity. • In the lower Kyalla samples clay minerals (in particular illite/muscovite) control microporosity and CH4 adsorption. • The global shale data set indicates that in shales with a TOC < 2% clay may be the primary control on CH4 adsorption. [ABSTRACT FROM AUTHOR]

Abstract A representative molecular model of shale organic matter (OM) is prerequisite to further theoretic investigation on the fundamental mechanisms governing storage, transport and recovery of shale gas. In this work, a systematic strategy to prepare structural and compositional properties of OM is reported first, and then a realistic molecular model of Chinese Cambrian OM is generated based on analytical experimental data. Microstructure characterization and adsorption simulation are further performed using molecular dynamics simulation and grand canonical Monte Carlo simulations, respectively. The OM model, composed of kerogen macromolecules, bitumen components and residual lighter components, shows a reasonable representation of realistic Cambrian OM with respect to structural parameters, generic compositions, physical density and porosity. The OM porous network consists of dominant ultra-micropores and limited micropores. Compared with heavier components, lighter components are more inclined to occupy accessible pores. Interestingly, lighter components are observed to appear in pairs due to competitive adsorption around heteroatom groups. Water molecules are scattered in the system because of abundant functional groups and poor pore connectivity. The OM skeleton represents the adsorption behaviors of methane, carbon dioxide and nitrogen well. The adsorption capacity is carbon dioxide > methane > nitrogen. A higher adsorption capacity corresponds to a lower pressure when the excess isotherm reaches the maximum. The adsorption behaviors of heavier hydrocarbon species (ethane, propane and n-butane) cannot be represented in the OM skeleton with ultra-micropores and limited micropores, and the effect of molecular sizes of these species cannot be neglected. This work reports a systematic construction process for realistic molecular model of shale OM, and the representative OM model can serve as a starting point to explore gas adsorption and transport mechanism in shale organic pores at microscopic scale. Graphical abstract Unlabelled Image Highlights • Novel construction process for OM model is elaborated. • Direct characterization experiments are used to study kerogen chemical structure. • Representative molecular model of Cambrian OM is generated. • Microstructure characterization is performed on the OM model. • Adsorption behaviors of gas components in the OM skeleton are studied. [ABSTRACT FROM AUTHOR]

Abstract Samples of the low-maturity New Albany Shale (Middle and Upper Devonian to Lower Mississippian) and Mowry Shale (Late Cretaceous), both containing kerogen Type II, and samples of Wilcox Coal (Eocene), containing kerogen Type III, were heated to 60, 100, and 200 °C at hydrostatic ambient pressure, 100, or 300 MPa for 6 or 12 months in sealed glass and gold cells to investigate temperature and pressure effects on porosity and thermal maturity. In addition, lithostatic experiments were conducted in a hydraulic press at 100 MPa and 100 °C over a period of 6 months. Porosimetric characteristics of samples before and after experiments were investigated by using low-pressure gas adsorption and scanning electron microscope (SEM). An increase from ambient temperature to 200 °C caused increases in random vitrinite reflectance (R o) for all samples, with Mowry Shale showing the largest increase from 0.57% to 0.65% and Wilcox Coal showing the smallest increase from 0.39% to 0.41%. For Mowry Shale and New Albany Shale, specific surface areas did not change in any notable way with an increase in temperature; specific surface area values for Mowry Shale ranged from 2.0 to 3.2 m2/g, and for New Albany Shale from 13.7 to 15.6 m2/g. Differences in Barrett-Joyner-Halenda (BJH) specific mesopore volumes and average mesopore size for the shales were also small to negligible. Considering the values of the original samples, we propose that these small differences are related to internal inhomogeneity of samples rather than to any temperature effect. Temperature-related changes in Wilcox Coal were more distinct. Specifically, there was a marked decrease in BET surface area, from 4.9 m2/g at 60 °C to 1.5 m2/g at 200 °C, and a decrease in both BJH mesopore volume and average mesopore size. The Wilcox Coal sample had large micropore surface areas (110–148 m2/g) compared to both shales, which had micropore surface areas below 10 m2/g. While Wilcox Coal showed a drop in micropore volume between 60 °C and 200 °C, no distinct or regular changes in micropore volume with temperature were documented for the other two samples. A sustained hydrostatic pressure increase from ambient to 300 MPa for 6 to 12 months resulted in insignificant changes in vitrinite reflectance values. Small differences in Brunauer-Emmett-Teller (BET) specific surface areas, micropore surface area, and volume may be related to internal sample heterogeneity rather than pressure treatment. Similar to the temperature effect, the Wilcox Coal sample experienced more pronounced changes compared to the shales. SEM observations on shales did not reveal porosity-related changes between the original and treated samples. No marked changes were documented for lithostatic pressure conditions at 100 MPa and 100 °C. We conclude that elevated isotropic hydrostatic or lithostatic pressure is unable to significantly affect the pore structure and pore-size distribution of shales, but it can make some modifications in the micropore and mesopore pore characteristics of low-rank coal. Highlights • Temperatures 60, 100, 200 °C and pressures 100 MPa and 300 MPa caused only minimal changes in maturity of coal and shales. • Coal experienced a more pronounced temperature effect on porosity than shale samples. • Hydrostatic and lithostatic pressures up to 300 MPa did not cause significant changes in shale samples. • Coal was more susceptible than shales to pressure-related porosimetric changes. [ABSTRACT FROM AUTHOR]

The presence of water in mudrocks has a largely negative impact on production of gas stored in these rocks, due to the fact that water causes swelling of the rock. Removing the water from the mudrock could potentially shrink the rock and increase the overall permeability of the rock. Investigation of the swelling/shrinkage behaviour of the rock during exposure to water vapour is of key importance in designing and optimizing unconventional production strategies. We have used outcrop samples of the Whitby Mudstone and the Posidonia shale, potential unconventional sources for gas in North-western Europe, to measure the swelling and shrinkage behaviour. Swelling and shrinkage of the rocks when exposed to water vapour was measured directly using 1 mm sample cubes in two different setups. The mm cubes were exposed to different levels of relative humidity either in an Environmental Scanning Electron Microscope (ESEM) or in a 3D dilatometer. Swelling of Whitby Mudstone and Posidonia shale is heterogeneous with 2–3 times more measured swelling strain perpendicular to the bedding. Volumetric swelling strains showed values between 0.6 and 2.2% for the Whitby mudstone and the Posidonia shale, respectively. The results suggest that it might be possible to increase permeability in the reservoir by decreasing the in-situ water activity due to shrinkage of the matrix. [ABSTRACT FROM AUTHOR]

The shale beds associated with Permian coal-bearing Barakar Formation of the Latehar-Auranga coalfield (north Koel Valley), India have been investigated for the hydrocarbon prospects and their critical reservoir properties. The shale core samples were collected from boreholes drilled in three different blocks like Gowa, Jagaldaga and Banhardih. The shale core samples are examined for in-situ gas content, desorbed gas composition, geochemical, Rock-Eval, scanning electron microscopy (SEM), X-ray diffraction (XRD), high pressure CH 4 adsorption isotherm, porosity and permeability aspects. The shales are rich in carbonaceous and silty materials with alternate bands of intercalations; suggesting deposition of the sediments and organic matters by slow or wavering river currents under the reducing environment. The van Krevelen diagram of H/C and O/C atomic ratio of the shales has demonstrated type III/IV kerogens; specifying that organic matters transformed from the fluvio-terrestrial depositional conditions to the diagenesis and catagenesis stages and placed in wet to dry gas window (H/C ratio < 0.5). The values of in-situ gas, lost gas, desorbed gas and residual gas contents are ranging from 1.06–7.02, 0.21–0.98, 0.35–4.16 and 0.42–2.45 cc/g, respectively. The Langmuir volume (V L ) is varying between 5.6 and 0.9 cc/g, when values of V L compared to the in-situ gas revealed low to moderate gas saturation (26.86–73.75%) of the shale beds. The negative trend of Langmuir pressure (P L ) with depth suggests affinity of CH 4 to the shale pore surfaces. The plot of lower hydrocarbons ratios like (C 2 /C 1 ) × 1000 and (C 3 /C 1 ) × 1000 shows the dry thermal origin of desorbed gas. The Rock-Eval pyrolysis constituents like S1, S2, S3, PI, T max , TOC, HI, OI and Calc. VR o % varies from 0.11–0.47, 3.45–28.34 mg HC/g, 0.11–0.89 mg CO 2 /g, 0.00–0.07, 414–456 °C, 1.28–16.26 wt%, 39.54–821.45 mg HC/g TOC, 1.52–20.00 mg CO 2 /g TOC and 0.29–1.05% respectively. The plots of hydrogen index (39.54–821.45 mg HC/g TOC) with calculated VR o (0.29–1.05%) and T max (414–456 °C) are signifying types I, II, III and IV kerogen in the shales prone to generate oil, wet and dry gas placed in immature to mature regions. The positive linear correlation of the V L with kaolinite and illite contents suggests that mainly clays contribute to the formation of shale matrix. The SEM images show six types of pore: i) lenticular open pores along the fissility, ii) altered pores due to weathering, iii) intergranular pores, iv) intermingled pores between crystal lattices, v) partially filled pores associated with clays and minerals, and vi) evolved pores by cracking of the organic compounds. The values of porosity and permeability have been measured under reservoir simulated confining pressure, and are ranging from 0.87–8.18% and 0.08–1.45 mD, respectively. This shows poor connectivity between the pores and fracture mechanisms controlled by the clay and minerals. It is summarized that the studied shales of Latehar-Auranga Coalfield have a low to moderate gas potential, based on their in-situ gas, TOC content (1.28–16.26 wt%), sorption capacity, T max values and thermal maturity. Moreover, the significant residual volume, low porosity and low permeability are the most critical properties for shale gas resource development at the Latehar-Auranga coalfield. [ABSTRACT FROM AUTHOR]

Gas generation from shale source rocks typically occurs via cracking of both kerogen and retained oils, such that it is difficult to predict and compare gas generation potentials of different shales because they are related not only to the kerogen type but also to the oil expulsion efficiency. In this study, five different shale kerogen samples were pyrolyzed in sealed gold tubes to investigate how kerogen type and oil expulsion efficiency affect their gas generation after oil-window maturity. The results illustrate that the maximum extractable organic matter (EOM) and gas generation potentials of different original shale kerogens (O-kerogen) in a closed system vary widely in the range of 229–790 mg/g TOC OK and 308–594 mL/g TOC OK , respectively. However, the gas yields of different residual shale kerogens (R-kerogen) with a starting equivalent vitrinite reflectance (EqVRo) value of approximately 1.22% are quite similar and vary between 131 and 145 mL/g TOC RK . Pyrolysis experiments also reveal that the late gas generation potential (EqVRo > 1.22%) of shale is mainly controlled by the amount of retained EOMs rather than kerogen type. When the shale source rocks containing types I and II kerogens have the same amount of retained EOMs, their gas generation potentials are quite similar. Under most geological conditions, the late gas generation potentials of shale source rocks, normalized to the TOC of matured shale at 1.22% EqVRo (TOC Shale ), vary approximately in the range of 180–300 mL/g TOC Shale . To reach a gas content of 3 m 3 /ton shale for the present-day overmature shale gas exploration in the Lower Palaeozoic shales of South China, a conservative present-day TOC (TOC pd ) value of 2.0% is proposed as a screening parameter that can eliminate the risk of insufficient gas generation potential as much as possible. [ABSTRACT FROM AUTHOR]

Matrix permeability is a key factor in determining long term gas production from shale reservoirs – requiring that it is determined under true reservoir conditions. We suggest a variable pressure gradient (VPG) protocol to measure shale matrix permeability using real reservoir fluids in powdered samples. The VPG method is described and a mathematical protocol for its analysis is developed. The first measures gas fractional production rate history under constant external pressure for each production stage and with a designated pressure gradient. The second establishes the mathematical protocol for analysis using pseudo-pressure to accommodate both the effect of gas pressure-dependent PVT parameters and desorption rate coefficient. The matrix permeability is determined by matching the solution of the model with the experimental data. The model fits the experimental data well when the fractional production is <0.75. Shale matrix permeability is calculated in the order of magnitude of 10 −7 –10 −6 md. Methane permeability decreases with a decrease in both average pore pressure and particle size of the individual component grains. Permeability considerably more sensitive to changes in desorption rate coefficient than flow regimes. Compared with current small pressure gradient (SPG) methods, the VPG method is considerably more applicable to actual gas production and reduces to the SPG method under simplified boundary conditions. Although some approximate treatments are used for establishing the VPG method and some flow mechanisms are not considered, this study still provides an information-rich technique to determine shale matrix permeability at conditions close to reality. [ABSTRACT FROM AUTHOR]

Laser Raman spectroscopy is used to assess the thermal maturity of organic matter in sedimentary rocks, particularly organic-rich mudstones. However, discrepancies exist between quantified Raman spectral parameters and maturity values obtained by vitrinite reflectance. This has prevented the adoption of a standard protocol for the determination of thermal maturity of organic matter (OM) by Raman spectroscopy. We have examined the factors influencing the Raman spectra obtained from low-maturity OM in potential shale gas reservoir rocks. The inconsistencies in Raman results obtained are due to three main factors that are critically evaluated: (1) different operational procedures, including experiment setup and spectral processing methods; (2) different methods of sample preparation; (3) the analysis of diverse types of OM. These factors are scrutinized to determine the sources of inconsistency and potential bias in Raman results, and guidance is offered on the development of robust and reproducible analytical protocols. We present two new Raman parameters for un-deconvolved spectra named the DA1/GA ratio (area ratio of 1100–1400 cm −1 /1550–1650 cm −1 ) and SSA (scaled spectrum area: sum of total area between 1100 and 1700 cm −1 ) that offer potential maturity proxies. An automated spreadsheet procedure is presented that processes raw Raman spectra and calculates several of the most commonly used Raman parameters, including the two new variables. [ABSTRACT FROM AUTHOR]

Two coal-to-shale sequences of late Middle Pennsylvanian (Asturian) age from the southern portion of the Eastern Interior (Illinois) Basin, USA were examined geochemically, petrographically and palynologically. The Springfield coal was found to be moderately low in ash yield and high in total sulfur content. Petrographically, the coal is high in vitrinite content and low in liptinite and inertinite. Palynologically, the bed is co-dominated by spores of arborescent lycopod and tree fern affinities. The examination of closely-spaced bench samples revealed vertical species variation within both of these plant groups. Lycospora micropapillata + L. orbicula , both of which were produced by Paralycopodites , are most abundant in basal coal benches, whereas Lycospora granulata , produced by Lepidophloios is the dominant arborescent lycopod spore throughout the rest of the bed. Thymospora pseudothiessenii is the dominant tree fern spore throughout most of the coal, with Laevigatosporites globosus becoming dominant in the top-most coal benches. The Herrin coal bed is also moderately low in ash yield and high in total sulfur content. Unlike the Springfield coal, it contains two distinct inorganic partings that have regional extent. The Herrin coal also has several coal benches with increased ash and sulfur that were not present in the Springfield coal bed. Petrographically, it is dominated by vitrinite, with the partings and high ash coal benches containing more inertinite, and liptinite. Palynologically, the Herrin coal is dominated by arborescent lycopod spores with subdominant tree fern spores. As with the Springfield coal, Lycospora micropapillata + L. orbicula are the dominant arborescent lycopod spores at the base of the coal, with Lycospora granulata dominating the rest of the bed. Granasporites medius , which was produced by Diaphorodendron and Synchysidendron , occurs more frequently in the Herrin coal bed, and are most abundant in, and in proximity to, the two inorganic partings. Tree fern spores are less abundant in the Herrin coal, and do not display any discernable vertical species variation. Collectively, both the Springfield and Herrin coal beds are interpreted to have formed in extensive planar, topogenous mires. Consistently saturated peat conditions throughout the development of both paleomires are indicated by the high vitrinite contents, and prevalence of arborescent lycopods. The deposition of widespread inorganic partings in the Herrin coal represents significant events in peat accumulation, with high ash coal benches representing smaller, more local events. Both of the coals are overlain by black, very organic-rich (avg. TOC ± 20%) marine shales. The Turner Mine Shale, which directly overlies the Springfield coal, has layers at the coal/shale contact with fairly abundant vitrinite, primarily in the form of vitrodetrinite, near the base of the shale, but the majority of the shale is dominated by the liptinite macerals bituminite, lamalginite and amorphinite. Micrinite is a major organic component of the shale. The Anna Shale, which directly overlies the Herrin coal, is similar in overall maceral composition, but contains less vitrinite, and more solid bitumen and micrinite. Trace element ratios (Ni/Co, V/Cr, V/V + Ni), indicative of paleoredox conditions, indicate that both shales were deposited under mainly dysoxic to suboxic/anoxic conditions. The shales are interpreted to represent a progressively rising water table, caused by an increase in eustatic sea levels. Vitrinite reflectance values in the shales are lower than corresponding values measured from the coal, indicating some degree of vitrinite suppression occurring in the Turner Mine and Anna Shales. [ABSTRACT FROM AUTHOR]

Micro-plugs of the Upper Devonian to Lower Mississippian Woodford Shale from the Ardmore Basin in southern Oklahoma were analyzed before and after hydrous pyrolysis (300, 320, 330, and 340 °C for 24 h) by using a combination of μ-FTIR, CP-Py-GC/MS, BIB-SEM-EDS techniques to investigate kerogen transformation and evolution of pore space. Tasmanites and Leiosphaeridia in Woodford Shale are abundant macerals characterized by relatively long, unbranched alkyl chains, with an additional carboxyl component, and a minor contribution of aromatic structures based on μ-FTIR spectra results. The aliphatic ν as CH 2 / ν as CH 3 ratios show almost no correlation with pyrolysis temperatures, except for a minor increase of the ratio for both samples after pyrolysis at 330 °C, which may be attributed to cracking of C-C bonds next to a tertiary carbon atom. A decreasing aliphaticity and increasing aromaticity for alginite with increasing pyrolysis temperature and thus thermal maturity is indicated by the reduction of aliphatic CH x stretching bands and increasing γCH/ νCH x ratios. The relative abundance of olefinic bonding (νC=C) decreases in alginite compared to aromatic hydrogen (γCH) with higher pyrolysis temperature, and thus formation of monoaromatic rings is indicated by the condensation ratios (γCH/ νC=C); similar observations have been made on natural maturation series. This is in line with the CP-Py-GC/MS results on whole kerogen showing an increase of aromatic structures over aliphatic pyrolysis products with increasing thermal maturities, though with some differences between the two samples investigated. The differences are probably related to higher alginite/bituminite ratios in one of the samples, which also contain more N-compounds. In contrast, the other sample enriched in bituminite contains more S-compounds. Both FTIR spectra and EDS results document a loss of carbonyl/carboxyl C=O functional groups and/or O content with thermal maturation. The hydrocarbon generation potential parameter "A-Factor" (νCH x / νCH x + νC=C), analyzed on alginite in this study, is rather consistent at different pyrolysis temperatures with a value of about 0.9 and with a slight tendency of higher values at higher pyrolysis temperatures. SEM observations show that there is no significant occurrence of microfractures in the initial samples and after pyrolysis at 300 °C, while microcracks and organic pores formed pore networks when pyrolysis temperature increased from 320 °C to 340 °C. Most of the newly generated cracks are parallel to the bedding. Mineral-filled Tasmanites cysts in Woodford Shale are silica-rich and may be related to the dissolution of siliceous tests (e.g., radiolarians). • High resolution SEM study on pyrolytic conversion of individual liptinite macerals • Functional groups variations in alginite after hydrous pyrolysis • Molecular building blocks of Woodford Shale kerogen before and after pyrolysis • SEM observations record development of microfractures and pores [ABSTRACT FROM AUTHOR]

The third member of the Paleogene Shahejie Formation (E s 3) in the Dongpu Depression, China, was studied to interpret its paleoenvironment through a series of trace element proxies, to reveal paleosalinity conditions, to elucidate on the hydrological conditions of the paleolake using carbon and oxygen stable isotopes, and to investigate the effects of paleoredox conditions on organic matter preservation. Most of the redox-sensitive proxies, such as U/Th, V/Cr, Ni/Co, U auth , (Cu + Mo)/Zn, Cu/Zn, Th/U, and V/Sc, indicate that the E s 3 was deposited under predominantly oxic and oxic/suboxic conditions, while V/(V + Ni) and δU and previous studies suggested that the formation was deposited under mainly anoxic conditions. Oxygen levels agreed with the trace element ratios and showed a decrease from the lower to the upper part of the E s 3 and an increase in paleoproductivity in the same direction. Salt rocks interbedded within the formation were shown to have overall lower oxygen levels than their neighboring organic-rich layers, black shale, and mudstone intervals, thus have likely altered the paleoredox proxies to oxygen consumption. Although Sr/Ba values point to a saline lake environment, the relative fluctuations seen suggest that the above ratio is not an appropriate indicator of paleosalinity in salt-bearing strata and that the variations in paleoredox conditions in the formation are not a function of paleosalinity. Based on the negative δ13C and δ18O stable isotopic values, it is inferred that the shales in the E s 3 were deposited in a hydrologically open lake environment. However, the presence of palynomorphs such as dinoflagellate cysts that are typically found in middle to outer neritic and open marine environments reinforces the assumption of a sea level transgression and inundation of the lake basin and mixing with freshwater algae and rare terrigenous phytoclasts such as cuticles, wood fragments, and suberin. The higher paleoproductivity and lower oxygen levels in the upper E s 3 have contributed to greater OM preservation conditions in the absence of any variations in salinity or freshwater influx. The study also demonstrates that many of the paleoredox proxies and thresholds established are not valid to properly characterize certain formations deposited in lacustrine lake paleoenvironments such as the Shahejie, thus their applicability in certain situations must be re-evaluated. [ABSTRACT FROM AUTHOR]

Igneous intrusion into organic-rich sedimentary rocks and coals has been suggested as a factor in the large-scale release of 13 C–depleted thermogenic CH 4 , which may have led to global warming and mass extinction events in the geologic past. If a significant release of 13 C–depleted thermogenic CH 4 results from the intrusion of coal or organic-rich rocks, then it should produce 13 C–enriched residual coal and dispersed organics in rocks adjacent to the intrusion due to the release of isotopically lighter CH 4 gas. A review of the literature suggests only minor changes in the δ 13 C org of coals adjacent to intrusions; however, a few studies have shown that changes in δ 13 C org in intruded shales may be slightly more pronounced. The current study further evaluates the geochemical, isotopic, and petrographic changes that result from contact metamorphism and specifically compares the intrusion of coal to that of an organic-rich shale collected from the same general vicinity. Data for two different transects of intruded Pennsylvanian coal (Danville (No. 7) Coal) and an intruded organic-rich shale in the southern part of the Illinois Basin are presented. Both transects show similar increases in mean vitrinite reflectance (R r ); reflectance increases from background levels of 0.66% to 4.40% in the Danville (No. 7) Coal and 0.71% to 4.78% in the organic-rich shale. In addition, both transects show the formation of isotropic coke, and even development of fine circular mosaic anisotropic coke structure at and near the contact with the intrusion, along with the visual loss of liptinites at higher reflectances. In the Danville Coal transect, volatile matter, N, H, S, and O decrease whereas fixed carbon, C, and ash increase approaching the intrusion. The coal shows a marked decrease in remaining hydrocarbon potential (S 2 ) and hydrogen index (HI) and an increase in T max (°C). Trends in most of the Rock-Eval parameters for the organic-rich shale are less clear due to variations in the amount of organic matter present, but a significant increase in thermal maturity (T max , 0 C) is observed. No systematic changes in δ 13 C occur in the No. 7 Coal transect as the intrusion is approached, with δ 13 C varying between − 25.4‰ and − 24.8‰. The organic-rich shale transect shows a minor 1.2‰ enrichment in δ 13 C (from − 25.2‰ to − 24.0‰) within 2 m of the intrusion. These isotopic shifts are not of a magnitude that would be expected if associated with a large-scale release of thermogenic CH 4 . In addition, no evidence exists in either transect for 13 C–depleted condensed gas or pyrolytic carbon at the intrusion contact that could have moderated the isotopic signature. These data agree with those reported previously that indicate no clear isotopic evidence for large-scale CH 4 generation due to rapid heating by igneous intrusion into coals or sedimentary rocks. [ABSTRACT FROM AUTHOR]

We present a novel approach to describe how micro-fracture closure, pore volume compressibility, and connectivity loss change intrinsic permeability of shale formations as a function of effective stress. Shale resources illustrate distinct characteristics, such as micro-scale pores (IUPAC definition), ultra-low permeability, and complex pore network system. Moreover, experimental results indicate that permeability reduction owing to increased effective stress in shale samples might be as large as two orders of magnitude. This significant reduction is often explained by micro-fracture closure while impact of pore connectivity loss is often neglected. Thus, we propose a novel model through which permeability reduction is described owing to combination of three main mechanisms: (1) micro crack closure (2) pore shrinkage and (3) connectivity loss due to bond breakage between interconnected pores. We use fractal and percolation theories and formulate a permeability model as a function of pore throat radius, porosity, pore size distribution, and average coordination number (average number of available/connected neighbor pores). The proposed model is validated using experimental data for 10 sandstone samples. Additionally, for selected shale samples, results of proposed model are compared with Katz-Thompson and Swanson methods. Furthermore, experimental data for two sandstone and two shale samples are utilized to evaluate connectivity reduction with effective stress. Using Walsh model, first we identified and isolated crack/fracture-dominated permeability region for shale samples and studied impact of pore shrinkage and connectivity loss as a function of effective stress for the remainder of the datasets. Results indicate that permeability values obtained from proposed model are consistent with experimental data for sandstone samples as well as predictions obtained from Katz-Thompson and Swanson methods for shale samples. Moreover, when effects of both pore shrinkage and connectivity loss are simultaneously analyzed, the results proved that connectivity loss (as expected) is insignificant in sandstone samples and that permeability reduction can be explained only by pore volume compressibility effects. However, in shale formations, impact of bond breakage and connectivity loss on permeability reduction is dominant. The results suggest that average coordination number can decrease as lower as 50% of the original value when effective stress exceeds 17,000 psi. The result of this study suggests that in shale formations permeability reduction should be corrected to account for micro-crack closure at early stage and for both pore compressibility and connectivity loss at late stage of production. This may well change the industry's predictions of the reservoir performance in unconventional shale plays. [ABSTRACT FROM AUTHOR]

During CO 2 geological storage, low porosity and permeability cap-rock can act as a structural trap, preventing CO 2 vertical migration to overlying fresh water aquifers or the surface. Clay and organic matter rich shales, fine-grained sandstones and mudstones often act as cap-rocks and may contain substantial sub-micron porosity. CO 2 -brine-rock interactions can open or close pore throats through dissolution, precipitation or migration of clay fines or grains. This could affect CO 2 migration if the porosity is accessible, with unchanging or decreasing accessible porosity favourable for trapping and integrity. Two cap-rock core samples, a clay and organic-rich mudstone and a more organic-lean feldspar-rich fine grained sandstone, from a well drilled for a CO 2 storage feasibility study in Australia were experimentally reacted with impure CO 2 (+ SO 2 , O 2 ) and low salinity brine at reservoir conditions. Mercury injection capillary pressure indicated that the majority of pores in both cores had pore throat radii ~ 5–150 nm with porosities of 5.5–8.4%. After reaction with impure CO 2 -brine the measured pore throats decreased in the clay-rich mudstone core. Dissolution and precipitation of carbonate and silicate minerals were observed during impure CO 2 reaction of both cores via changes in water chemistry. Scanning electron microscopy identified macroporosity in clays, mica and amorphous silica cements. After impure CO 2 -brine reaction, precipitation of barite, Fe-oxides, clays and gypsum was observed. Ion leaching from Fe-rich chlorite was also apparent, with clay structural collapse, and fines migration. Small-angle neutron scattering measured the fraction of total and non-accessible pores (~ 10–150 nm radii pores) before and after reaction. The fraction of pores that was accessible in both virgin cap-rocks had a decreasing trend to smaller pore size. The clay-rich cap-rock had a higher fraction of accessible pores (~ 0.9) at the smallest SANS measured pore size, than the feldspar rich fine-grained sandstone (~ 0.75). Both core samples showed a decrease in SANS accessible pores after impure CO 2 -water reaction at CO 2 storage conditions. The clay-rich cap-rock showed a more pronounced decrease. After impure CO 2 -brine reaction the fraction of accessible pores at the smallest pore size was ~ 0.85 in the clay-rich cap-rock and ~ 0.75 in the feldspar-rich fine-grained sandstone. Reactions during impure CO 2 -brine-rock reaction have the potential to close cap-rock pores, which is favourable for CO 2 storage integrity. [ABSTRACT FROM AUTHOR]

Sample polishing by argon ion beam is a widely used method for examining shale samples for inherent porosity characteristics; the high quality of these surfaces suggests that this technique may also be used for optical reflectance measurements to provide information about the thermal maturity of samples. Yet, the inevitable surface heating that this polishing method engenders has raised concerns that the measured reflectance properties are no longer those of the original sample. To explore the impact of ion milling on the maturity of shale samples as measured by vitrinite and solid bitumen reflectance, five different ion milling configurations were applied to a set of organic-rich New Albany Shale (Late Devonian-Early Mississippian) samples that range in maturity from immature to post-mature. Using two ion mill designs, edge milling vs planar milling, single and dual ion beams, variable acceleration voltages, and milling at room temperature vs samples cooled by liquid nitrogen, provided a wide range of beam heating scenarios. Reflectance of macerals was measured before and after ion milling to investigate whether and to what extent various ion-milling approaches change the reflectance values, and by extension the perceived thermal maturity of organic matter in these samples. Our results demonstrate that more aggressive milling methods, such as the use of multiple beams and higher acceleration voltages elevate reflectance values, and that this effect is most pronounced in immature samples and diminishes for samples of increasing original maturity. Specifically, for the two least mature samples, the most aggressive milling method (configuration D) increased reflectance of vitrinite from 0.48% to 0.58%, and from 0.58% to 0.74%. Increase of reflectance (perceived maturity) can be counteracted by reducing beam intensity (e.g., fewer beams, lower voltage) and cooling of samples with liquid nitrogen. The severity of heating artifacts depends partially on the ion mill design, and non-damaging settings must be determined experimentally for a given ion mill model. Because thermal alteration of organic matter typically involves the expulsion of volatiles, there is also a danger that ion beam heating of immature and oil window samples can skew the porosity characteristics of shale samples. Thus, determining non-damaging ion mill settings has the dual benefit of avoiding measuring false maturity levels and misleading porosity characteristics. [ABSTRACT FROM AUTHOR]

Measurement of matrix permeability is essential for predicting, evaluating, and modeling the performance of shale reservoirs. However, the repeatability and accuracy of these measurements can be questioned because procedures have not been standardized. As a result, permeability measurements from the same sample by different laboratories can vary by orders of magnitude. Microfracturing related to changes in stress during core retrieval and crushing during sample preparation is thought to be a significant source of error. Different interpretations of pressure decay curves could also account for inconsistent permeability values. The goals of this research were to analyze relationships among crushed particle size, microfractures, and matrix permeability, as well as to evaluate the ways in which pressure decay curves are interpreted and to determine the sample mass best suited for analysis. Crushed rock pressure-decay measurements of particles of different sizes were obtained using a shale matrix permeameter, and permeability was estimated by curve fitting using Core Laboratories software and by other methods that assess the geometry and evolution of pressure decay curves. Results indicate that the relationships between permeability and particle size vary considerably when determined by different methods. Analysis of pressure decay curves reveals three distinct segments. The early segment is characterized by hyperbolic decay, whereas the late segment is characterized by exponential decay. A third segment records a pseudo-steady state where pressure has declined to the extent that decay can no longer be characterized. Decay was measured for about 2000 s; most decay curves stabilize within 500 s, and data collected beyond 500 s are dominated by noise associated with the pseudo-steady state and are beyond the resolution of the apparatus used. Analysis of early hyperbolic curves yields permeability values one to two orders of magnitude greater than whole curve analysis. The hyperbolic pressure decay segment appears to be influenced by microfractures and other large pores near the surface of samples, whereas the late time segment and whole curve correlate more strongly with the microporous to nanoporous rock matrix. Also, permeability values derived from whole curve analysis are sensitive to measurement duration, and different values are obtained when permeability is determined from different time windows. SEM images of all particle sizes analyzed reveal microfractures with diameters ranging from 60 to 1020 nm, but no correlation was found between microfracture aperture and particle size. The optimal sample mass used in our shale permeameter is 50–100 g, which facilitates resolution of the major elements of the decay curve. Optimal particle sizes are between 1.0 and 1.4 mm. [ABSTRACT FROM AUTHOR]

The microscale characteristics of gray and black shale samples collected from two different locations of Singrauli coalfield, Madhya Pradesh, India were investigated using scratch tester and Raman stress mapping. The failure events were analyzed for the entire scratch track. The areas of critical point were identified based on the acoustic emission, tangential force measurement along with characterization methods Scanning Electron Microscopy (SEM) and Raman spectroscopy. The SEM studies at the critical points indicate the failure in black and gray shale are completely different. The critical points are analyzed by confocal Raman spectroscopy for measuring the Raman spectral shifts and Raman stress mapping. The Raman spectra of disordered D band are used for quantifying the stress in the entire scratch track. Micro scratch test performed in different directions along with critical point regions of black and gray shale is compared. Raman spectral shifts of D band are measured and compared for the strained regions. This reveals the 2D Raman imaging of black and gray shale as a proxy for characterizing the stress inversion. Correspondingly the Raman peak intensity ratios along with full width at half maximum (FWHM) were calculated for the critical regions. [ABSTRACT FROM AUTHOR]

Supercritical CH 4 and subcritical CO 2 and N 2 gas adsorption measurements, combined with scanning electron microscopy (SEM) have been used to determine CH 4 sorption capacity and pore characteristics for immature, mature and overmature shales from the Baltic Basin (Poland). Organic matter (OM) maturity exerts a dominant control on porosity evolution in micro- and mesoscale. In the Baltic Basin shales, the initial formation of micro- (< 2 nm) and mesopores (2–50 nm) occurs in the oil window (beginning of catagenesis, vitrinite reflectance R o ~ 0.5-0.9%) due to primary cracking of kerogen that left OM highly porous. The expelled liquid hydrocarbons turned into solid bitumen that is responsible for pore blocking and significant decrease in micro- and mesopore volume in late mature shales (middle catagenesis R o ~ 0.9–1.2%). Micro- and mesopores were regenerated in advanced catagenesis (R o ~ 1.4–1.9%) due to secondary cracking of OM. The micropore volume in the Baltic Basin shales is mostly controlled by the OM content while the influence of clay content is minor and masked by OM. The CH 4 adsorption in the Baltic Basin shales is predominantly controlled by OM micropore structure. The mesopore surface area and volume do not play an important role in CH 4 sorption. The proposed adsorbed CH 4 density equivalent (maximal absolute CH 4 adsorption divided by micropore volume), revealed that the CH 4 loading potential decreases in micropores with increasing maturity. The highest CH 4 loading potential is linked to OM before metagenesis (R o < 2%) where the adsorbed CH 4 density equivalent was found greater than the density of liquid CH 4 . This suggests that in addition to physical adsorption, absorption (dissolution) of CH 4 in OM occurs. When OM content was reduced by the treatment with NaOCl solution, CH 4 adsorption decreased significantly, suggesting that OM microstructure has much higher adsorption potential than that of clay microstructure. [ABSTRACT FROM AUTHOR]

Understanding the distribution of pores and organic matter with varying organic matter concentrations and maturity is essential to understanding fluid flow in shale systems. Analysis of samples with low, medium, and high total organic carbon (TOC) and varying maturities (gas-mature and oil-mature) enables the impact of both organic matter concentrations and thermal maturation on organic matter porosity to be examined. Three gas-mature samples of varying TOC (Lublin Basin) and one oil-mature sample (Baltic Basin), both with similar mineral compositions, were selected from the same formation. Samples were imaged in 3D over four orders of magnitudes (pixel sizes from 44 μm to 5 nm). A combination of X-ray computed tomography (XCT) and Focus Ion Beam Scanning Electron Microscopy (FIB-SEM) enabled the morphologic and topological characteristics of minerals, organic matter and pores to be imaged and quantified. In the studied samples, organic matter primarily has two geometries: lamellar masses (length: 1–100 μm, thickness: 0.5–2.0 μm) and discrete spheroidal particles (0.5–20.0 μm). Organic matter forms an inter-connected network where it exceeds a concentration between 6 and 18 wt%. Different pore types have different diameters and total pore volumes: inter-mineral pores (0.2 μm, 10–94%), organic interface pores (0.2 μm, 2–77%), intra-organic pores (0.05 μm, 1–40%) and intra-mineral pores (0.05 μm diameter, 1–2% of total porosity). The major pore system in the studied shales is composed of inter-mineral pores which occur between clay mineral grains. TOC concentration influences the total volume of organic matter-related pores while maturity controls the presence of intra-organic pores. The study improves the understanding of the relationship of organic matter concentrations, maturity and pore systems in shales. This study characterises porosity and organic matter distributions in 3D; it also improves the understanding of the relationship of organic matter concentrations, maturity and pore systems in shales. [ABSTRACT FROM AUTHOR]

This paper adopts and improves the existing workflows for integrated production data analysis. Clarkson (2013) presented an integrated production data analysis workflow through incorporating existing models and methodologies. Despite great achievements, some additional improvements are required to address the complexities associated with reservoir/fluid properties in shale plays. Some of the improvements are as follows. A new iterative algorithm is introduced toward integrated evaluation, prediction, and optimization of production in shale plays; the production contribution from unstimulated parts of the matrix (outside SRV) is considered; a new multi-phase productivity index is proposed; a new mechanistic formulation is presented to describe Dynamic-Drainage-Volume (DDV) for both early transient-linear flow and late compound-linear flow regime; a new pressure-saturation relation is established through relating fluid properties to production history. Moreover, geomechanics effects are coupled into material-balance model by introducing the pressure-dependent rock and fluid properties. The optimization of fracture and well spacing is achieved in Niobrara shale oil. [ABSTRACT FROM AUTHOR]

Thermal maturity assessment in pre-Devonian shales is challenging due to the absence of vitrinite macerals that form the basis for vitrinite reflectance petrography, the most-widely used technique for organic maturity assessment. This paper presents an integrated analysis of thermal maturity on the basis of alternative spectroscopic and geochemical techniques in lieu of conventional organic petrography, applied in four drilled wells in the pre-Devonian (Silurian) Qusaiba Member of the Qalibah Formation in northwestern Saudi Arabia. The techniques comprise both bulk sample (Rock-Eval pyrolysis, infrared and Raman spectroscopy), and kerogen isolate analysis (elemental, density, surface area, and X-ray absorption near edge structure), with each method calibrated to the vitrinite reflectance scale. Rock-Eval pyrolysis, a common alternative to vitrinite reflectance measurements, provided unreliable maturity estimates in the majority of samples because of low S2 signal. In contrast, the other techniques defined a consistent and narrow maturity range within each well, and revealed a wide range of maturity between the wells. On the basis of the spectroscopic and geochemical results, equivalent vitrinite reflectance for the Qusaiba Member in northwestern Saudi Arabia ranges from at least 0.9 ± 0.1 to 2.1 ± 0.2%Ro, demonstrating significant variation in its maturation history. The integrated assessment of maturity across multiple wells provides data that can be used to construct maturity maps for oilfield exploration and appraisal. More generally, the methods and calibrations for thermal maturity presented here can be used to establish vitrinite-reflectance-equivalent maturities in shales as a complement to or especially in the absence of conventional maturity estimates. [ABSTRACT FROM AUTHOR]

Characteristics of water film thickness and stability within nanopores are topics of great interest for evaluation of initial fluid storage in unconventional reservoirs. Although related researches with thin film on flat substrates have been carefully and extensively considered, the thickness and stability of liquid films affected by nanoscale confinement in nanostructured materials, such as clay minerals and tight rocks, have raised lots of questions. In this work, an approach by considering fluid/pore-wall interactions (surface forces) was developed to describe the phase behavior of thin water film transition into liquid condensation. The calculated results reveal that the instability mechanisms of adsorbed films differs inside slits and capillaries. In slit pores, the coalescence of flat wetting films forms under the action of attractive forces by opposite slit surfaces. Whereas in capillaries, collapse of curved wetting films occurs due to the integrative action of surface force and cylindrical capillary force. Due to the additional capillary action, the total surface interactions inside capillaries are higher than that inside silts, which leads to an easier condensation and thicker film thickness in capillaries. Meanwhile, the phase behavior of adsorbed water film within nanoporous montmorillonite and shale were investigated by water vapor (H 2 O) adsorption isotherms. Specially, the water distribution characteristics inside single nanopore rather than the whole porous media were also investigated based on the difference of pore size distribution (PSD) between dry and moist samples, and these PSD information was obtained by low temperature (77 K) nitrogen (N 2 ) sorption analysis. Our experimental results directly demonstrated the evidence of water condensation in hydrophilic clay samples, e.g., pores < 6–7 nm would be totally blocked by capillary water. However, a “partial condensation” phenomenon was found in shale samples, e.g., the shale nanopores could not been entirely filled by water even under a high-moisture condition (RH = 0.98), which was mainly caused by hydrophobic repulsion of organic minerals. This surface repulsion could prevent water from condensing and likely result in a monolayer water film adsorbed inside these hydrophobic organic nanopores, e.g. graphite. Therefore, in an actual shale system with initial moisture, the storage of water inside organic pores can be neglected while these inorganic micropores blocked by condensate may be unavailable for gas storage or transport. [ABSTRACT FROM AUTHOR]

In shale gas plays, both the permeability and diffusion coefficient are indispensible parameters to reservoir assessment and production forecast. Unlike previous works which measured the two parameters individually, this paper first proposed an integrated method of measuring the gas permeability and diffusion coefficient simultaneously with a single pressure decay curve. The experiments were conducted through one-chamber pressure decay tests (PDT) with shale core plugs under stressful conditions, simplifying the apparatus and time saving. According to the gas transport mechanisms, the whole gas flow in shale plugs was divided into three stages: viscous and slip flow stage (stage I ), non-surface diffusion stage (stage II ), and surface diffusion stage (stage III ). Then using the linear permeability and bidisperse diffusion models, the permeability was calculated to be on the order of 10 − 5 mD, and the effective diffusion coefficients ( D / r 2 ) of stages II and III were about 10 − 5 s − 1 and 10 − 7 s − 1 , respectively, which got well agreements with the existed methods. Given that the multiple gas transport stages in shale are actually interacted and coupled with each other, the integrated measuring values in this paper may be more representative. [ABSTRACT FROM AUTHOR]

This study examines the influence of analytical particle size on the surface area and mesopore and micropore volume data obtained from low-pressure N 2 and CO 2 adsorption analyses in response to the crushing of coal and shale. Pennsylvanian high-volatile bituminous coal (R o ~ 0.57%) and Devonian to Lower Mississippian low-maturity (R o ~ 0.57%) and high-maturity (R o ~ 1.30%) shales from the Illinois Basin were progressively crushed from chunks (~ 7 mm) to 4 mesh (< 4.78 mm), 7 mesh (< 2.83 mm), 18 mesh (< 1 mm), 30 mesh (0.595 mm), 60 mesh (< 0.250 mm), 200 mesh (< 0.074 mm), and 230 mesh (< 0.063 mm), and, subsequently, low-pressure N 2 and CO 2 adsorption analyses were performed on all the grain size fractions. Our results demonstrate that the values of both surface area and specific mesopore and micropore change with progressive crushing. For example, BET surface area of coal shows a steady increase from 2 m 2 /g in the 4 mesh fraction to 4.7 m 2 /g in the 200 mesh fraction. For comparable size ranges, BET surface area changes from 0.15 to 7.82 m 2 /g in the low-maturity shale, and from 0.02 to 6.26 m 2 /g in the high-maturity shale. Changes in mesoporosity and microporosity parameters indicate that the coarsest fractions (4 mesh and larger) are not suitable for low-pressure adsorption analysis; the values are very low and not reproducible dominantly because of equilibration problems. Our results demonstrate that the 60 mesh fraction for coal and the 200 mesh fraction for shales seem to be optimal and the most practical sizes for performing low-pressure N 2 and CO 2 adsorption analysis; these analytical particle sizes yield results closest to the “real” values, unbiased by disequilibrium. [ABSTRACT FROM AUTHOR]

The Jude-1 well is located in the central part of the Danish Central Graben, North Sea, and was drilled into immature black shales of the Upper Jurassic–lowermost Farsund Formation, a world-class marine source rock. The well was drilled with oil-based drilling mud (OBM). The lithofacies consists of argillaceous shale, calcareous shale and dolomite stringers as confirmed by cuttings and core. A core was taken in the upper part of the formation at the beginning of a ‘hot’ argillaceous shale interval characterized by elevated TOC and HI values. Cuttings and core samples were investigated to unravel kerogen composition, source rock quality and the contamination effect of OBM on organic geochemical analyses. The organic facies of the source rocks corresponds to Type II kerogen or Organofacies B ( sensu Pepper and Corvi, 1995). Considerable fluctuations in HI values through the Farsund Formation reflect pronounced variations in source rock quality, although a faint lamination of the shales and overall high TOC contents testify to prevailing oxygen-deficient depositional conditions preventing significant bioturbation and reworking of the sediment and organic matter. Petrography of core samples reveals a relatively homogenous sapropelic kerogen composition dominated by a groundmass of yellowish fluorescing amorphous organic matter and liptodetrinite intimately associated with the mineral matrix. Telalginite is less abundant, but Tasmanites - and in particular Leiosphaerida -type telalginites were observed. Minor but varying amounts of detrital terrigenous macerals suggest a considerable distance to land areas and thus limited supply of land plant-derived organic matter. The argillaceous shale lithofacies generally is more oil-prone and organic-rich than the more gas-prone calcareous shale facies. The uppermost section includes the ‘hot’ argillaceous shales, which together with two deeper argillaceous shale intervals are highly organic-rich and oil-prone. Average TOC of the ‘hot’ argillaceous shales is ~ 7 wt% and HI reaches > 500 mg HC/g TOC. The total Ultimate Expulsion Potential (UEP) of the over 853 m (2799 ft) thick Farsund Formation is ~ 142 mmboe/km 2 . Results from non-contaminated samples are thus consistent with the Farsund Formation being a world-class highly oil-prone marine source rock. The predicted oil composition corresponds to ‘paraffinic low wax oils’. The adverse effect of OBM contamination on geochemical analyses is demonstrated by Rock-Eval data and measured bulk kinetics of contaminated core samples. The measured kinetics has a considerable proportion of low activation energies related to OBM contamination which is also supported by high Production Indices. Further, gas chromatograms of the saturated fraction of extracts from contaminated cores clearly show evidence of OBM in the nC 11 –nC 14 range. Rock-Eval S 2 peaks have a ‘shoulder’ showing that the low E a -peaks result from carry over from the S 1 peak, caused by the OBM contamination. As a consequence Hydrogen Index values are increased. [ABSTRACT FROM AUTHOR]

This study presents a robust correlation between Raman spectroscopy signal (expressed as the Raman band separation) and thermal maturity obtained by the vitrinite reflectance technique. The organic-rich mudstones used to build this correlation originate from a variety of paleo-marine sedimentary basins. The resulting correlation enables thermal maturity of kerogen expressed as vitrinite reflectance equivalent to be estimated in unknown formation samples using Raman spectroscopy. Raman spectroscopy can thus be used for determination of maturation windows (immature, oil, wet gas, or dry gas). Moreover, different to other Raman measurements that are performed on isolated kerogen or on polished surfaces of drill core and cutting fragments, the technique here is executed directly on fragments with minimal preparation, making it potentially applicable for wellsite maturity estimations. It is further shown that differences in the Raman analysis of kerogen seen among different published studies can be ascribed in part to the use of different Raman laser wavelengths. Taking wavelength dependence into account, the maturity determination of organic-rich mudstones by Raman spectroscopy may be developed into a generalized method, independent of the instrumental setup. [ABSTRACT FROM AUTHOR]