Solid Bitumen Research Articles

Effect of solid bitumen on pore structure of ultra-deep carbonate reservoir and its logging calculation method

An amount of highly evolved bitumen has been discovered in carbonate reservoirs during ultra-deep oil and gas exploration. This bitumen damages the pore structure and is difficult to dissolve using chemical reagents. To address the gap in studying highly evolved bitumen’s impact on carbonate reservoirs. This study utilized samples from the second member of the Dengying Formation (referred to as Deng 2) in Sichuan Basin. Using thin-section observation, and full-diameter CT scanning, were employed to establish two digital models: with bitumen and without. The study aims to observe bitumen distribution characteristics, compare physical properties and pore structures of two digital cores, clarify bitumen content and its impact on the reservoir, and establish a regression equation. The results indicate: (1) Bitumen in Deng 2 exhibits three states: semi-filled, fully filled, and combined cementation; (2) Properties of the bitumen-containing model decline, with significant reductions in pore and throat numbers. Bitumen primarily occupies large-pore spaces with high coordination numbers and blocks large-radius, long-throat spaces; (3) A bitumen calculation model was established using digital core analysis and well logging parameters, demonstrating good applicability. In conclusion, this approach offers guidance for studying the impact of bitumen on ultra-deep reservoirs and quantitative well logging analysis.

Vitrinite Reflectance Suppression Revisited

Vitrinite Reflectance Suppression Revisited

Sources of natural gas in the Middle-Permian carbonate succession in the central-northern Sichuan Basin, Southwest China

Natural gas-source correlation is a challenging aspect of natural gas exploration in deep strata. The Middle-Permian carbonate succession in the Sichuan Basin, southwest China, particularly in the Maokou Formation, is a hotspot for natural gas exploration. However, determining the natural gas source in the Maokou Formation is challenging because of the high maturity and complexity of potential source rocks. In this study, we analyzed the genesis and sources of natural gas in the central-northern Sichuan Basin while considering the geological conditions and systematically utilizing the gas components, stable and rare-gas isotopes, and solid bitumen biomarkers. The results indicate that (1) the natural gas in the northern Sichuan Basin comprises a mixture originating from the source rocks of the Maokou and Wujiaping formations; (2) the Qiongzhusi Formation is the major source of natural gas in the north slope (and the Maokou Formation source rock could be used as an important supplement); (3) the natural gas in the Moxi-Longnvsi structure comprises a mixture originating from the source rocks of the Qiongzhusi and Maokou formations. From south to north and west to east, the major source rocks of the gas reservoirs changed from belonging to the Qiongzhusi Formation to the Maokou and Wujiaping formations. This study is the first to combine multiple geochemical methods and consider different geological settings to identify the gas source of a deep carbonate gas reservoir. Our study provides a reliable method for determining the natural gas-source correlation of gas reservoirs that contain highly mature and complex gas sources.

Determination of multistage oil charge processes in the Ediacaran Dengying gas reservoirs of the southwestern Sichuan basin, SW China

The Sichuan Basin has experienced multi periods of tectonic uplift event, accompanied with multiple hydrocarbon accumulation and phase transitions processes in the deep and ultra-deep reservoirs. The formation of paleo-oil reservoir plays an important role in the distribution of present-day gas fields, yet many records of early oil reservoirs have been destroyed. A series of methods including, petrography, cathodoluminescence, fluid inclusion, in-situ U–Pb geochronology, and basin modeling, were used to determine the multistage oil charge process in the Ediacaran Dengying Formation of the Weiyuan area, SW Sichuan Basin. The lace-like dolomite lamination and three stages of dolomite cement were petrographically, and geochronologically distinguished in the Dengying Formation, dated at c. 542 Ma, 486–482 Ma, 410 Ma, and 270 Ma, respectively. Three stages of bitumen in the Dengying reservoir indicated three episodes of oil charge. The first and second oil-charging events occurred at 500–486 Ma and 410–400 Ma, by combining the modeled timing of oil generation with mineral ages of the two generations before and after the solid bitumen. The modification of the Weiyuan paleo-oil pool occurred during the Caledonian tectonic uplift, after the second oil-charging event. The timing of the third oil charge was at 270–230 Ma, according to the Th value of aqueous inclusions coeval with secondary bitumen inclusions in the stage 3 dolomite cement (CD-3), close to the timing of main oil generation for the Lower Cambrian source rocks. The first oil charge may be a contribution from the Doushantuo source rock, and the Lower Cambrian source rocks provide the major contribution for the third oil charge. This research reveals the timing of multistage oil charging events in the southwest Sichuan basin, and provides a further method for determining the timing of oil charge in multi-cyclonic composite basins.

Organic Petrologic Characterization and Paleoenvironmental Analysis of Permian Shale in Northeast Sichuan Province, China

The Permian shale in Northeast Sichuan is an important shale oil and gas resource potential area, and the study of its organic matter characteristics and paleoenvironmental analysis is of great significance for revealing the shale oil and gas formation mechanism and resource evaluation. In this study, the organic matter of Permian shales in northeast Sichuan was carefully studied based on various analytical tools, such as petrology, laser Raman, microscopy, and principal trace elements, and the paleoenvironmental parameters of the shales were comprehensively analysed. A detailed study of the organic matter characteristics of Permian shales in northeast Sichuan reveals important features such as organic matter fractions, structural characteristics, maturity and sources. The results show that the organic matter of the shale consists mainly of solid bitumen, putrescine group, specular group and multicellular planktonic algae. Petrological observations and laser Raman analyses indicate a high maturity of the organic matter and a high content of organic carbon (TOC), showing good hydrocarbon potential. In this study, we reconstructed the palaeoenvironmental parameters and inferred the palaeoenvironmental evolution through palaeoenvironmental analyses of Permian shales in northeast Sichuan. The results of the comprehensive multi-indicator study show that the type of palaeoenvironment at the time of shale deposition was mainly an anoxic-reducing environment, and the depositional conditions were favourable to the enrichment and preservation of organic matter. In summary, the organic matter characteristics and paleoenvironmental analyses of the Permian shales in Northeast Sichuan provide important geological background information for an in-depth understanding of the formation mechanism, exploration potential and development prospect of shale hydrocarbons in this area. The results of this study can provide a scientific basis for the evaluation and development of shale oil and gas resources in this area, which is of great significance to geologists and the energy industry.

Fluid characterization of oil and gas fields: implications for fault and top seal integrity assessment

Integrity of fault and top seal is a key factor that affects hydrocarbon fluid phase distribution in the subsurface. Mapping fluid property distribution can therefore provide important tools towards assessing seal integrity and trapping mechanisms – two of the most critical elements in petroleum systems analysis towards optimzing exploration and development strategies. This is best achieved by proper fluid characterization that integrates fluid geochemistry and pressure–volume–temperature (PVT) data to identify equilibrated and disequilibrated fluid gradients. Fields from Paleozoic and Mesozoic basins in the Arabian Peninsula at different stages of delineation, appraisal, development and management are discussed as examples to demonstrate the role of fluid characterization in aiding the evaluation of top, lateral and fault seal integrity, and in providing insights into the sealing and buffering effects of reservoir heterogeneity on trapping mechanism, fluid distribution and flow capacity. Examples discussed include (1) reservoir heterogeneity controlling fluid distribution and trapping mechanisms in two neighbouring gas fields, (2) geochemical evidence for a lateral seal separating gas condensate region from oil discovered during field development, (3) solid reservoir bitumen atop a giant gas field, (4) selective gas leakage through anhydrite seal, and (5) geochemical evidence for fault-controlled reservoir compartmentalization rather than a hydrodynamically tilted fluid contact in a field at an appraisal stage where PVT data are limited or inconclusive. Put in structural context, seal-related interpretations of the fluid data are aligned with observations from seismic and geological data on the existence of faults with favourable orientations or facies changes. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

Solid bitumen as an indicator of petroleum migration, thermal maturity, and contact metamorphism: A case study in the Barrandian Basin (Silurian - Devonian), Czech Republic

Silurian and Devonian marine shales and limestones of the Barrandian Basin host abundant black solid, non-fluorescing bitumens that fill tectonic fractures and veins, and occlude fossil moulds and diagenetic concretions. Solid bitumen, interpreted as thermally degraded petroleum, entered the rocks during several successive episodes of fracture-bound petroleum migration that occurred during deeper burial of the strata. Regional distribution of bitumen reflectance values that range between ∼0.9–2.3% Rr, correlate with variations of its FT-IR and Raman spectroscopic characteristics and aromatic hydrocarbon composition, and collectively evidence the maturity trend increasing across the basin from the southwest to the northeast. The reflectance of chitinozoans and graptolites (∼0.8–1.9% Rr) in the country rocks and homogenization temperatures of hydrocarbon fluid inclusions document palaeotemperatures ranging between ∼90–150 °C, characteristic of the oil window zone grading into the gas/condensate zone. Although in a basin-wide perspective the averaged values of solid bitumen and zooclast optical reflectance converge and indicate the same northeastern-increasing regional diagenetic trend, solid bitumen reflectance values vary considerably at individual localities and even within some bitumen samples. The wide scatter of optical reflectance values and the heterogeneity of optical properties, which were attributed to the presence of multiple source rocks in the basin, the variable lithology of bitumen host rocks, or other variables, hamper the use of solid bitumen as a simple alternative to zooclast/vitrinite reflectance palaeothermometers in a given basin. On the other hand, the highly anisotropic domain and the mesophase “coking” textures of the solid bitumen that were recognized in the NE part of the basin provide unique evidence on an anomalous, hitherto unrecognized, geologically short-lasting thermal event that affected the Palaeozoic rocks. A line of indirect evidence suggests that the coking of the bitumen was caused by a cryptic intrusion, possibly a concealed branch of the Central Bohemian Pluton, which intruded into the strata during the Variscan orogeny. More rarely occurring semi-solid, vividly yellow fluorescing waxy bitumen, that postdates solid bitumen in some fractures and voids, does not reveal a regional thermal maturation trend. It precipitated from relict waxy oils that migrated through the strata during a post-Neogene uplift of the Barrandian region.

A complex case of thermal maturity assessment in a terrigenous sedimentary system: The Northwestern Black Sea basin

An integrated approach combining fluorescence spectrometry, pyrolysis geochemistry, and dispersed organic matter (DOM) maceral analysis has been used to determine the thermal maturity of Oligocene source rocks in two neighboring offshore wells within the complex deep-sea system of the Northwestern Black Sea. The samples contain predominantly immature Type II kerogen, including a mixture of marine liptinite (alginite, liptodetrinite), degraded liptinite, primary vitrinite, and reworked vitrinitic macerals. The occurrence of several vitrinite reflectance (VRo) populations in the samples is attributed to a high influx of reworked vitrinite transported to the marine basin from multiple terrestrial sources with diverse degrees of degradation. The presence of multiple VRo populations complicates the application of VRo for determining the thermal maturity of the organic matter. Further, the VRo measurements on the primary vitrinite population show only a subtle increasing trend with depth. A significantly improved thermal maturity resolution was obtained using the red to green quotient (R/G). R/G was measured on the autochthonous unicellular Tasmanites-type alginite under UV-excitation. In contrast to VRo the results show a significant correlation between increasing R/G values with increasing depth. This indicates that the R/G quotient is a better maturity proxy for the studied low maturity marine system with a large influx of sediments. The beginning of the downward declining trend in the temporal variation of liptinite is regarded as the onset of catagenesis. This occurs at a burial depth of 2.5 km and a R/G value of 0.50, corresponding to a VRo equivalent (VRo Eq) of 0.44%. At a burial depth of 3.2 km and a R/G value of 0.57 (VRo Eq = 0.57%), the onset of the oil window is marked by an increase in the amount of solid bitumen (initial oil solid bitumen). The observed alterations in maceral composition with burial depth align with the thermal maturity of the wells. However, the data suggest that the thermal evolution of the organic matter is out of sync with the surrounding formation temperature, possibly due to rapid burial induced by a high sedimentation rate.

Origin of organic matter pore heterogeneity in oil mature Triassic Chang-7 mudstones, Ordos Basin, China

Organic matter (OM)-hosted pores play a crucial role in hydrocarbon storage and migration in unconventional shale oil and gas systems. An accurate identification of different OM compositions is critical to understanding the origin of heterogeneity in OM-hosted pore development, which remains challenging due to the lack of apparent intrinsic connection between them. This study correlates light-electron-Raman spectroscopy to investigate various OM maceral types and their molecular structures with respect to the pore characteristics in an oil mature Triassic Chang-7 lacustrine mudstone from the Ordos Basin, China. Moreover, the occurrence and distribution of soluble bitumen and its effect on OM-hosted pore development were directly characterized by comparison of a stitched large SEM image mosaic (∼1 mm2) before and after organic solvent extraction. Results show that terrestrial OM including inertinite and vitrinite fragments display well-preserved biological structure and high reflectance intensity in light microscopy. They often are nonporous under SEM, and have no change before and after solvent extraction. Solid bitumen is the predominant maceral of the examined mudstone, and shows two general populations: 1) nonporous or weakly porous solid bitumen (SB1) that often occurs in large-sized and structured accumulation; 2) porous solid bitumen (SB2) that is filled or dispersed in mineral matrix. After extraction, SB2 was completely removed and have a noticeable recovery of pores, while SB1 changed slightly. The heterogenous pore characteristics can be related to the varying OM molecular structure which shows a decreasing trend of aromaticity in the order of terrestrial macerals, SB1, and SB2 as indicated by Raman parameters. A relatively higher pore abundance in SB2 may be attributed to chromatographic fractionation which led to more mobile and compliant components of SB2.

Hydrocarbon generation potential of Campano-Maastrichtian to Paleogene shales in the Benin Flank of the Anambra Basin, SW Nigeria

The hydrocarbon generation potential of the Campano-Maastrichtian to Paleogene shales from the Benin Flank (located in SW Nigeria) of the Anambra Basin, has been previously investigated mostly by studying outcrops and by relatively few subsurface data-based studies. Thus, it is expedient undertaking an assessment of the hydrocarbon generation potential of this frontier area from subsurface samples. Campano-Maastrichtian to Paleogene shale samples obtained from Egoli-1 borehole in the Benin Flank of the Anambra Basin are studied by means of HAWK programmed pyrolysis, organic petrography, and mineralogy (XRD), with the aim to explore the petroleum-generating potential and the thermal maturity. The obtained results display a significant variation of the TOC content ranging from very low (<0.5%) to significant (>5%), indicating poor to excellent oil potential based on S2 values under the condition, of course, the studied formations reached the oil window. The shales of the Nsukka and Imo Formations display lower petroleum-generating potential than these of the Mamu Formation. All the studied samples are dominated by gas-prone (type III) and inert (type IV) kerogens, with few displaying mixed II/III (oil- and gas-prone). The organic-petrography observations support partly the results of the HAWK programmed pyrolysis, as they reveal an organic-richer Mamu Formation in comparison to the Nsukka and Imo Formations; huminite/vitrinite particles (both indigenous and recycled) along with variable contents of liptinite (mostly alginite and bituminite) and inertinite macerals (mostly inertodetrinite) are hosted in the shales. The latter display a typical composition for fine-grained clastic sediments; mostly kaolinite, illite/montmorillonite, quartz, and subordinately, anatase. In terms of thermal maturity, huminite/vitrinite reflectance data points to immature stage; however, the occurrence of solid bitumens, displaying equivalent vitrinite reflectance values within the oil window, points to an active petroleum system in sequences deeper than the examined ones.

Spectrum of Nanopores, Micropores, and Associated Pore Networks and their Origins in Carbonate Strata

Nano- and micropores (defined as pores less than 10 μm in diameter) are common in carbonate reservoirs as either the sole pore type or in combination (dual pore networks) with matrix macropores and fracture pores. These very fine-scale pores form in limestones and dolostones and in associated organic matter (e.g., solid bitumen). Limestone nano- and micropores occur between crystals that are commonly less than 1 to 9 μm in size in limestone, but in dolostone the crystal size can be much larger. Limestone nano- and micropores commonly originate in three ways, although some inherited original nano- and micropores between mud components are preserved. First, in original lime-mud mixtures of aragonite, Mg–calcite, and calcite, the origin is both depositional and diagenetic as aragonite dissolves and reprecipitates because microrhombic calcite, Mg–calcite transforms to microrhombic calcite, and original calcite grains are generally unaffected. Second, in chalks, nano-and micropores are related to the original depositional fabric as interparticle pores between coccoliths and other pelagic allochems. Third, in sediment originally composed of Mg–calcite-rich allochems, nano-and micropores form by transformation of unstable Mg–calcite allochems to microrhombic calcite. In dolostones, nano-and micropores are associated with extensive dolomitization and the nearly complete occlusion of pores (overdolomitization), whereas another diagenetic origin in dolostones is differential dolomitization at the grain scale. Also, in some dolostones, nano- to micropores pores are inherited from precursor microporous limestone. A late process of nano- and micropore formation is subaerial weathering of both limestones and dolostones resulting in pulverulite. This form of micropores is commonly developed at unconformities as enhanced porosity zones. Organic-matter nano- and micropores in solid bitumen, common in thermally mature organic-rich argillaceous limestone, can also be present in coarser-grained carbonates in which solid-bitumen occurs within macropores. Only in organic-rich limestones do organic-matter pores have potential to form an effective pore system. Because nano- and micropores have multiple origins, their lateral and vertical distribution reflects or depends on their origin; therefore, one must not only describe nano- and micropores, but also define their origin. Recognition of nano- and micropores is important because they form tight carbonate reservoirs and have significant effects on permeability, porosity perseveration with burial, hydrocarbon saturation, hydrocarbon recovery, sweep efficiency, storage, and reserve estimations. Not recognizing nano- and micropore networks can lead to errors relative to the aforementioned measurements and as a result, economic evaluations may be invalid.

РАСПРЕДЕЛЕНИЕ И ГЕНЕЗИС УГЛЕВОДОРОДНЫХ ГАЗОВ ДОННЫХ ОТЛОЖЕНИЙ ЛАПТЕВО-СИБИРОМОРСКОЙ ЗОНЫ ВОСТОЧНО-АРКТИЧЕСКОГО ШЕЛЬФА

Gases from bottom sediments of the Laptev–Siberian Sea zone contain methane (up to 8.3047 cm3/kg) and its homologues (down to and including pentane) totaling 0.0259 cm3/kg. The established values of the carbon isotope composition of methane (δ13С), the molecular weight of the hydrocarbon fraction, the weight concentrations of С1–С5 hydrocarbons and their ratios, the «wetness» and «transformation» coefficients of the hydrocarbons fraction, indicate the presence of various syngenetic and epigenetic gases in bottom sediments. Potential gas sources are modern sediments, peat, coal, gas and gas hydrate? deposits, solid bitumen, igneous rocks, and inferred oil and gas accumulations. It has been established that the distribution of hydrocarbon gases in sediments vertically and horizontally depends on the influence of a complex of geological factors – fold and fault tectonics, magmatism and seismic activity in the region, coal, oil and gas potential and bituminosity, organic saturation and lithological composition, hydrogeological, geocryological, and other conditions for accumulation of gases or their degassing.

Pore Structure and Fractal Characteristics of the Middle and Upper Permian Dalong and Gufeng Shale Reservoirs, Western Hubei Province, South China

The Middle and Upper Permian Dalong and Gufeng Formations in South China have recently been considered as potential gas-producing shales. However, their pore structure characteristics remain poorly understood. To investigate the pore structure and fractal characteristics of the pores in these two formations, a suite of shale samples from the Dalong and Gufeng Formations in the western Hubei Province, South China were analyzed by multiple techniques, namely, TOC content, X-ray diffraction (XRD) mineralogy analysis, optical microscopy observations, major elemental analysis, field emission-scanning electron microscopy (FE-SEM), and low-pressure gas adsorption measurements (N2 and CO2). The identified major shale lithofacies include siliceous mudstone, carbonaceous mudstone, argillaceous-siliceous mixed mudstone, and calcareous-siliceous mixed mudstone. SEM images show that the dominant pore types include the pores between brittle minerals, slit-shaped pores between clay sheets, and secondary organic matter (OM) pores within solid bitumen. The pore size distribution is dominated by micropores and mesopores (&lt;30 nm), which are the major contributors to total pore volume and surface area for the Dalong and Gufeng Formations. Based on the Frenkel–Halsey–Hill (FHH) method, fractal dimensions (D1, D2) calculated from the nitrogen adsorption data have a range of from 2.489 to 2.772 (D1) and from 2.658 to 2.963 (D2), and are higher in the Gufeng Formation (average TOC = 8.3 wt.%) due to a higher TOC content comparing to the Dalong Formation (average TOC = 6.2 wt.%). The pore development and fractal characteristics are primarily controlled by organic matter (OM), carbonate minerals, and clay minerals for both the Dalong and Gufeng Formations. Shale samples with high TOC content, low carbonate content, and high clay content tend to develop more heterogeneous micropores and mesopores, which is ascribed to the generation of clay-related and OM-hosted pores, along with the destruction of primary pores by pore-filling carbonate cements.

Organic petrology and geochemistry of the Devonian-Mississippian bakken formation, Williston Basin, North Dakota

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 (SBRo) 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 CO2/g TOC), and Ro (0.60–1.03%) calculated from Tmax. Plots of HI vs. OI and HI vs. Tmax (°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 (Ro = 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 (Ro = 0.60–0.83%) compared to more dispersed SB (67–86%) and less alginite and bituminite (<1%) in the more thermally mature samples (Ro = 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 SBRo to vitrinite reflectance equivalence (VRE). 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% SBRo) and VRE 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 Ro, whereas VRE based on the D–M Woodford Shale equation of Cardott and Comer (2021) does not. This suggests the importance of applying VRE equations from similar formations both in terms of thermal history, as well as kerogen type and age. Results from SBRo, Rock-Eval Ro, VRE, and observations of alginite fluorescence indicate that samples from the current study range from the early oil window into the condensate, wet gas zone.

Identification, evolution and geological indications of solid bitumen in shales: A case study of the first member of Cretaceous Qingshankou Formation in Songliao Basin, NE China

On the basis of sorting out current understanding of solid bitumen (SB) in shales and taking organic-rich shales in the first member of the Cretaceous Qingshankou Formation in the Songliao Basin as an example, the definition, classification, occurrence and evolution path of SB are systemtically studied, and the indicative significance of SB reflectance (Rob) on maturity and its influence on the development of reservoir space are discussed and summarized. The results show that the difference of primary maceral types is primarily responsible for the different evolution paths of SB. Most of the pre-oil bitumen is in-situ SB with only a small amount being of migrated SB, while most of the post-oil bitumen and pyrobitumen are migrated SB. From the immature to early oil maturity stage, bituminite, vitrinite, and inertinite can be distinguished from SB based on their optical characteristics under reflected light, and alginite can be differentiated from SB by their fluorescence characteristics. Under scanning electron microscope, in-situ SB and migrated SB can be effectively identified. Rob increases linearly with increasing vitrinite reflectance (Ro), as a result of a decrease of aliphatic structure and the enhancement of aromatization of SB. Within the oil window three types of secondary pores may develop in SB, including modified mineral pores, devolatilization cracks and bubble holes. At a high maturity stage spongy pores may develop in pyrobitumen. Scanning electron microscopy combined with in-situ SEM-Raman spectroscopy can further reveal the structral information of different types of SB, thus providing crucial data for understanding for understanding OM migration paths, dynamics, and distances at micro-scale.

Understanding pore space and oil content of liquid-rich shale in the southern Bohai Sea, China

The commercial production of shale oil in onshore Bohai Bay Basin has become a reality, but the potential of offshore shale oil is still unclear. The Bohai Sea, the leading crude oil-producing area in China in 2022, has great potential of shale oil resources, but the shale properties have not been comprehensively studied. The southern Bohai Sea, including the Huanghekou and southwestern Bozhong Sags, was selected. The study was performed on three layers: the third member of Shahejie Formation, first and second members of Shahejie Formation (as a whole), and the third member of Dongying Formation. Twenty-one shale core samples from nine wells, for the first time, were analyzed for sedimentary structure, lithology, pore space, composition of the thermally hydrocarbons and oil content. The content of minerals, pore sizes, and composition of the thermally hydrocarbons were compared with those of shales from other regions of China. The potentially producible oil generated in the organic-rich laminae was found to be accumulated in the silt-grained laminae through micromigration. Mixed and siliceous shale were the main lithofacies. Mineral overgrowths and solid bitumen reduce the volume of former intergranular pores. Honeycomb-like OM pores in samples with higher maturity (Ro > 1.1%) substantially increased pore connectivity from FIB-SEM image datasets. The retained oil was mainly distributed in pores with widths larger than 4 nm. The composition of the thermally hydrocarbons in samples stored at ambient conditions was governed by the maturity and concentration of the OM. Light hydrocarbons, even gaseous hydrocarbons are still retained in the shale with lower maturity and higher TOC for strong sorption of OM. The oil content is 0.50–23.41 mg/g after Rock-Eval S1 correction, with an average of 6.27 mg/g. While average oil content is 1.38 mg/g without correction. Finally, the optimal production intervals for Well B4 and Well B8 were determined. This study provides data and suggestions for the exploration of shale oil resources in the southern Bohai Sea.

Combining atomic force microscopy and nanoindentation helps characterizing in-situ mechanical properties of organic matter in shale

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.

A Cryogenian interglacial source rock in South China: Geochemistry, spatial distribution and organic matter enrichment

The organic-rich Datangpo Formation was deposited between Sturtian and Marinoan glaciations during the Cryogenian in South China. As a set of source rocks with great petroleum exploration prospect, it is important to understand how the glacial ocean transformed into a favorable condition for organic matter (OM) accumulation for evaluating its hydrocarbon potential. Here, the organic and inorganic geochemical data were tested, and the lithological and geochemical data were compiled to study the spatial distribution and OM enrichment of Datangpo Formation. The Datangpo Formation is a set of good quality (average total organic carbon (TOC) content = 1.83 %), sapropelic OM type (light organic carbon isotopes (δ13Corg) and overmature source rocks (average solid bitumen Raman spectroscopy equivalent vitrinite reflectance (Requ) = 4.28%). The areas of thickest source rock are located in the Xiushan and Tongren, and spatial distribution was controlled by rift activity and the erosion by the Marinoan glaciation instead of the remnant glacial topography of the Sturtian glaciation. The OM enrichment of Datangpo Formation was controlled by anoxic/euxinic water condition, high sedimentary rate, and high productivity. The primary productivity in interval Ⅰ and Ⅱ was promoted by hydrothermal nutrients continued since late Sturtian glaciation and few terrigenous nutrients, and terrigenous nutrients of continental weathering during greenhouse period, respectively.

Geological Aspects of the Formation and Distribution of Gas Anomalies in Bottom Sediments of the New Siberian Sedimentary Basin and Adjacent Geostructures of the East Siberian Sea

Abstract —In bottom sediments of the New Siberian sedimentary basin and adjacent geostructures of the East Siberian Sea, we identified СН4, as well as its limit and unsaturated homologues (up to and including C5H12), CO2, CO, H2, He, H2S, O2, N2, and Ar. Isotope-gas-geochemical parameters δ13С СО2, СН4 and С2Н6, of the molecular mass of hydrocarbon fraction and genetic coefficients indicate the presence of both syngenetic and epigenetic gases of various gas sources in sediments, including recent sediments, peatlands, coal-bearing and gas-bearing formations, solid bitumen, igneous formations, accumulations of gas hydrates and prognostic condensate-gas, condensate, oil-and-gas and gas-and-oil reservoirs. Concentrations of CO2 and CO reach 29.25 and 0.06 cm3/kg, CH4 and the sum of its homologues – 5.93 and 0.031, Н2 and He – 0.78 and 0.318, H2S – 0.092 cm3/kg; this indicates that gas-geochemical anomalies, exceeding the anomaly criteria by 6–124 times, form in bottom sediments. The formation and distribution of abnormal concentrations of natural gases depend on the complex influence of gas-controlling factors – geological structure, fold and fault tectonics, magmatism, coal-oil-gas content, bituminous content, organic saturation, lithological composition, water-physical and reservoir properties of sediments, hydrogeological, geocryological and other conditions for accumulation of natural gases or their degassing.

The influence of asphaltene matrix on the thermal evolution of polycyclic aromatic hydrocarbons: Experimental evidence and geochemical implications

The thermal evolution of components trapped in matrix of asphaltenes is supposed to be retarded, as compared to the free ones. Studying the geochemical evolution of trapped polycyclic aromatic hydrocarbons (PAHs) may provide insight for the characterization of high-maturity organic matter. The discrepancies in the thermal evolution between free and trapped (asphaltene-adsorbed/occluded) PAHs (phenanthrene, chrysene, pyrene, and their methylated isomers) were studied by thermal maturation (gold tubes, 300 ∼ 400 °C) experiments on a low-maturity solid bitumen from the Sichuan Basin, southwestern China. The results show that the thermal evolution of asphaltene-adsorbed PAHs is retarded compared to that of free ones. This is attributed to slight differences in reaction kinetics due to steric hindrance by the asphaltene structure. The asphaltene matrix appears to act as a reaction inhibitor leading to a retardation of the thermal evolution of the methylphenanthrene index (MPI) in asphaltene-adsorbed hydrocarbons. This could provide a possibility for maturity assessment of high-maturity organic matter. The thermal evolution of asphaltene-occluded PAHs in the experiments resulted in thermodynamically controlled isomer distributions of occluded methylphenanthrenes and methylchrysenes. However, the occluded methylpyrene isomers were hardly affected by thermal stress. They probably retained their original distributions and may serve as source indicators.