Solid Bitumen Research Articles

Origin and evolution of a CO2-Rich gas reservoir offshore Angola: Insights from the Gas Composition and isotope analysis

The pre-salt sections of the offshore Kwanza Basin, Angola are potentially petroliferous reservoirs like their Brazilian counterparts on the other side of the South Atlantic Ocean. In this study, a pre-salt reservoir of the offshore Kwanza Basin was found to contain solid bitumen and gas of high portions of CO2 (ca. 83%) and methane (ca. 16%). The chemical and isotopic (C, H and He) compositions of the gas indicate that the CO2 is primarily mantle-derived while the gaseous hydrocarbons are mainly late mature thermogenic gas. The Barremian-Aptian Red Cuvo Formation with sapropelic and humic organic matter and an average TOC content of 1.7% could be the principal source of the bitumen and gaseous hydrocarbons in the reservoir. Rapid oil generation since the source rock sedimentation could have occurred as a result of the fast and thick salt deposition or the high thermal gradient created by the crustal thinning and magmatism during the South Atlantic Ocean opening. The δ13C of gaseous hydrocarbons also indicates their mixed origins of sapropelic and humic organic matters and possible abiotic processes.This reservoir is similar in the origin of CO2 and geological background to some pre-salt reservoirs in the Brazilian basins. Such similarities with prolific petroleum systems may imply great petroleum potential in the pre-salt sections of the offshore Kwanza Basin, Angola.

Adhesion Performance between Solid Waste and Bitumen Based on Surface Energy Theory

Natural aggregates are gradually experiencing resource shortages and price accumulations with the rapid development rate of the highway construction industry. Therefore, new materials with social and economic benefits must be identified to replace natural aggregates. Limestone was selected as the representative of natural aggregates, and waste glass and waste ceramics were chosen as the representatives of solid waste in this article. This was undertaken to compare their physical and mechanical properties and the adhesion performance between bitumen and aggregates and to investigate the applicability of solid waste in asphalt pavement. The chemical and mineral compositions of these materials were tested by an X-ray fluorescence spectrometer and an X-ray powder diffractometer. The adhesion performance between bitumen and aggregates was analyzed by establishing adhesion and spalling models based on surface energy theory. Results show that the sizes of glass and ceramics must be small, characteristics which are unsuitable for use in high-grade roads. Glass and ceramics are more adhesive to bitumen than limestone and are suitable for areas with a considerable amount of rainfall and insufficient drainage systems. This article can promote the recycling of glass and ceramics and also provide a research idea for verifying the suitability of other solid waste in asphalt pavement.

PENGARUH AGRESIVITAS PAJAK TERHADAP CORPORATE SOCIAL RESPONSIBILITY (CSR) : UNTUK MENGUJI TEORI LEGISTIMASI

In the Mineral and Coal Law no. 4 of 2009, mining is a mineral and coal exploitation activity which consists of stages of general investigation, exploration, feasibility studies, construction, mining, processing and refining, transportation and sales, and post-mining activities. Coal mining is the mining of carbon deposited rock found in the earth, including solid bitumen, peat, and asphalt rock. The purpose of this study was to determine the effect of tax aggressiveness on corporate social responsibility in coal mining sub-sector companies in 2017- 2021. The method used in this study is a quantitative method. The variables in this study consist of the dependent variable, namely corporate social responsibility, while the independent variables are tax aggressiveness and the control variables are capital intensity, company size, return on assets, and leverage. The population in this study is the coal sub-sector mining companies listed on the Indonesia Stock Exchange in 2017-2021, amounting to 22 companies. The number of samples that have complete financial statements are 10 companies with a research period of 5 years so that a sample of 50 samples is obtained with the sampling technique using the purposive sampling method. The results showed that the tax aggressiveness variable based on the results of the t-test obtained a Tcount of 0.770 <Ttable 1.67655. The conclusion of this study is that partially shows that tax aggressiveness has no effect on corporate social responsibility

Characteristics and significance of the solid bitumen in the second member of Dengying Formation of Sinian system in the north of central Sichuan Basin, China

With ongoing advancements in natural gas exploration, the second member of the Sinian Dengying Formation (Deng 2 Member) has emerged as a crucial region for providing natural gas reserves in the north of the central Sichuan Basin. The Deng 2 Member has a significant volume of reservoir solid bitumen. Geochemical characteristics and development mechanism of the solid bitumen were determined through measurements and analyses of the Deng 2 Member samples collected from primary exploration wells by using optical microscopy, SEM, gas chromatograph-mass spectrometer, and laser Raman spectrometer. The results show that the Deng 2 Member has a generally high content of solid bitumen, ranging from 2.96% to 5.13% on average in single wells. The solid bitumen mainly occurs as the fillings of dissolved pores (caves) and fractures, followed by intergranular pores, in the shape of spots, balls, plates, and veins dominantly. Diasteranes content and laser Raman spectrograms indicate that the solid bitumen is in the high maturity stage. The bitumen reflectance calculated by laser Raman spectroscopy is distributed between 2.49% and 4.09%, indicating the major source of the thermal cracking of crude oil. Solid bitumen in the Deng 2 Member has different contents of 21α(H)–C29 norhopane, C35 hopane, and C34 hopane, and Ts/Tm values from the Deng 4 Member in the Gaoshiti Moxi area. It is inferred that some solid bitumen is from the source rocks of the Lower Cambrian Maidiping Formation and the Sinian Doushantuo Formation. Two stages of bitumen were developed in the Deng 2 Member, indicating possible two stages of oil filling and thermochemical sulfate reduction (TSR) in the geologic history.

Изменение аминокислотного состава природных углеродистых веществ и некоторых синтетических аналогов в ряду карбонизации

Amino acids are important records of geochemical processes in sedimentary rocks. The knowledge about changing the composition of amino acids is important for our understanding of genetics of organic compounds in the geological records. In the presented work, compositions of amino acids in natural solid bitumens, graphites and some synthesized carbonaceous materials were investigated. We determined that the content of amino acids decreases with increasing temperature of the formation of natural carbonaceous substances. the content of aliphatic amino acids gradually increases with increasing degree of transformation in the carbonization (dehydrogenation) series, mainly due to glycine, alanine and leucine. The revealed changes in the amino acid composition of natural carbonaceous substances are associated with the genesis of the initial organic matter, as with as the content of carbonaceous matter and its interaction with the mineral component.
 We showed that the selection of dominant individual amino acids without involvement of statistical methods did not allow distinguishing some types of natural carbonaceous materials. At the same time, lots of amino acids were identified by statistical methods, statistically significantly distinguishing all the studied types of solid natural bitumen and graphite.

Pore systems and organic petrology of cretaceous Mowry and Niobrara source-rock reservoirs, Powder River Basin, Wyoming, USA

The Powder River Basin (PRB) is a world-class oil province, in large part thanks to contributions from premier source rocks, Cretaceous Mowry and Niobrara shales. Both formations are also unconventional reservoirs. A critical aspect of evaluating production potential and finding sweet spots is the nature of the pore systems in these fine-grained source-rock reservoirs. Variation by stratigraphic interval is important for selecting optimum target zones for horizontal wells. Understanding variation in pore type, size, and connectivity and relationships with mineralogy and fabric help in determining prospectivity in different parts of the basin. Deciphering controls on pore-system development helps predict intervals and locations of optimum reservoir quality.Imaging of Niobrara and Mowry samples from a range of thermal maturities provided observations and data on pore systems, organic matter (OM) types and associations with mineralogy and fabric, wettability, and microporosity associated with both diagenetic and detrital clays. Imaging techniques included scanning electron microscopy, organic petrography and correlative scanning electron microscopy, and mapping of mineralogy through energy dispersive spectroscopy.Mean solid bitumen (BRo) and vitrinite reflectance (VRo) values indicate all samples are in the oil window with values ranging from 0.52 to 1.15%. Organic fluorescence is prominent in amorphous OM, solid bitumen and some vitrinite in the early oil window. The fluorescence is extinguished at higher thermal maturity. Carbonate pellets (in Niobrara) mainly contain migrated solid bitumen and residual live oil and little or no terrigenous OM (vitrinite and inertinite). However, terrigenous OM is common in siliceous/argillaceous laminae in both formations, where it occurs with amorphous OM, some of which has converted in situ to a solid bitumen petroleum residue.One key finding is the widespread presence of migrated OM at very early oil window maturity. Distribution of such OM and associated wettability alteration is fabric-controlled, at all levels of thermal maturity studied. Clay morphology and abundance and supporting rigid mineral grain framework strongly influence pore development, preservation, and connectivity in both formations. Carbonate content is a good proxy for reservoir quality in Niobrara intervals due to association of porous solid bitumen with calcareous fecal pellets. High recrystallized microquartz content is associated with the best reservoir intervals in the Mowry.

An evaluation of organic matter dispersed in the Menilite Formation in Silesian Nappe (Polish Outer Carpathians): an optical microscopic approach

In this study, optical microscopic analyses were applied to evaluate the thermal maturity, characteristics of solid bitumen, and other organic matter finely dispersed in Oligocene shales of the Menilite Formation in the Iwonicz-Zdrój–Rudawka Rymanowska Fold (IRF) and Bóbrka–Rogi Fold (BRF) of the Central Carpathian Synclinorium of the Silesian Nappe, Outer Carpathians, Poland. The investigation was carried out at two-unit depths of the shallow and deeper D-1 sections (430 m – IRF and 4,300 m – BRF) and outcrop samples (BRF). The mean random huminite reflectance values indicate immature conditions with respect to hydrocarbon generation in samples from the D-1 shallow section (VRo≈0.40%) and in the outcrop samples (VRo=0.36%). The degree of thermal maturity of the organic matter from a depth of about 4,300 m – BRF based on random vitrinite (VRo≈0.80%) and solid bitumen (BRo≈0.65%) reflectance measurements is associated with the “oil window” for petroleum generation. The organic components dispersed in the examined Menilite Formation samples are typical for hydrocarbon-prone organic matter, suggesting the dominant kerogen type II. The potential precursor maceral for solid bitumen occurring in the examined samples from the deeper D-1 sections is largely the alginite maceral.

In-situ cracking of oil into gas in reservoirs identified by fluid inclusion analysis: Theoretical model and case study

Natural gas formed by cracking of crude oil occurs in many basins globally. One of the key questions about such gas is whether it was produced in-situ—by cracking of crude oil in the reservoir itself—or whether it was generated elsewhere and accumulated in the reservoir subsequently. Fluid inclusions trapped in minerals can provide direct evidence regarding the genesis of natural gas, because these inclusions represent samples of the fluid present at the time of trapping, and/or resulting from subsequent modification of the trapped fluid. Here, we outline some theoretical aspects of the processes of cracking, trapping of fluid inclusions, and potential post-entrapment modifications, that lead to a model for identifying evidence for in-situ cracking of crude oil in reservoirs based on fluid inclusion assemblages (FIAs). This model divides the crude oil cracking process into three main stages, and considers the predicted evolution of fluids and possibility of forming FIAs. In the initial step, before cracking, only liquid oil and aqueous fluid are present in a reservoir, and two endmember types of inclusions may be formed. If cracking of crude oil occurs in the reservoir after these inclusions were trapped, then in-situ cracking of oil within the inclusions gives rise to systematic changes that can be interpreted through the lens of progressive thermal maturation, and hence provide direct evidence for cracking in the reservoir. In the second step, during cracking, the reservoir may host up to four fluid phases (residual oil, aqueous fluid, natural gas, and solid bitumen), and in theory as many as fourteen types fluid inclusions can be trapped; hence, complex FIAs comprising multiple fluid inclusion types can be considered evidence for trapping during in-situ cracking of crude oil in the reservoir. In the third and final step, after complete cracking, liquid oil has been exhausted and only natural gas, solid bitumen and aqueous fluid remain in the reservoir; at this stage, up to six fluid inclusion types can be trapped, which can be indicative of cracking. We applied this model to study the genesis of natural gas in the Sinian Dengying Formation reservoir of the Anyue Gas Field in the Sichuan Basin, southwest China. Six types of hydrocarbon-bearing primary fluid inclusions were observed in fluorite crystals formed during hydrocarbon accumulation. Notably, one type of inclusion showed consistent volumetric phase ratios of solid bitumen plus gas, suggesting that these inclusions originally captured crude oil, which subsequently underwent in-situ cracking in a closed system (within the inclusions) to generate fixed proportions of gas and solid bitumen. These FIAs are consistent with our model and suggest that the fluid inclusions trapped in fluorite can record the in-situ cracking of crude oil in the reservoir, and can therefore be used as direct evidence for the genesis of natural gas.

Thermal Evolution and Hydrocarbon Generation Capacity of Typical Palaeozoic Marine Source Rocks in the South China Craton: Constrains from Semiclosed Artificial Thermal Maturation Experiments

Abstract Palaeozoic petroleum systems in the South China craton are prospecting frontiers for unconventional oil/gas. Understanding the hydrocarbon generation/retention capacity of source rocks has critical implications for reserve evaluation and targeting, which yet remains ambiguous in this region. In this study, six representative lithological types of organic-rich, immature-low-mature source rocks (two shales, two carbonates, a coal, and a solid bitumen) taken from the South China craton were treated with semiclosed hydrous pyrolysis (300–550°C). Pyrolysis results show that shale and carbonate source rocks have great hydrocarbon generation capacities, and immature solid bitumen can also generate appreciable quantities of hydrocarbons, whereas coal has the least hydrocarbon generation capacity. Both oil and gas are important hydrocarbon products of thermal maturation of shales, whereas gas generation capacity of carbonate source rocks is relatively moderate compared to their oil generation capacity. Therefore, marine shale is an important exploration target for unconventional oil and gas, yet marine carbonate is an important target for unconventional oils. The presence of appreciable carbonate minerals in shales can facilitate oil and gas generation likely by (1) enhancing oil expulsion, (2) facilitating decarboxylation of organic acid, and (3) catalysis. Pyrolysis data also support that molecular composition of thermogenic gas is not dominantly controlled by lithofacies of source rocks but mainly affected by maturation. Outcomes of this study demonstrate that marine organic-rich rocks within the Palaeozoic strata in the South China craton are critical prospecting targets for unconventional oil and gas.

Characterization of the bituminite-rich Chia Gara Formation in M-2 well Miran field, Kurdistan Region, NE Iraq

The present study focuses on the Chia Gara Formation that is part of the oil-prone sedimentary formations of Northern Iraq, being under extensive scientific concern in recent years. The Chia Gara Formation is considered one of the major source rocks of the prolific Kirkuk oil field of Northern Iraq, consisting of alternating layers of bituminous limestones and calcareous shales that were deposited during Late Jurassic – Early Cretaceous.The studied sequence from the Miran-2 well (depth 2185–2315 m) comprises mostly argillaceous limestones with calcite and quartz being the main minerals with variable amounts of clay minerals, K-feldspars, pyrite, gypsum, and anhydrite. TOC wt% ranges between 0.73 and 7.24 wt%, pointing to a significant variation regarding organic matter content. The average random vitrinite reflectance (VRo) is 1.00% and the average value of solid bitumen random reflectance (BRo) is 0.73%. Solid bitumens and bituminite (the latter corresponding to kerogen type II) are the predominant organic particles, particularly in the bottom to middle part of the Formation, whereas alginite occurs subordinately. Additionally, the common occurrence of vitrinite fragments indicates a significant terrestrial input (kerogen type III).Organic petrography proved to be the most important tool to provide with clear-cut results regarding the organic matter characteristics. Chia Gara Formation was deposited in a shallow marine palaeoenvironment probably shelf-slope, under reducing conditions. In particular in Miran-2 the studied strata are within the oil window, and the obtained results provide a better understanding of the organic matter type and maturation of this highly prolific and productive Formation.

Discovery of a new Proterozoic paleo-reservoir and its oil source in the Jianchang Sag, Yanliao Faulted-Depression Zone, North China

The discovery of many Proterozoic primary oil and gas reservoirs around the world testifies that the Meso-Neoproterozoic petroleum is an energy resources realm worthy of attention. This paper firstly reports the occurrence of hydrocarbon accumulations in the Neoproterozoic Luotuoling Formation in the Jianchang Sag, the Yanliao Faulted-Depression Zone. Petrography observation shows that the lower sandstone member of the Luotuoling Formation contains yellow fluorescent liquid hydrocarbons, while the upper sandstone member is rich in solid bitumen. Further analysis of the biomarkers and isotopic compositions reveals that the upper and lower reservoirs have different oil sources. The bitumen in the lower reservoir is rich in C 19 –C 20 tricyclic terpanes (TTs), 13 α (n-alkyl)-tricyclic terpanes and rearranged hopanes, but lacks gammacerane and steranes and depletes 13 C isotope (−33.4‰ to −30.6‰). This is consistent with the properties of the Hongshuizhuang Formation source rocks. The upper reservoir bitumen has C 23 TT as the major peak among C 19 –C 23 TTs, lacks 13 α (n-alkyl)-tricyclic terpanes, has a low abundance of rearranged hopanes, obvious distribution of gammacerane and steranes, and depletion of the 13 C isotope; essentially the same as the Gaoyuzhuang Formation source rocks. The discovery of oil seepage in the Luotuoling Formation of the Han-1 well is a promising indicator of the Precambrian oil and gas exploration potential of the Jianchang Sag.

Study on characteristics of oil and gas occurrence and reservoir space of medium-high maturity continental shale—A case study of middle jurassic lianggaoshan formation in fuling block, southeast of sichuan basin, south China

Possessed of easy access to development and fair economic benefits, medium-high maturity continental shale oil and gas have become the focus of shale oil and gas study in the future. Shale oil and gas mainly occur in pores, but studies on the pore characteristics of shale oil and gas occurrence are by no means sufficient. Focused on shale from the Middle Jurassic Lianggaoshan Formation in Well TYX, Fuling block, southeast of Sichuan Basin where a breakthrough in shale oil and gas exploration was recently achieved, this study selects core samples and conducts a series of analyses, including vitrinite reflectance analysis, kerogen microscopic examination experiment, total organic carbon (TOC) content analysis, mineral composition analysis, gas content measurement, isothermal adsorption experiment, S1 content analysis, and others. The analyses are to identify the pore characteristics of the continental medium and high maturity shale oil and gas by virtue of scanning electron microscope (SEM) with Ar-ion milling and the image processing software ImageJ. The conclusions are drawn as follows: in terms of lithofacies, medium-high maturity continental shale oil and gas mainly occur in organic-rich clay shale and organic-rich mixed shale; with regard to material composition, shale oil and gas mainly occur in organic matter, illite-smectite mixed layers and illite. Shale adsorbed gas content accounts for at most 40% of the total shale gas content and shale free gas content takes up at least 60% of the total shale gas content. Pores of solid bitumen, solid bitumen-clay mineral complex mass, clay minerals, structured vitrinite, and funginite are mostly developed in shale. Among them, the first three types of pores are the main reservoir space in shale considering their large number, good roundness, medium pore diameter, fairly good roundness of pore edges, and the complex shapes which altogether contribute to the large surface porosity.

Dynamic reconstruction of the hydrocarbon generation, accumulation, and evolution history in ultra-deeply-buried strata

The evolution mechanism of hydrocarbons in ultra-deeply-buried and ultra-old strata is the core issue of petroleum geology moving towards Deep Earth. Reconstructing the evolutionary history of ultra-deeply-buried hydrocarbons is the key to shedding light on deep hydrocarbon accumulation and evolution mechanisms. Furthermore, it can help point out directions for oil and gas exploration in Deep Earth. Anyue gas field in the central Sichuan Basin is the Frontier of deep natural gas exploration in China. This study selected the natural gas reservoirs of the Upper Sinian Dengying Formation in the central Sichuan Basin as the research object. By integrating analysis of natural gas geochemical characteristics, source rock evaluation, reservoir bitumen-source correlation, inclusion analysis, one-dimensional and two-dimensional hydrocarbon accumulation simulations, the generation and evolution of hydrocarbons in different structural regions, namely the inherited paleo-uplift and slope area in central Sichuan Basin, have been dynamically restored and compared. The results show that: 1) The natural gas of the ultra-deeply-buried Sinian Dengying formation in central Sichuan is typical oil-cracking gas from the paleo-oil reservoir. The Sinian gas is mainly sourced from the Qiongzhusi/Maidiping Formation. 2) The formation of Sinian gas reservoirs includes three stages: the formation of paleo-oil-reservoirs; the cracking of paleo-oil-reservoirs into paleo-gas-reservoirs; the adjustment of the paleo-gas-reservoirs. 3) Source rock and reservoir evaluation, quantitative solid bitumen analysis, and hydrocarbon accumulation simulation show that the natural gas accumulation conditions in the slope area are better than in the inherited uplift area. The scale of the paleo-oil-reservoirs in the slope area may be greater than that in the inherited uplift area.

Origin and re-Os geochronology of vein bitumen in the Nanpanjiang basin, SW China: Implication for the ore-forming age of Carlin-type gold deposits

The Nanpanjiang basin has the second-largest concentration of Carlin-type gold deposits in the world. Although significant progress has been made during the past two decades, the age of gold mineralization has not been well constrained. Field observation shows that these gold deposits are spatially associated with hydrocarbon reservoirs. At the Lannigou gold deposit, solid bitumens exist as films within structural fractures and cut through the orebodies, indicating that these bitumens formed after gold mineralization. In this work, we systematically studied bitumen reflectance (Rb), trace element, carbon isotope, and Re-Os isotopic compositions. These results show that these bitumens have high Rb values ranging from 2.40 to 2.71, indicating that they are high-maturity pyrobitumen. Trace element analysis reveals that bitumens in the deposit have high V/Ni, V/(V + Ni), and Zr/Sc ratios, but low Ni/Co, La/Sc ratios, and exhibit relatively flat rare-earth element (REE) patterns with no obvious Ce or Eu anomalies, comparable to the corresponding elemental ratios and REE patterns of Permian source rocks in the region. These bitumens also have similar δ13C values (-24.4 ‰ to –23.8 ‰, mean = -24.1 ‰) to the Permian source rocks (–22.4 ‰ to 24.7 ‰, mean = –23.6 ‰), indicating that they originate from the Permian source rocks. Five bitumen samples cut through the orebody yield a well-defined isochron age of 173 ± 6 Ma, indicating that the Lannigou gold deposit formed before this time. Our new data, combined with previously published geochronological data, suggest that the majority of Carlin-type gold deposits in the Nanpanjiang basin were mineralized at late Triassic to early Jurassic. The Re-Os data of this study also imply that the bitumen Re-Os chronometer has a large potential to constrain the timing of metal mineralization in low-temperature hydrothermal deposits.

The Analysis of Bio-Precursor Organic Matter Compositions and Its Significance for Gas Shale Reservoir of Wufeng–Longmaxi Formation from Dingshan Area, Sichuan Basin

In order to analyze the organic matter (OM) composition, this study carefully identified the OM types of 66 samples from Well A in the Dingshan area under microscope, and made an effort to obtain the semi-quantitative statistics contents of different bio-precursor derived OM. The results of OM content obtained under microscope showed a strong positive relationship (R2 = 0.85) with the TOC content analyzed by carbon–sulfur analyzer. The OM contained bethic algae debris, phytoplankton amorphous organic matter (AOM), acritarch, vitrinite-like particles, zooplankton (including graptolite, chitinozoa and others) and solid bitumen which was secondary formation OM. The phytoplankton AOM, graptolite and solid bitumen were the dominated OM in this interval. Solid bitumen (8%~11%) was filled at the bottom of the Wufeng Formation, which could be one reason for the high shale gas production in the lower part of this shale interval. N2 adsorption results showed that micropores and mesopores were predominant in this shale gas system, while pore volumes illustrated better positive relationships with organic matter than minerals, especially AOM content. Thus, both solid bitumen and AOM kerogen were the main sources for shale gas generation in this shale gas system.

Characterization and classification of the microporosity in the unconventional carbonate reservoirs: A case study from Hanifa Formation, Jafurah Basin, Saudi Arabia

Formation porosity is a key factor that exerts substantial control upon reserve estimates, and ultimately may affect the development viability of unconventional resources. Microporosity studies have largely focused on siliciclastic mudstones, with limited examples that assess porosity type and distribution in organic-rich calcareous mudstone successions. In this work, a comprehensive porosity characterization study was performed on the organic-rich carbonate-dominated Hanifa Formation of the Jafurah Basin, which is the largest unconventional basin in Saudi Arabia. An extensive experimental program, involving petrographical description, SEM analysis, mineralogical analysis using XRD and QEMSCAN, and geochemistry analysis was employed in order to characterize the samples and analyze the geological origins of the microporosity. The main constituent minerals in this study are calcite (87 wt%) and anhydrite (9 wt%), as well as <1 wt% quartz, illite, pyrite, and dolomite. Total organic carbon reaches up to 5.46 wt %, yielding 5.09 mg HC/g rock (S2), while the free hydrocarbon content (S1) is 5.36 mg/g rock. Type II kerogens characterize the rock samples, and the thermal maturity index is 1.28. The microporosity in Hanifa Formation can be classified into three groups, including framework, solid bitumen, and intraparticle pores. Framework porosity is observed as the main type of microporosity, with solid bitumen representing a subordinate component of the overall porosity. Sheltered pores are also encountered associated with coccoliths tests deposited within the pelagic sediments. Higher degrees of thermal maturity of these sedimentary rocks increase the storage space for the generated hydrocarbon hosted in the solid bitumen. This study introduces an under-explored category of unconventional resources, nominally those that have a carbonate content >85%. Fundamentally, the findings of this study demonstrate that the Hanifa Formation in the Jafurah Basin has the potential for gas exploration and recovery.

Sulfate sources of thermochemical sulfate reduction and hydrogen sulfide distributions in the Permian Changxing and Triassic Feixianguan formations, Sichuan Basin, SW China

The sulfate sources of thermochemical sulfate reduction (TSR) and hydrogen sulfide (H2S) distributions in the Permian Changxing (P2c) and Triassic Feixianguan formations (T1f) in the Sichuan Basin were investigated using geochemical and carbon isotopic data for gases, and sulfur isotopic data for solid bitumen, H2S, and anhydrite. The concentration of H2S (>5.0%) is relatively high, and the δ34S values of the H2S are significantly higher than those of the Permian source rock kerogen, suggesting a TSR origin for the H2S. The δ13C values of the methane and ethane do not increase as the gas souring index (H2S/(H2S+∑Cn)) increases, and the δ34S values of the H2S are significantly lower than those of the solid bitumen, suggesting mainly liquid hydrocarbon dominated-TSR. The δ34S values of the solid bitumen and H2S in the Puguang gas field in the eastern platform are significantly lower than those in the Yuanba gas field in the western platform, and the sulfates for the TSR were most likely derived from the Early and Late T1f evaporative seawater, respectively. The sulfates required for TSR were most likely enriched during dolomitization based on the positive relationship between the H2S concentrations and the thickness of the dolostone reservoirs. The H2S distributions were mainly controlled by the sulfate distributions and the paleo-oil accumulations. The edges of the eastern and western platforms in the Kaijiang-Liangping trough, which were favorable for dolomitization and paleo-oil accumulations, are the most likely H2S-enriched areas in the Sichuan Basin.

Generation and geochemical signatures of natural gas from solid bitumen: Implications from closed and stepwise semi-open pyrolysis experiments

Solid bitumen has been acknowledged as an important source of overmature shale gas. However, the gas generation potential, chemical signatures and carbon isotopic compositions of natural gas derived from solid bitumen in an overmature hydrocarbon system are not well-understood with respect to various geological conditions. In this study, a relatively low-maturity solid bitumen from Cambrian reservoirs in the northwest Sichuan Basin was pyrolyzed in both closed and stepwise, semi-open systems. In the closed system, methane generated in the overmature thermal stage is dominated by the secondary cracking of wet gas and cumulative methane carbon isotopic values that are 4.4‰–14.8‰ lighter than the carbon isotope composition of the original solid bitumen. In semi-open systems, the gas is predominantly generated from residual solid bitumen and has wetness (i.e., C2–C5/C1–C5 by volume) values of generally less than 1%. At the same thermal maturity levels, the carbon isotope composition of methane in various semi-open systems is 4.4‰–10.0‰ heavier than those in the closed system and may also be isotopically heavier than the carbon isotope value of the original solid bitumen. The present study also illustrates that the calculated gas yields and methane carbon isotopes within a certain thermal maturity range in the closed system cannot be compared with those from residual solid bitumen as measured in the corresponding semi-open systems. This highlights the need to conduct specific semi-open pyrolysis experiments to investigate the late gas generation potential and geochemical signatures of natural gas from solid bitumen when the geological system is not a closed system. By comparing the above-mentioned results with the geochemical characteristics of Wufeng-Longmaxi shale gas from the Changning and Jiaoshiba gas fields of the Sichuan Basin, southwest China, it is suggested that the shale gas examined in this study is most likely generated in semi-open systems rather than in a closed system. In other words, the early-generated gas has been expelled from the shales, leaving the late-generated gas from residual solid bitumen and/or kerogen as the main gas source in the present hydrocarbon system.

Comparison of the Ediacaran and Cambrian petroleum systems in the Tianjingshan and the Micangshan uplifts, northern Sichuan Basin, China

Several different types of petroleum occurrences (including solid bitumens, oil sands, and oil seeps) are observed in various strata (e.g., the Ediacaran, Cambrian, Devonian, Permian, Triassic, and Jurassic strata) of the Tianjingshan and the Micangshan uplifts, northern Sichuan Basin, China. However, the sources of these petroleum occurrences are still in dispute, because of the severe biodegradation, strong thermal alteration, and multiple tectonic movements. At present, such uncertainty in the potential source rock systems has hindered oil and gas exploration in the study areas. In this study, methods including catalytic hydropyrolysis and trace elements analysis were introduced into the oil-source correlation study, to avoid the influence of biodegradation and/or thermal alteration. The results show that the petroleum shows that occur in the Cambrian-Jurassic strata of the Tianjingshan area are characterized by low maturity (equivalent vitrinite reflectance (EqVRo) < 1.0%), light organic carbon isotopic ratios (δ13Corg values ranging from −34.0‰ to −38.4‰), a predominance of C29-steranes, enrichment in V and Mo, and strong depletion in Bi elements. In contrast, the solid bitumens in the Ediacaran Dengying Formation in the Micangshan area have high maturity (EqVRo > 2.0%), slightly heavier δ13Corg values ranging from −27.5‰ to −36.0‰, a predominance of C27-steranes, weak enrichment in Mo and strong depletion in Rb and Bi elements. In addition, the Ediacaran and the Lower Cambrian source rocks can be discriminated by the bound sterane distributions, trace element concentrations, and bulk δ13Corg values. Further oil-source correlation indicates that the petroleum shows in the Cambrian-Jurassic strata in the Tianjingshan area were dominantly derived from the Lower Cambrian Qiongzhusi Formation, while those in the Ediacaran Dengying Formation in the Micangshan area were mainly sourced from the Ediacaran Doushantuo Formation. Finally, the results of oil-source correlation, combined with the tectonic evolution history of the investigated areas further elucidate the occurrence and distribution of petroleum, which can assist in oil and gas exploration in the investigated uplifts and the adjacent areas.

Maturity assessment of solid bitumen in the Sinian carbonate reservoirs of the eastern and central Sichuan Basin, China: Application for hydrocarbon generation modelling

Maturity assessment of solid bitumen is significant for the reconstruction of the thermal evolution history and obtaining the key periods of hydrocarbon generation for the Qiongzhusi source rocks in the eastern and central Sichuan Basin because of the absence of vitrinite in the marine mudstones. Based on the Fourier transform infrared (FTIR) spectroscopy and Raman spectroscopy analyses of solid bitumen, the thermal maturity of solid bitumen in the Sinian reservoir was evaluated, which was used to calibrate the thermal maturation history modelling results of the Qiongzhusi source rocks. The FTIR spectrums of solid bitumen are characterized by depleted aliphatic carbon and CO group, and enrichment of aromatic carbon, which indicates that the vitrinite reflectance equivalent (VReq) values of solid bitumen in the Sichuan Basin exceed at least 1.3%. The calculated VReq values of solid bitumen inferred by Raman spectroscopy analysis are 3.8%–4.09% and 3.51%–3.77% in the eastern and central Sichuan Basin, respectively. The calculated VReq values of bitumen in fluorite and calcite inclusions of the central Sichuan Basin vary from 3.54% to 3.64%. The thermal evolution history of the Qiongzhusi source rocks can be divided into two heating–cooling stages. At the end of the second heating stage, which is the Late Cretaceous, the Qiongzhusi source rocks reached the highest temperature of 250 and 225°C in the eastern and central Sichuan Basin, respectively. The different burial and thermal history of the Qiongzhusi source rocks controls their key periods of hydrocarbon generation in the eastern and central Sichuan Basin. Two episodes of intense oil generation of the Qiongzhusi source rocks were determined at 440–380 Ma and 290–260 Ma, and one phase of gas generation from oil cracking was from 260 to 85 Ma in the eastern Sichuan Basin. The intense oil generation of the Qiongzhusi source rocks occurred at 240–185 Ma and the oil cracking phase was from 185 to 90 Ma in the central Sichuan Basin.