Kerogen Research Articles

Petroleum system analysis of Fujairah basin, eastern offshore of the United Arab Emirates

The Fujairah basin, located on the eastern margin of the United Arab Emirates, forms part of the hinterland basin of the Oman-UAE mountains. Despite its geological significance, the hydrocarbon potential of this basin remains unexplored. This study aims to address this knowledge gap by using 2D seismic reflection data, three exploration wells, geochemical data from one well, a 2D velocity section, and two pseudo-wells. The study began with the interpretation of the seismic profiles and then proceeded to create depth maps for the most significant units. We used Rock-Eval pyrolysis plots to identify the primary source rocks and to classify their kerogen types. The seismic interpretation formed a basis for the 1D and 2D basin modeling techniques that are used to determine the petroleum system of the basin. Our results identify the Pliocene, Miocene, and Eocene sequences as potential source rocks in the basin with TOC values less than 1 wt% and low expulsion efficiencies. The Pliocene and Miocene source rocks are mainly type-II kerogen, whereas most Eocene samples are characterized as type-III kerogen. The Pliocene and Miocene source rocks are immature in the basin. The Eocene is mature depending on the burial within the sub-basins. The Eocene started expelling hydrocarbons during the Burdigalian, which was linked to the collision of the Arabian and Central Iran plates along the Zagros suture zone. Structural and stratigraphic traps may have entrapped the generated hydrocarbons. The three drilled wells in the basin lack good reservoir rocks. However, low-velocity anomalies and bright spots indicate possible hydrocarbon accumulations in the basin.

High sulphur oil of Type II kerogen of the oil shales from Western Central Jordan based on molecular structure and kinetics

Organic rich sedimentary rocks of the Late Cretaceous Muwaqqar Formation from the Lajjun outcrop in the Lajjun Sub-basin, Western Central Jordan were geochemically analyzed. This study integrates kerogen microscopy of the isolated kerogen from 10 oil shale samples with a new finding from unconventional geochemical methods [i.e., ultimate elemental (CHNS), fourier transform infrared spectroscopy and pyrolysis–gas chromatography (Py–GC)] to decipher the molecular structure of the analyzed isolated kerogen fraction and evaluate the kerogen composition and characteristics. The optical kerogen microscopy shows that the isolated kerogen from the studied oil shales is originated from marine assemblages [i.e., algae, bituminite and fluorescence amorphous organic matter] with minor amounts of plant origin organic matter (i.e., spores). This finding suggests that the studied kerogen is hydrogen-rich kerogen, and has the potential to generate high paraffinic oil with low wax content. The dominance of such hydrogen-rich kerogen (mainly Type II) was confirmed from the multi-geochemical ratios, including high hydrogen/carbon atomic of more than 1.30 and high A-factor of more than 0.60. This claim agrees with the molecular structure of the kerogen derived from Py–GC results, which suggest that the studied kerogen is mainly Type II-S kerogen exhibiting the possibility of producing high sulphur oils during earlier stages of diagenesis, according to bulk kinetic modeling. The kinetic models of the isolated kerogen fraction suggest that the kerogen conversion, in coincidence with a vitrinite reflectance range of 0.55–0.60%, commenced at considerably lower temperature value ranges between 100 and 106 °C, which have produced oils during the early stage of oil generation. The kinetic models also suggest that the commercial amounts of oil can generate by kerogen conversion of up to 50% during the peak stage of oil window (0.71–0.83%) at relatively low geological temperature values in the range of 122–138 °C. Therefore, further development of the Muwaqqar oil shale successions is highly approved in the shallowly buried stratigraphic succession in the Lajjun Sub-basin, Western Central Jordan.

Characterizing competitive adsorption and diffusion of methane and carbon dioxide in kerogen type-III slit model

Characterizing competitive adsorption and diffusion of methane and carbon dioxide in kerogen type-III slit model

Microstructural BIB-SEM investigation of Upper Cretaceous Jordanian carbonate-rich oil shales bearing type II-S kerogen

AbstractIn this study, we use Broad Ion Beam polishing and Scanning Electron Microscopy (BIB-SEM) to characterize the microstructure of selected core samples of immature Upper Cretaceous carbonate-rich oil shales from Jordan and to link the observations to porosity and compositional and geochemical data. The aim of this study is to understand the distribution of pore space, primary organic matter, and organic sulfur on a sub-micron scale, particularly in carbonate- and silicate-dominated layers. The thermal maturity of these marine carbonate mudstone samples of pelagic origin was found to be influenced by the elevated sulfur contents in these Type II-S kerogen source rocks. This was confirmed through both organic geochemistry and BIB-SEM observations, which revealed high sulfur content. Porosity in the carbonate mudstone exists within foraminifera, and aggregates of microfossil fragments. Initially, these voids provided significant inter- and intra-particle porosity which were later filled by organic matter during diagenesis. This ‘mobile’ organic matter is interpreted as microscopic bitumen, which exists as a solid or highly viscous fluid at surface conditions. It is likely a residue of low-temperature (“early”) bitumen generation. By examining the samples before and after dichloromethane (DCM) extraction and subsequent BIB-SEM analyses, we observed that the specimens contained a significant amount of soluble organic matter (SOM), mostly present in the micropores associated with calcite. The microscopic solid bitumen is observed to remain stable even under various conditions, such as in vacuum oven conditions of 105 °C (24 h), or exposure to ultra-high vacuum, broad ion beam (heat > 70 °C) and an electron beam of 15 keV. This suggests that the solid bitumen acts as a solid at elevated temperatures and confining pressures (85 °C and 250 MPa), and its presence can lead to the buildup of significant fluid overpressures. Our observations indicate that the pores associated with calcite provide high storage capacity in the shales during the early stages of hydrocarbon generation. In contrast, it suggests that siliciclastic-rich samples are more prone to hydrofracturing as the (early) generated hydrocarbons cannot be expelled easily. These findings highlight the complex distribution and behavior of pore space, organic matter, and sulfur in shales, shedding light on their potential for hydrocarbon generation and storage. Graphical abstract

Assessment of the Upper Cretaceous Abu Roash carbonate source rocks from the Beni Suef field, Western Desert, Egypt

Global sea-level rise during the Early Turonian-Late Cenomanian Bonarelli event resulted in oceanic anoxia and deposition of organic-rich source rocks across Northern Africa, such as the Late Cretaceous Abu Roash-F carbonates. Here, using thin sections, SEM, XRF, standard core analysis, and Rock-Eval pyrolysis data, we examine the petrographic and geochemical properties of the Abu Roash-F (AR-F) carbonate source rocks. These deep marine carbonates consist of dominantly planktonic foraminifera and calcispheres and are classified as wackestone. Extensive micritization, calcite cementation, and ferroan dolomite cement replacement (filling the bioclastic tests and chambers) are identified as the principal diagenetic factors. Core measurements indicate that these carbonates have very low porosity below 3% and horizontal permeability of 0.003 mD (3x10-18 m2), which is also supported by the observed isolated nanopores in SEM. The elemental concentration from the XRF data confirms a highly reducing depositional environment that facilitated the organic richness during the Early Turonian Oceanic Anoxia Event 2 (OAE2). The studied carbonate interval consists of Type-II kerogen in the oil window with a Tmax of about 440 °C and up to 4.2 wt.% TOC indicating ‘fair’ to ‘excellent’ organic richness and a very high probability of active oil generation and expulsion. Following the wireline logs and core data, the self-sourcing unconventional reservoir potential of the AR-F carbonates has been emphasized.

Geochemical characterization and paleo-burial history modelling of unconventional resources: A case study from the Kimmeridge Clay Formation (KCF) in the UK North Sea

For several decades the UK North Sea has been a prolific oil and gas province, with numerous conventional oil and gas discoveries sourced predominantly by the Upper Jurassic to Lower Cretaceous Kimmeridge Clay Formation (KCF). In this study, we have combined the analysis of total organic carbon/pyrolysis and vitrinite reflectance geochemical data from KCF samples with 1D basin modelling to investigate the potential for shale oil and gas plays in the Outer Moray Firth region. The results of geochemical evaluation show that most of the samples have very good to excellent hydrocarbon generation potential and contain predominantly oil-prone Type-II kerogen. A few samples show a significant oil saturation index above 100 mgHC/gTOC, which indicate a good potential for producible shale oil. The modelling results suggest that vitrinite reflectance values for the KCF vary mainly between 0.51 and 1.15%Ro, with kerogen transformation of up to 86 %. This is indicative of early-oil to late-oil/early-gas maturity window at present day, and within the range reported for proven shale oil plays. The KCF shows good oil saturation in most of the modelled well locations of up to 6.4 mg/g rock, indicating potentially producible shale oil. Predictions from modelling support the interpretations from geochemical data.

Geochemical evaluation of the carbonaceous shale associated with the Permian Mikambeni Formation of the Tuli Basin for potential gas generation, South Africa

Abstract The increasing demand for energy and global commitment to reduce CO2 emissions to mitigate climate change has spurred countries to pursue unconventional hydrocarbon generation for power production. The investigation of the carbonaceous shale from the Permian Mikambeni Formation of the Tuli Basin in South Africa aims to assess the potential for gas generation. The Rock-Eval 6 pyrolysis of the studied samples shows total organic carbon (TOC) content ranging from 10.10 to 37.61 wt%, indicating an excellent source rock quality since it exceeds the threshold limit of 5 wt%. The produced gas that emanated from the thermal breakup of remaining hydrocarbon (S2) ranged from 14.30 to 65.55 mg HC/g rock while the hydrogen index (HI) ranged from 56.55 to 198.22 mg/g TOC. The plot of the HI against T max indicates the predominance of type-III kerogen, prone to gas generation. The thermal maturity parameters, T max (430–466°C), and vitrinite reflectance, VRo (0.6–1.2), showed a matured organic material. The production index value (0.06) of the samples indicates a moderately mature source generating a biogenic gas. The carbon isotopic composition, δ 13C (−20.0 to −23.4‰), indicates a predominant influx of organic matter derived from a vascular higher plant. The studied samples showed relatively depleted values of oxygen isotopic composition δ 16O (14.1–18.8‰), suggesting a brackish water depositional environment. Additionally, the Ba concentration (303.15–331.27 ppm) exceeds the 200 ppm threshold for the marine environment, indicating a non-marine environment characterised by low marine paleo-productivity and high detrital influx. Based on the evaluation, the studied coaly-shale is found with a matured and type-III kerogen that is prone to gas generation in a fluvial, paleo-depositional environment.

Thermal maturity calculation in Type II-S source rocks using the alkyl dibenzothiophenes

Distributions of the alkyl dibenzothiophenes (DBT) are proven as effective proxies for the thermal maturity of bitumen extracts and oils expelled from marine source rocks containing Type II-S kerogen. Here we report on an expanded sample suite and DBT ratios to further refine these relationships. This study investigates the methyldibenzothiophenes (MDBT), dimethyldibenzothiophenes (DMDBT), and trimethyldibenzothiophenes (TMDBT) in 52 source rocks from formations in the United States and the Middle East to substantiate the reliability of these sulfur-bearing compounds to estimate maturity in Type II-S samples. The isomerization of MDBTs, DMDBTs, and TMDBTs shows strong correlations with pyrolysis data (Tmax, hydrogen index, and equivalent %VRo), enabling a direct calculation of thermal maturity from the ratios of the MDBT homologous series. Maturity indicators from biomarkers and other ancillary compounds are also analyzed to highlight the limitations and inconsistencies that can be observed when applying such methods to assess the maturity of Type II-S samples. The derived MDBT, DMDBT, and TMDBT maturity equations provide a reliable assessment of maturity for Type II-S samples, ranging from the immature window to the end of the condensate/wet gas window. Moreover, evaluation of 18 sulfur-rich oils validates the application of MDR maturity equations to fluid samples. Such flexibility allows for inclusive, yet consistent, maturity assessment in sulfur-rich formations when compared to other molecular maturity proxies.

Modeling competitive adsorption and diffusion of CH4/CO2 mixtures confined in mature type-II kerogen: Insights from molecular dynamics simulations

In this study, the adsorption and competitive diffusion of methane (CH4) and carbon dioxide (CO2) mixtures through a molecular model of mature type-2 kerogen was investigated using molecular dynamics simulations. The Dual Control Volume-Grand Canonical Molecular Dynamics method was used to analyze the system and the results were focused on the selectivity of kerogen towards mixtures under a wide range of thermodynamic conditions. The results showed that the adsorption selectivity of CO2/CH4 was around 2–4 and decreased with temperature in the range 350–450 K. The Extended Langmuir (EL) model was found to underestimate the selectivity, and a correction was proposed in the form of the Corrected Extended Langmuir (CEL) model, which improved the estimations of the adsorption of CH4/CO2 mixtures in kerogen with only one adjustable parameter independent of thermodynamic conditions. Interestingly, we noticed that, out of equilibrium, the adsorption selectivity was not affected by the flow conditions when a pressure gradient was imposed, and the CEL model can thus be used to describe the contribution of adsorption to the selectivity under flow conditions. The results showed that the ratio of the collective diffusion coefficients of CH4 and CO2 was around 0.3−0.4, which was about two times lower than other simulations found in the literature. To describe the global selectivity, a simple approach combining the CEL model and the average ratio of diffusion coefficients was proposed, resulting in a selectivity of around 1.

Integration of petrophysical and geochemical approaches for lower Miocene Euphrates and Jeribe Formations in selected wells in Tawke Oil Field, Northwestern Iraq, Zagros-fold belt

The Lower Miocene Euphrates and Jeribe Formations are among Iraq's potential reservoirs with significant proven reserves. Petrophysical and geochemical techniques were used to investigate these Formations in the recently discovered Tawke Oil Field. Investigation consisted of acquiring a considerable amount of data from eight wells including conventional core analysis, wireline logging data, gas chromatography data and formation water analysis. The Euphrates and Jeribe Formations are considered to have low to moderate porosity (avg. 2.7–20.5%) and low matrix permeability (avg. 0.87–15mD). Secondary porosity is more prevalent than primary depositional porosity and is a significant factor in optimal reservoir properties with an average of 3.7–5.4% Secondary Porosity Index (SPI) for Jeribe and Euphrates Formations respectively. Meanwhile, fractures increased matrix permeability by up to 33mD and 56mD in the Euphrates and Jeribe Formations respectively. Lithology and core analysis revealed that the Dhiban Formation is a non-reservoir rock with maximum 2% He-Porosity and 0.069mD Klinkenberg permeability confirming that the formation is insufficient as a hydrocarbon reservoir, and that the rock properties are primarily controlled by the depositional environment. The Jeribe Formation contains crude oil of intermediate gravity and high sulfur content. According to gas chromatograph analysis the liquid and oil extracted from the Jeribe Formation originated from a matured marine setting that was possibly algae rich (Type-II kerogen) and has been deposited in a reductive environment. It is believed that these hydrocarbons were sourced from the Middle Jurassic Sargelu and Upper Jurassic-Lower Cretaceous Chia Gara Formations. The chloride-calcium water class is determined from the produced water in the Jeribe Formation and the concentration of elements with dissolved salts confirmed that the Jeribe Formation is in contact throughout eight Tawke wells studied.

Early porosity generation in organic-sulfur-rich mudstones

High total organic sulfur (TOS) content (i.e., Type IIS kerogen) is well known to significantly influence kerogen transformation but the effect of TOS content on the evolution of organic porosity has only rarely and indirectly been investigated. This study demonstrates that organic porosity is generated at lower thermal maturity in mudstones containing Type IIS kerogen relative to those with Type II kerogen. To our knowledge this phenomenon has not been previously demonstrated. The implications are relevant for the characterization of organic-rich mudstones as cap rocks, hydrocarbon reservoirs, and disposal reservoirs for CO2 or nuclear waste because pore systems control storage volumes and matrix fluid flow. Five thermally immature core samples were selected from three organic-rich mudstone units with low to high TOS content: the late Devonian Duvernay Formation (Canada), middle late Miocene Onnagawa Formation (Japan), and early Jurassic Gordondale member of the Fernie Formation (Canada). Hydrous pyrolysis was used to artificially mature splits of the immature samples to four maturity stages, upon which petrophysical and organic geochemical properties were measured and compared to baseline immature samples. Most porosity growth in Type IIS samples occurred below 0.70% VRoeqv, but in Type II samples was broader and robust until 1.1% VRoeqv.

Spectral narratives of microstructural restyling and their controls on hydrocarbon generation potential from coal

The low to medium-rank Tertiary coals from Meghalaya, India, are explored for the first time for their comprehensive microstructural characterization using the FTIR and Raman spectroscopy. Further, results from these coals are compared with the Permian medium and high-rank coals to understand the microstructural restyling during coalification and its controls on hydrocarbon generation. The coal samples are grouped based on the mean random vitrinite reflectance values to record the transformations in spectral attributes with increasing coal rank. The aliphatic carbon and the apparent aromaticity respond sharply to the first coalification jump ({bar{rm R}}r: 0.50%) during low to medium-rank transition and anchizonal metamorphism of the high-rank coals. Moreover, the Raman band intensity ratio changes during the first coalification jump but remains invariable in the medium-rank coals and turns subtle again during the onset of pregraphitization in high-rank coals, revealing a polynomial trend with the coal metamorphism. The Rock–Eval hydrogen index and genetic potential also decline sharply at the first coalification jump. Besides, an attempt to comprehend the coal microstructural controls on the hydrocarbon potential reveals that the Tertiary coals comprise highly reactive aliphatic functionalities in the type II-S kerogen, along with the low paleotemperature (74.59–112.28 °C) may signify their potential to generate early-mature hydrocarbons. However, the presence of type II-III admixed kerogen, a lesser abundance of reactive moieties, and overall moderate paleotemperature (91.93–142.52 °C) of the Permian medium-rank coals may imply their mixed hydrocarbon potential. Meanwhile, anchizonal metamorphism, polycondensed aromatic microstructure, and high values of paleotemperature (~ 334.25 to ~ 366.79 °C) of the high-rank coals indicate a negligible potential of producing any hydrocarbons.

Comment: Suppression of vitrinite reflectance by bitumen generated from liptinite during hydrous pyrolysis of artificial source rock by Peters et al. (2018)

Peters et al. (2018) provide new hydrous pyrolysis data in defining the coal-reflectance and the suppressed-reflectance trends that source rocks may follow during their thermal maturation. The difference in the two trends is between hydrous pyrolysis temperatures of 300 to 360 °C for 72-hour durations. As implied in their title the suppressed-reflectance of vitrinite is a result of bitumen generation from liptinite during hydrous pyrolysis. Their experimental results do show that coal reflectance is lower when mixed with isolated liptinite encased in G-class Portland cement. However, there are published and omitted experimental data that they did not include in their interpretations. These are addressed as concerns and include early experiments of mixtures of Liptinite in source rocks mixed with coal that do not show a reduced reflectance of the coal. Earlier publications show that some source rocks with oil-prone Type-II kerogens also follow the suppressed-reflectance trend. Resinites did not cause reductions in coal reflectance. The validity of using G-class Portland cement as an artificial rock is not established and is unlikely to be an appropriate representative of natural shales. Reflectance suppression by free radicals are also feasible and more research is needed to better define the causes of the suppression.

Effect of thermal maturation on the isotopic compositions of volatile organic sulfur compounds released from a kerogen by hydrous and anhydrous pyrolysis

Volatile organic sulfur compounds (VOSCs) may provide an alternative and improved approach in the evaluation of source and thermal maturity of natural gas. However, the role of water in the generation and decomposition of VOSCs is still ambiguous. Hydrous pyrolysis experiments were conducted on the isolated type Ⅱ-S kerogen of a source rock collected from the Ghareb Formation, Israel at 200–360 ℃ for 72 h (Easy%Ro = 0.32–1.20). The evolved gases were quantified for C1-C5 hydrocarbons, CO2, H2S and VOSCs. Compound specific isotope analysis were conducted both on the VOSCs and H2S (δ34S), and also on the C1-C5 hydrocarbons and CO2 (δ13C, δ2H). The results show that thiols concentration increased from 200 ℃ to 300 ℃ and then decreased from 300 ℃ to 360 ℃. The formed thiols isotopically co-vary with H2S from 200 ℃ to 340 ℃ and present the opposite trend with H2S from 340 ℃ to 360 ℃. The δ34S values of thiols are usually 3–7‰ lighter than the parent kerogen and 0.5–4‰ heavier than H2S. The concentrations of thiophenes generally increased with thermal stress with peak generation at 360 ℃, the δ34S values of thiophenes are mostly < 2–4‰ lighter than the parent kerogen and 2–8‰ heavier than H2S through the experiments. The δ13C and δ2H values of gaseous hydrocarbons are gradually enriched in heavy isotopes with increased thermal maturity. VOSCs dominated by thiols and thiophenes are generated by two ways: 1. the interactions between H2S and hydrocarbon molecules (synthetic pathway), 2. thermal cracking of OMs including kerogen and associated bitumen primary cracking and hydrocarbon secondary cracking (thermal cracking pathway). The synthetic pathway played the major role in the generation of thiols at the immature and early mature stages (200–300 ℃, Easy%Ro = 0.32–0.71), the cracking pathway has the dominant effect on the occurrence of thiols at higher thermal maturity levels (300–360 ℃, Easy%Ro = 0.71–1.20). The main pathway of thiophenes formation throughout the experiments is by the thermal cracking pathway. In the hydrous experiments, water promotes the synthetic pathway that generated thiols and retarded the thermal cracking pathway that forms thiophenes, but had no significant impact on δ34S values of individual VOSCs, δ13C and δ2H values of gaseous hydrocarbons. Therefore, combining with carbon and hydrogen isotopic compositions of gaseous hydrocarbons, molecular and sulfur isotopic compositions of individual VOSCs in the gas phase can provide valuable clues for petroleum systems in sedimentary basins including gas sources, generation pathways, thermal maturity levels and petroleum secondary transformations, such as thermochemical sulfate reduction in the subsurface reservoirs.

Geochemical investigation of oil seepages and Paleozoic sediments for determining probable source rock in the Bandar Abbas Hinterland

A remarkable characteristic of the Bandar Abbas Hinterland is the frequent presence of oil seepages that can serve as an indicator of probable oilfields in the region. The Seeps A and B are located in the main Zagros Suture Zone, 150 km to the northeast of Bandar Abbas and 30 km to the west of the same city, respectively. The presence of well-known Paleozoic source rocks (e.g., Seyahou, Sarchahan, and Gurpi formations) in the vicinity of the mentioned oil seepages shows that the seeping oil is coming from an oil source. The present research is aimed investigating the petroleum system and determining the source of the mentioned oil seepages. Results of the Rock-Eval analyses showed that the samples of the Seyahou Formation are thermally overmatured, making them exhibit inadequate oil generation potential. These samples contain Type-III kerogen and were found to be in the metagenesis stage. However, compared to other formations, Sarchahan and Gurpi exhibited good hydrocarbon generation potentials. On the other hand, based on the PI – Tmax diagram, the Sarchahan Formation was found to be in the early oil and condensate production window (i.e., catagenesis stage) while the Gurpi Formation was seen to be immature. Biomarker analysis results showed that the samples were deposited in a mixed marine environment and contained Type-II and Type II/III kerogen. The reason behind the occurrence of the oil seepages in an oxidative environment could be the sever impact of the biological degradation. The stable carbon isotope composition of the crude samples supported the biomarker data in general. Therefore, it can be concluded that the studied oil seepages were probably sourced from the Sarchahan Formation.

Mineralogical and geochemical characterization of lacustrine calcareous shale in Dongying Depression, Bohai Bay Basin: Implications for paleosalinity, paleoclimate, and paleoredox conditions

Shale is an important self-sourced reservoir rock in many sedimentary basins worldwide. In this research work, a geochemical history of variations in the sedimentary environment of the lacustrine basin is analyzed based on extensive shale samples collected from the lower 3rd member (Es3L) and upper 4th member (Es4U) of the Paleogene Shahejie Formation in the Boxing Sag (Dongying Depression, East Coast of China). The representative shale samples were analyzed for total organic carbon (TOC) contents, mineralogical composition, the concentration of different elements (major, minor, and trace), kerogen types and vitrinite reflectance (Ro), and different sedimentary structures to understand the evolution of the depositional settings and their effect on the distribution of shale lithofacies in this basin. The TOC content in this shale ranges from 0.08 % to 13.6 %. Ro values range from 0.55 to 1.19 % with type-I to type-II kerogens. The studied shale is composed of calcite (average 37.83 wt%), dolomite (avg. 10.47 wt%), quartz (avg. 23.8 wt%), plagioclase (avg. 3.91 wt%), clay (avg. 20.84 wt%), and pyrite (avg. 2.85 wt%). Seven lithofacies have been established including mixed shale, calcareous shale, laminated limestone, argillaceous shale, dolomitic shale, siliceous shale, and siliceous dolomite based on mineral composition, TOC contents, and sedimentary structures. Different geochemical proxies including Sr/Ba, Ca/Ca + Fe, C-values, CIA values, Ti/Al, Al/Al + Fe, Al/Ti, V/V + Ni, Ni/Co, and Fe/Ca + Mg were used to interpret salinity, paleoclimate, detrital influx, provenance, paleoredox and water depth of the depositional environment in the studied shale. The detailed interpretation of the sedimentary environment suggested that during the deposition of Es3L shale, the terrigenous influx was high in shallow to a deep open lacustrine system with higher primary biogenic productivity. Semi-humid climatic conditions with higher precipitation rates prevailed during the deposition of this shale. On the other hand, relatively limited terrigenous input with low bioproductivity prevailed during the deposition of Es4U shale in the study area. Semiarid to humid climatic conditions with strong evaporation prevailed during the deposition of this shale. In this research work, a detailed depositional model of the Es3L–Es4U shale in Boxing Sag is established. The interpretations deduced from the current research work are likely to expand the knowledge of shale lithofacies and the genesis of lacustrine fine-grained sedimentary rocks, as well as can offer a theoretical foundation for lacustrine shale oil exploration and development.

Petrographic, mineralogical, morphological and organic constraints of the Permian shaly-coal in the Tuli Basin of Limpopo-Area Karoo-Aged basin, South Africa: Implication for potential gas generation

The transition to a low-carbon energy source from coal has become imperative to mitigating the escalating climate change crisis. This study aims to investigate the organic-rich shale core samples of the Limpopo-Area Karoo Basin, retrieved from the borehole at depth 480–580 m. These samples were subjected to petrographic, mineralogical, morphological, and kerogen-type analysis to investigate potentials for shale gas generation. The petrographic analysis reveals maceral group mainly comprised of vitrinite group with some liptinite and inertinite and mineral compositions. The preponderance of pyrite framboids (1.6–12%) indicate redox of FeS2 as a precursor to methane gas generation in anoxic condition. The x-ray diffractometer (XRD) reveals the presence of quartz, albite, microcline, dolomite, pyrite and clay minerals which alluded to the mineral composition indicated by the petrographic analysis. The clay mineral component consists of montmorillonite, illite, chlorite, and mixed layered illite/smectite (I/S) in the Madzaringwe samples. The representative scanning electron microscopy-Energy Dispersive X-ray (SEM-EDX) images of the studied shales depict a combination of organic-matter, groundmass mineral, micro-fracture pore structures reflecting polyframboidal pyrite and carbonate dissolution morphology. The total organic carbon (TOC) contents averaging at 47 wt%, indicating an excellent source rock. The Rock-Eval 6 programmed pyrolysis samples showed S2 value (15.25–16.47 mg HC/g rock) with an average of 15.69 mg HC/g rock and Hydrogen index (HI) (34.0–37.0 mg HC/g TOC) indicating a Type-III Kerogen dominance prone to gas generation. The shale showed Tmax values (464–470 °C) averaging at 467.2 °C, yielding a thermally mature condensate wet-gas. This study reveals that the Permian carbonaceous rock tends to generate gas which can be hosted mainly by the organic matter pore structures, inorganic and micro-fracture pore structures.

Geochemical characteristics of the Rajmahal coals in Dhulia North Block, Eastern India: implication to their utilization and environment.

The borehole coal samples of Dhulia North Block from the Rajmahal Basin, Eastern India, were systematically analyzed based on the chemical composition and concentration of major and trace elements (including rare earth elements, REEs) to assess the distribution of REEs and their environmental implications with utilization potential. TheDhulia North Block coals are characterized by the predominant majoroxides of SiO2, Al2O3, and Fe2O3, accounting for 94% of the total ash composition, indicating the presence of quartz, clay-rich minerals, and pyrite. Compared with the average world coal ash, the total REE content in the analyzed samples ranged from 341.0 to 810.4ppm, which is substantially higher. Hot humid climate conditions with intermediate igneous source rocks of the basin were demonstrated by the major oxide ratios (Al2O3/TiO2 < 20) and plots of TiO2 with Al2O3 and Zr. The redox-sensitive elements such as V, Ni, Cr, and Co found in the Dhulia North Block coal indicate that an oxic sedimentary environment existed in the basin when coal was formed. The low sulfur content (1% in most samples) indicates freshwater conditions in the basin at the time of organic matter deposition. The outlook coefficient (Coutl) varies between0.7 and 1.6, indicating that the Dhulia North Block coals are a prospective source of REEs. The Dhulia North Block coals are characterized by low H/C and O/C atomic ratios ranging from 0.56 to 0.90 and 0.10 to 0.22, respectively, and contain type-III kerogens, indicating gas-prone source rock. Further, the basic-to-acid oxide ratio suggested that Dhulia North Block coals were suitable for utilization during combustion processes.

GEOCHEMISTRY OF POTENTIAL SOURCE ROCK AND NATURAL GAS SEEPAGES IN THE MANGOLE-TALIABU ARCHIPELAGO, NORTH MALUKU, INDONESIA

The Mangole-Taliabu Archipelago has great potential for natural gas exploration due to its many active natural gas seepages. The limited natural gas exploration activities initiated during the last three decades led to a lack of publications on source rock and natural gas geochemistry. Previous research has postulated that the potential source rocks in this area and its surroundings are the Buya and Salodik formations, and known active natural gas seepages are hypothesised to originate from humic organic matter (type-III kerogen). The research aims to review and re-discuss the geochemical characteristics of potential source rock, the origins and genetics of natural gas seepages, and the correlation between natural gas seepage and source rocks by integrating the existing data with the newly collected data. This research revealed that the potential source rock is the Bobong Formation, aside from the previously confirmed Buya Formation, while the Salodik Formation is not a potential source rock as was suggested in previous publications. The most significant research finding is the type of natural gas seepage which found not only coal-derived gas but also oil-type gas. The calculated Ro of the coal-derived gas source rock is 0.80% – 1.00% and that of oil-type gas source rock ranges between 0.50% – 1.31%. For gas–source rock correlation, the Bobong Formation appears to be the most likely source for RAG/88/012 and RAG/88/014 gas samples, while the Buya Formation is the source for Binono Seep, RA/21/33, RA/21/34, and RA/21/35 gas samples. The new research findings are hoped to have significant implications for increasing the understanding of the petroleum system and encouraging further exploration activities.

Evolution of electrical resistivity and NMR during early-stage maturation of an organic-rich chalk

This paper studies the changes in the electrical resistivity of an organic-rich source rock chalk containing a Type-IIs kerogen during early-stage maturation of the kerogen. As bitumen is generated during maturation, the chalk changes from water wet to a complex mixed-wet pore system, with the micritic pore space remaining water wet while the bitumen expelled into the macro pores converts some pores to oil wet. This mixed-wet system results in non-Archie electrical behavior with pronounced curvature of the I-Sw curve. We find that this curvature is well fit by connectivity theory. The connectivity theory parameters are determined both on native state core and from artificial laboratory pyrolysis which generates bitumen. NMR is used to distinguish the brine in micritic, water-wet pore spaces from that in the intergranular, mixed-wet pore spaces, from which the observed connectivity parameters may be independently estimated. Comparison between electrical resistivity and dielectric logs show that the connectivity parameters match the laboratory results over a calcareous section more than 300 m thick.