Petroleum Source Rocks Research Articles

Organic petrologic and geochemical characterization of petroleum source rocks in the Middle Jurassic Dameigou Formation, Qaidam Basin, northwestern China: Insights into paleo-depositional environment and organic matter accumulation

The organic matter-rich mudstones of the Middle Jurassic Dameigou Formation in the northern Qaidam Basin are regarded as the principal petroleum source rocks for unconventional resource exploration in China. In this study, a detailed investigation on the organic petrography, inorganic geochemistry as well as bulk and molecular organic geochemistry is presented. Three different source rock units were identified with TOC contents and VRr ranging from 1.5–39.2% and 0.35–0.57%, respectively. Carbonaceous mudstone and organic matter-rich mudstone in unit 1 with high Pr/Ph (4.79–7.25) and low Gam index (0.02–0.03) values mainly developed in an oxic freshwater column under warm and humid climatic conditions and strong weathering intensity. Organic matter in unit 1 with high proportions of C29 ααα 20R steranes (61–74%) is interpreted to be derived from terrestrial higher plants. By contrast, units 2 (Pr/Ph: 2.56–4.23; Gam index: 0.03–0.14) and 3 (Pr/Ph: 0.73; Gam index: 0.48) were deposited in sub-oxic to oxic freshwater and anoxic saline environments, respectively. Progressive aridification during the deposition of units 2 and 3 are reflected by decreasing CIA values (59.97–86.68) resulting in weakened weathering intensity and lower terrestrial influx. A mixture of terrestrial higher plants and algal biomass was the main source of organic matter in unit 2 with moderate C19/C23 Tri (0.96–5.44), C20/C23 Tri (1.28–3.87) and C24 Tet/C26 Tri (1.10–2.54) ratios, while unit 3 with the lowest C19/C23 Tri (0.25), C20/C23 Tri (0.95), and C24 Tet/C26 Tri (0.65) ratios and highest proportions of C27 ααα 20R steranes (69%) is characterized by a decrease in terrigenous organic matter content. The dominant source of organic matter is lake plankton, including halophilic algae and cyanobacteria. Organic matter accumulation in unit 1 is associated with a warm and humid climate, weathering intensity, and terrigenous organic matter input. Primary productivity is the most important factor controlling the enrichment of organic matter in units 2 and 3.

Organic matter enrichment in a terrestrial-marine transitional environment driven by global/regional climate recorded in the Upper Permian succession from the Qiangtang Basin, northern Tibet

Compared to organic matter (OM) accumulation in marine environments, OM enrichment mechanism in terrestrial-marine transitional environments remain unclear. The Late Permian was an important coal-forming period in China. Late Permian coal-bearing mudstones are important petroleum source rocks in the Qiangtang Basin. In this study, the coal-bearing rocks in the Late Permian Nayixiong Formation from the Qiangtang Basin are selected to address OM accumulation process in transitional environments. Our work demonstrates three-stage climatic changes during the deposition of coal-bearing sedimentary rocks: stages I, II and III, corresponding to a semi-warm and semi-humid climate, warm and humid climate, and cold and arid climate, respectively. Based on degree of pyritization (DOP), enrichment factor (EF) of elements, the Late Permian coal-bearing rocks were deposited under oxic-dysoxic environments. Low excessive barium (Baxs) and biogenic silica (Sibio) contents in the coal-bearing rocks indicates a low primary productivity. We suggest that warm and humid conditions, freshwater and terrestrial plants input are the primary factors controlling OM accumulation during the Late Permian coal-bearing deposition. We summarized a global/regional climate-driven model for OM accumulation in transitional environments. The warming climate created a habitable environment for both terrestrial and marine organisms. Subsequent freshwater input brought abundant nutrients and terrestrial OM to the aqueous system to build high OM accumulation.

Controls on generation and accumulation of blended gases (CH4/H2/He) in the Neoproterozoic Amadeus Basin, Australia

Various gases are generated in the subsurface, by diagenetic processes, fluid/rock interactions, maturation of petroleum source rocks and microbial activity. Often these gases just leak at the surface but sometimes they may accumulate in a subsurface trap. The present study investigates the case of the southern part of the Amadeus Basin, Australia, where exploration wells tested a blend of hydrocarbon (HC), helium (He) and hydrogen (H2). In Mt Kitty-1 well, He- and H2-rich gases were reported (He ∼9%, H2 ∼11.4%) with traces of HC, whereas C1 and C2+ HC gases associated with He were discovered in Magee-1 well. Seismic and well data elucidate accumulation of the gas blend within a classical subsurface system with a structural trap, a permeable reservoir and a thick salt layer as seal. This salt, the Proterozoic Upper Gillen, is overlying the Heavitree sandstones and fractured basement reservoirs. The former is dominated by intergranular porosity (∼13%), whereas the latter is commonly associated with complex patterns of fractures associated with deep-seated faults. The sources of blended gases are different: thermal cracking of organic matter for hydrocarbons, radiolytic decay of radioelements for helium. Radiolysis, and water reduction as well as oxidation of hydrocarbons are open hypothesizes for H2 generation in the study region. Neoproterozoic and Early Paleozoic tectonic episodes (e.g. Petermann; Alice Springs) allowed the formation of various structural traps where the gas blend was accumulated.The large quantity of He, light gas slowly generated by the crustal radioactivity indicates that the seal is very efficient and that accumulations could have been in place for millions of years very likely with an evolving CH4/H2/He ratios through time. The presence of gas chimneys and surface depressions in the basin indicate that the generation, and/or migration of the gases are still active. All the data are consistent with a long-term accumulation of this gas blend, different from the short term H2 retention in the reservoir that was proposed in other contexts such as in Mali.

Depositional environment and petroleum source rock potential of Mesozoic lacustrine sedimentary rocks in central Mongolia

Middle Jurassic (five samples from one location) and Lower Cretaceous (thirty-two samples from eight locations) lacustrine sedimentary rocks of central Mongolia were studied to determine their depositional environments and petroleum source rock potential. The Middle Jurassic shale contains sufficient organic matter (OM) with Type II/III kerogen to represent a mixed oil and gas potential source rock. Tmax and biomarker maturity indices suggest a thermally immature level. Pristane/phytane and the gammacerane index indicate that the shale accumulated in an oxic, freshwater environment. Terrigenous OM with input from algae and macrophytes was a major contributor as indicated by long-chain n-alkanes and the abundance of C29 regular steranes. The stable carbon and nitrogen isotope compositions and kerogen types agree with land plant derived OM. Lower Cretaceous shales are highly oil-prone but thermally immature, reflected by Rock-Eval data and biomarker parameters. Carbon preference index (CPI), n-alkane distributions, and C27/C29 ratios suggest that OM in Lower Cretaceous shales is a mixture of phytoplankton, macrophyte, and land plant. The contribution from algal OM is variable. Lower Cretaceous shales were deposited in stratified lakes with anoxic bottom waters and the salinity of paleolakes was variable, indicated by Pr/Ph and the gammacerane index, respectively. Organic geochemical characteristics and depositional environments of Middle Jurassic and Lower Cretaceous sedimentary rocks studied herein are similar to those of Jurassic source rocks in western Chinese basins and Lower Cretaceous source rocks in eastern Mongolian basins, respectively.

Geochemistry of Formation Water and Its Implications for Petroleum Source Rocks in the Fengcheng Formation, Mahu Depression, Xinjiang, China

Geochemical properties of formation water reflect the sedimentary environments and the sealing conditions of the formation, which are of great significance for oil and gas exploration. In this research, the formation waters in the deep Permian Fengcheng Formation in the Mahu Depression were studied by analysis of chemical composition, stable isotopes, and the homogenization temperatures and salinities of fluid inclusions. The results show that the formation water is NaHCO3-type with high salinity, high HCO3-, low concentrations of Ca2+ and Mg2+ and high pH. The overall sealing of the formation is well maintained. Na2SO4-type water was found in some places with poor preservation of oil and gas. The fluid geochemistry and alkaline mineral distribution in the strata, which are dominated by deep fine-grain mixed deposits, indicate that the main body of the Fengcheng Formation was deposited in an alkaline lake sedimentary environment. The isotopic signatures are characterized by high δ13C, negative δ18O, and light strontium and heavy boron isotopes in the strata near the deep fault zone, which indicate that the Fengcheng formation may have been affected by deep hydrothermal fluids. From the first member to the third member of the formation, the salinity first increases and then decreases. This low-high-low trend corresponds to the initial stage of alkaline lake development followed by strong alkali formation and a final stage of water retreat. The coincidence between the spatial distribution of alkaline minerals, high-salinity formation water and source rocks indicates that the alkaline lake environment can form high-quality source rocks with good petroleum generation capacity.

Geochemistry and organofacies characteristics of organic-rich chalky marl deposits, northern Jordan: Insights into Type II-S source rock

This study deals with organic matter in chalky marls of the Wadi Shallala Formation in northern Jordan. We report geochemical analyses (Total organic carbon, programmed pyrolysis, bitumen extraction, and pyrolysis–gas chromatography) for the chalky marls from 17 samples to provide information on the quantity, quality, the thermal maturity of the organic matter, their potential as petroleum source rocks. The chalky marl samples contain a significant amount of total organic carbon (TOC, max = 6.53%) and hydrogen index (HI) ranging from 300 to 702 mg HC/g TOC. The organic facies are mainly Types-II and -I kerogen with a potential to generate high amounts of oil. The dominance of such kerogen is consistent with significant amounts of fluorescent alginite macerals, observed under ultraviolet light microscopy. These organic facies are also confirmed by the Py-GC investigation, showing sulfur-rich Type II-S kerogen. The presence of weak carbon–sulfur (C-S) bounds in the kerogen molecules, however, suggests the generation of sulfur-rich oil at the early stages during the oil-generation window as reported by earlier works. Both geochemical maturity indicators (i.e., Tmax and PI) and the fluorescence color of the liptinite macerals indicate that the studied chalky marls in the outcropped section of the study area are still thermally immature, and maturity did not alter the organic-rich intervals to generate suitable oil for commercial production. Therefore, these organic-rich sediments in the locations having relatively deeper stratigraphic sections are likely to be promising source rocks and recommend for petroleum exploration and production in northern Jordan.

The Shahejie Formation in the Dongpu Depression, Bohai Bay Basin, China: Geochemical investigation of the origin, deposition and preservation of organic matter in a saline lacustrine environment during the Middle Eocene

The Eocene Shahejie Formation in the Bohai Bay, Eastern China is known to contain important petroleum source rocks. Here, a new, large set of geochemical, petrographical and mineralogical data obtained on 41 samples from 9 wells within the North Dongpu Depression is presented in order to investigate organic matter precursor material, thermal maturity as well as paleoenvironment during deposition of the Es3U, Es3L, Es3M and Es4U members within the Eocene Shahejie Formation. These shales and marlstones from the four sub-members show low to moderate TOC contents (up to 5%) with highest values in the Es3U member; quartz content is at about 10% and carbonate content is variable, partly reaching more than 40%. A range of different maturity parameters was determined indicating early mature to peak oil mature stages, and maturity increase with burial depth. Throughout, alginite is the predominant maceral, whereas both vitrinite and inertinite are rare. Hydrogen index values are highly variable, ranging from about 100 to 700. Distinctly different biomarker assemblages indicate variable depositional environments and organic matter inputs between the four intervals. The Eocene Shahejie shales and marlstones in the study area were deposited under episodic photic zone anoxia as revealed by the presence of aryl isoprenoids. Bottom water conditions were anoxic during most of the time, except for Es3M, as indicated by several parameters, e.g. low pristane/phytane ratios. In north Dongpu Depression Es4U displays a fairly uniform biomarker composition, which indicates relatively stable hypersaline lake conditions with a shallow chemocline based on the high Gammacerane Index > 0.6 and abundant aryl isoprenoids. Water salinity changed during deposition of Es3L according to variable C24 tetracyclic terpanes related parameters and evaporite minerals content. The aquatic algal organisms, i.e. haptophyte algae, diatoms and bryophytes which are reflected by abundant nC37–39 alkanes, a variable sterane pattern and other biomarkers, were flourishing during Es3L. Additionally, specific PAHs, i.e. retene, cadalene, fluoranthene, indeno[1,2,3-cd]pyrene and benzo[ghi]perylene also have been identified in small concentration in Es3L, which may be attributed to limited terrigenous organic matter input. Es3M was deposited in a normal lacustrine environment under rather low salinity conditions with substantial input of organic matter derived from algae. During Es3U, saline lake conditions were re-established accompanied by input of both algal and microbial organic matter, especially cyanobacteria as deduced from MMAs and 2α-MeHs, methanogens as deduced from abnormally abundant phytane, PMI, squalane, and methanotrophs from 3β-MeHs.

On the question of petroleum source rocks (modern aspects of the sedimentarymigration theory of naphthydogenesis)

Natural processes contradictive to the common organic (sedimentary and migrational) theory of oil formation were concluded to take place based on the study of the hydrocarbons-biomarkers distribution regularities at the molecular level in the dispersed organic matter of rocks, petroleum and kerogen thermolysis products.Here specific examples of the generation of oil (concentrated organic matter) directly in the reservoir, i.e. reduced scheme of naphthydogenesis, excluding the process of migration were presented. At the same time, these examples do not exclude the migration of organic matter from the «oil source strata», but are an exception that confirms the general rule. It was shown that the study of organic matter, organic carbon (TOC), chloroform-soluble bitumen, pyrolysis “Rock-Eval”, etc., necessarily supporting the conclusions with data from a detailed study of the hydrocarbon composition at the molecular level.

Maturation and migration processes in intact source rock micro plugs induced by chemical and thermal treatment: A new approach combining Rock-Eval pyrolysis and organic petrography

This study proposes a new approach to investigate hydrocarbon generation and migration processes in petroleum source rocks under laboratory conditions. For the first time, programmed open-system pyrolysis using a Rock-Eval 6 instrument is applied on small, polished source rock plugs to induce changes in the type and distribution of solid bitumen, which are qualitatively investigated by means of organic petrography before and after different pyrolysis experiments. This approach allows us to directly visualize the evidence of solid bitumen (SB) formation and distribution after the following treatments: (1) thermal extraction at 300 °C for 3 min, (2) chemical extraction of the surface using dichloromethane (DCM), and subsequently (3) artificial maturation by applying the standard procedure of Rock-Eval programmed pyrolysis up to a temperature of about 400 to 500 °C (depending on the initial thermal maturity of the sample). After each step, the surface of the treated micro plugs was digitally scanned to allow a comparison of specific areas of interest before and after the respective treatments and alterations. For this study, core samples of the Eagle Ford Shale Formation are used, which are suitable for such investigation, as the Eagle Ford Shale exhibits a variety of different initial thermal maturities from immature to overmature. Furthermore, the presence of large intraparticle porosities provides suitable voids where changes in SB distribution can easily be observed. After the thermal extraction, the volume of observed SB in the early- and moderately mature samples slightly increased, while most of the thermally mobilized bitumen from inside the plug was evaporated and thus lost from the sample. The initial solid bitumen was not or hardly affected by thermal extraction at 300 °C for 3 min, i.e. it was thermally stable at this temperature. Solid bitumen reflectance was slightly higher than in the initial sample showing a minor maturation. In contrast to thermal extraction, solid bitumen in the early mature samples was almost completely dissolved after DCM treatment. These petrographic observations on micro plugs are in agreement with the pyrolysis results of powdered fractions, where the initial Rock-Eval S1 and to a much lesser extent also the S2 signal decreases after the chemical extraction in DCM. While the SB in early mature sample was almost entirely dissolved by DCM, only about half of it is was dissolved in the moderately mature sample showing more mature and more stable SB. After the artificial maturation, the volume of SB in early- as well as in moderately mature samples clearly increased within the intraparticle pores, indicating presence of new SB due to bitumen migration from the deeper part of the micro plug to the surface. In contrast, SB in initially overmature sample is mainly present as thermally-highly stable pyrobitumen, indicated by no change in the SB distribution after chemical and thermal treatments representing a stable type of SB at the very end of petroleum generation.

The Occurrence of Bedding-Parallel Fibrous Calcite Veins in Permian Siliciclastic and Carbonate Rocks in Central Thailand

Bedding-parallel fibrous calcite veins crop out at two Permian carbonate localities in the Phetchabun area, central Thailand, within the Nam Duk and Khao Khwang Formations. Samples are studied to determine their petrographic, geochemical and isotopic character, depositional and diagenetic associations and controls on the formation of fibrous calcite across the region. Biomarker and non-biomarker parameters are used to interpret organic matter sources in the vein-hosting units, the depositional environment and levels of source rock maturation in order to evaluate source rock potential in the two Formations. Carbon and oxygen isotope values of the veins and the host are determined to discuss the source of carbonates and diagenetic conditions. The petroleum assessment from the Khao Khwang and Nam Duk Formations suggests that both Formations are a petroleum potential source rock with type II/III kerogen deposited in an estuarine environment or a shallow marine environment and a slope-to-basin marine environment or an open marine environment, respectively. The bedding-parallel fibrous calcite veins from the Khao Khwang and Nam Duk Formations are divided into two types: 1) beef and, 2) cone-in-cone veins. The carbon and oxygen isotope compositions from the fibrous calcite veins suggest that the calcite veins could be precipitated from a carbon source generated in the microbial methanogenic zone. The results in this study provide a better understanding of the interrelationship between the bedding-parallel fibrous calcite veins and petroleum source rock potential.

Evaluation of Petroleum Source Rock Using Well Logs in the Niger Delta Region of Nigeria

Petroleum source rock potential evaluation was carried out on eight wells of the Niger Delta’s Agbada Formation by assessing some source parameters from well logs and through well logs analysis based on organic matter effect and relationship on and with well logs. Source rock determinant parameters such as volume of shale (Vsh), total organic content (TOC), and amount of generated hydrocarbon (S2) was derived from well logs following established organic matter effects on well logs using Schlumberger's Techlog 2015 software, while hydrogen index (HI) was calculated using known values of TOC and S2 respectively. Well log data used for the analysis includes GR log, resistivity, sonic and Density logs. Apart from deriving source rock parameters, the well logs were also used to identify, quantify and somewhat determine mature zones of source rock intervals by correlation with TOC, S2, and HI source parameters respectively, Therefore, a source interval criterion composing of high GR log, high resistivity, high sonic and low-Density was developed alongside source rock parameters. Results of the analysis in the area show poor to fair source rock quality rating in terms of TOC, and insufficient source rock thickness fit for sustaining a world-class petroleum province like the ND petroleum province and further depicting that the Agbada FM may not be the principal source rock of the area. It is, therefore, recommended that more elaborate studies covering greater depths of the Agbada FM be carried out in other to properly represent the true source quality of the area.

Biomarkers in Source Rocks from Barreirinha Formation (Devonian): Distribution and Paleoenvironment Significance

The Barreirinha Formation-Upper Devonian, is the main petroleum source rock of the Amazon Basin, deposited during the great Devonian Transgression, contributing to significant accumulations of organic matter (OM) in anoxic conditions, which allowed its preservation. The present work had the objective of characterizing the molecular composition of biomarkers in outcrops samples of the Barreirinha Formation, aiming to evaluate the paleoenvironment, thermal evolution, and the preservation of OM total organic carbon (TOC) and Rock-Eval pyrolysis indicate considerable amounts of immature OM deposited in a low oxygenation environment. Gas chromatographymass spectrometry (GC-MS) and gas chromatography-tandem mass spectrometry (GC-MS/MS) data corroborate that the OM was deposited in a suboxic to the oxic environment and low salinity (absence or low relative abundance of β-carotane and gammacerane). 24-N-Propyl-cholestane was detected and identified by synthetic pattern co-injection. High concentrations of tetracyclic polyprenoids (TPPs) in ascending order from base to top, high hopane/sterane ratios, to suggest that the samples had a high molecular weight n-alkanes, C29 steranes, low thermal evolution, and anoxic depositional paleoenvironment.

Paleoenvironmental conditions and organic matter enrichment of the Late Paleoproterozoic Cuizhuang Formation dark shale in the Yuncheng Basin, North China

The Paleoproterozoic dark shale of the Cuizhuang Formation is the potential petroleum source rock in the Yuncheng Basin. Mineralogy, organic and inorganic geochemical analysis were applied in this study to evaluate the sedimentary paleoenvironments and its factors that control the enrichment of organic matter and to reconstruct the organic matter accumulation model of the Cuizhuang Formation dark shale. Quartz and clay minerals are the most abundant minerals in the Cuizhuang Formation dark shale. The TOC content of the dark shale is relatively fair, ranging from 0.13% to 1.09% and averaging of 0.51%, with the organic matter having a high thermal maturity (mean of 2.24 Ro%) and type I kerogen. The Cuizhuang Formation shale was deposited in a passive continental margin setting, and the climate was under moderate warm and humid conditions with low salinity of seawater as evidenced by the proxies of chemical alteration index (CIA) and Sr/Ba. The paleoproductivity proxies Ba bio , Ba%, Ba/Al, P 2 O 5 and P/Ti indicate low productivity with negative and no correlations with TOC content and thus didn't control the organic matter enrichment. The low productivity may have significantly played a role in limiting the organic matter formation resulting in relatively low TOC content. The anoxic redox environment of the dark shale is indicated by the proxies of V/(V + Ni) and V/Sc, with strong positive correlations of V and V/Al with TOC. The anoxic redox environment in deeper waters and a higher sedimentation rate than the grey and red shale played the main role of enriching the organic matter of the dark shale. Therefore, the Cuizhuang Formation dark shale in the Yuncheng Basin is regarded as a potential source rock, holding promise for petroleum exploration. • Paleoenvironment and its relationship with organic matter enrichment was revealed. • Low productivity resulted in low TOC content of the Cuizhuang Formation shale. • Reducing environment and higher sedimentation rate contributed to the organic matter enrichment of the dark shale. • The accumulation model of the dark shale organic matter in the Cuizhuang Formation was established. .

Influence of Quaternary glaciations on subsurface temperatures, pore pressures, rock properties and petroleum systems in the onshore northeastern Netherlands

AbstractPleistocene glacial stages were implemented into a 3D basin and petroleum systems model of the northeastern Netherlands to address the influence of low surface temperatures and the mechanical loading of ice sheets on the subsurface. Two ice sheet thickness scenarios were used based on published data. Overall, Quaternary glacial stages have a substantial impact on the temperature and pressure distribution in the subsurface. Subsurface temperatures are significantly reduced during glacial stages, leading to lowered present-day temperatures and a low geothermal gradient in the shallow subsurface. In deeply buried sedimentary formations, pressures build up with every glacial advance resulting in overpressures at the present day. Glacial stages do not directly influence the petroleum generation of petroleum source rocks in the area, but high pressures during loading might have impacted petroleum expulsion of the early mature Coevorden Formation. Hydrocarbon accumulations in the Lower Saxony Basin were simulated to investigate the possible effects of mechanical ice loading and unloading on hydrocarbon migration. A loss of Coevorden Formation-sourced hydrocarbons to the surface was calculated in the Lower Saxony Basin during the glacial stages, indicating an influence of glacial loading on the Mesozoic petroleum system.

Source Rock Generation Kinetics from Routine Rock-Eval Pyrolysis Data for Heterogeneous Petroleum Source Rock Units of the Upper Ordovician Strata in Southern Ontario, Canada

Source Rock Generation Kinetics from Routine Rock-Eval Pyrolysis Data for Heterogeneous Petroleum Source Rock Units of the Upper Ordovician Strata in Southern Ontario, Canada

Source rock pyrolysis and bulk kinetic modelling of Miocene sedimentary sequences in southeastern Sabah, Malaysia: The variability of thermal maturity to oil-gas producing kerogen

The study reports a new organic geochemical evaluation for a petroleum source rock in the Southeastern (SE) Sabah basin. The analyses focus on Kalabakan, Tanjong, and Kapilit Formation deposited in the deltaic-shallow marine environment stratigraphically from the Early to Late Miocene sequences. The basin sediments are part of the hydrocarbon prolific Tarakan basin, extending from the northernmost of Kalimantan Indonesia to the southeastern Sabah (mainly onshore area). The hydrocarbon generation of Kapilit and Tanjong Formation pinnacles the Total Organic Carbon (TOC) contents that range from 0.62 to 81.97 wt% and 0.97–92.96 wt% respectively. The dominant black shale in Kalabakan Formation has lower TOC content between 0.50 and 1.82 wt%. The results in the Rock-Eval S2 of Kapilit (0.31–351.61 mg HC/g rock) and Tanjong Formation (3.32–239.78 mg HC/g rock) have excellent source rock potential compared to the Kalabakan Formation (0.12–1.19 mg C/g rock) with fair to good source rock potential. All three formations give a wide maturity range of vitrinite reflectance (VRo) and Tmax values, from immature to over-mature stage. Stratigraphically from youngest to oldest Miocene sequences, the Tmax increases with increasing VRo values. The dispersion of organic matter that requires high maturity and overburden of thick upper succession over Kalabakan Formation reflects a higher maturity stage than the Tanjong and Kapilit Formations. Pyrolysis results in Kapilit, Tanjong, and Kalabakan Formation has HI values to varies between 50 and 498 mg HC/g, 157–367 mg HC/g and 14–110 mg HC/g TOC respectively. The binary plot of HI versus Tmax supported by Py-GC pyrolysis marks that the Kapilit source rock is dominated by Type II-III kerogen, potentially generating immature to mature oil and gas prone. Tanjong Formation portrays a mature to late mature stage of Type III kerogen with a minor Type II kerogen capable of producing mixing of oil and gas prone, with mainly gas. The Kalabakan Formation shows a post-mature Type III and IV kerogen that generates gas or barren source rock. In terms of bulk kinetic evaluation, both Kapilit and Tanjong Formation are derived from heterogeneous organic matter. The projected petroleum temperature varies substantially due to the compositional variation. The onset of bulk petroleum generation in the Kapilit and Tanjong Formation occur at 112 °C - 128 °C and 127 °C - 142 °C respectively. The results are consistent with the maturity generated where the Tanjong has higher thermal maturity than Kapilit Formation due to stable aromatic Type III kerogen. Generally, all samples show great variability in thermal maturity and hydrocarbon generation potential, which that be influenced by the tectonism and development of sediments in the basin. The Early Miocene source rock yields post mature gas prone and continues to generate hydrocarbon that consists of mature oil and gas prone from younger source rocks.

Potential of petroleum source rock brines as a New Source of Lithium : Insights from basin-scale modeling and local sensitivity analysis

The demand for lithium (Li) has greatly escalated during the past decade and is predicted to increase continuously with the market growth of the electrified transportation and renewable energy, given that Li-ion batteries are the major energy storage method for these sectors. In spite of the urgent need of satisfying the increasing demand of Li, sources of global Li production have been limited in continental brines and pegmatites. In the line with the effort to enhance and diversify the sources of Li supply, this study seeks to predict the production potential of Li from a new source—petroleum source rock brines—and evaluate the most influential factors affecting it. This subject matter is addressed by basin-scale numerical simulation combined with local sensitivity analysis. The numerical simulation with a conceptual model of petroleum source rock system addresses the accumulation of Li in various locations, by taking account for the release of Li from kerogen decomposition reaction in organic-rich source rock, and fate and transport of expelled Li as interacting with reservoir rock. In combination with the numerical simulations, the impacts of various parameters on the Li mass fraction in brines at various observation points are quantified, by conducting local sensitivity analysis. It elucidates the relative sensitivity of Li production potential to the parameters of Li stoichiometry in kerogen decomposition reaction, Na–Li equilibrium coefficient, Na–clay mass fraction in solid phase, Li–clay mass fraction in solid phase, and Na ion mass fraction in brines. Our results provide the conceptual information of most important parameters to be investigated to quantitatively predict the Li production potential from brines at various locations in the petroleum source rock systems that can be used to contribute to the enhancement and diversification of the Li supply.

Organic geochemical and petrographical characteristics of the major lower cretaceous petroleum source rock (Makhul Formation) in Kuwait - Arabian Gulf

The Lower Cretaceous Makhul Formation is one of the major petroleum source rocks in Kuwait. This study aims to evaluate the Makhul source rock for its organic matter richness and its relation to the rock composition and depositional environment. A total of 117 core samples were collected from five wells in Raudhatain, Ritqa, Mutriba, Burgan, and Minagish oil fields north and south Kuwait. The rock petrographical studies were carried out using a transmitted and polarized microscope, as well as SEM and XRD analyses on selected samples. Total organic matter TOC and elemental analyses were done for kerogen type optically. The GC and GC-MS were done as well as the carbon isotope ratio. The results of this study show that at its earliest time the Makhul Formation was deposited in an anoxic shallow marine shelf environment. During deposition of the middle part, the water oxicity level was fluctuating from oxic to anoxic condition due to changes in sea level. At the end of Makhul and the start of the upper Minagish Formation, the sea level raised forming an oxic open marine ramp depositional condition. Organic geochemical results show that the average TOC of the Makhul Formation is 2.39% wt. High TOC values of 6.7% wt. were usually associated with the laminated mudstone intervals of the formation. The kerogen is of type II and is dominated by marine amorphous sapropelic organic matter with a mixture of zoo- and phytoplankton and rare terrestrial particles. Solvent extract results indicate non-waxy oils of Mesozoic origin that are associated with marine carbonate rocks. The formation is mature and at its peak oil generation in its deepest part in north Kuwait.

Application of X-ray Diffraction (XRD) and Rock–Eval Analysis for the Evaluation of Middle Eastern Petroleum Source Rock

In this study, collected samples of nine different wells from the Middle East are used for various geochemical analyses to determine the hydrocarbon generation potential. The determination is carried out following the grain density, specific surface area, XRD, and Rock–Eval pyrolysis analyses. Four different types of kerogen are plotted based on the Rock–Eval analysis result. Kerogen type I usually has high hydrogen index (e.g., HI > 700) and low oxygen index, which is considered oil-bearing. Kerogen Type II has hydrogen index between type I and type II and oxygen index higher than type I (e.g., 350 < HI < 700) and is also considered to have oil-bearing potential. Kerogen type III has a lower hydrogen index (e.g., HI < 350) and is considered to have a primarily gas-generating potential with terrigenous organic matter origination. Kerogen type IV has a very low hydrogen index and higher oxygen index (compared with other types of kerogen), which is considered the inert organic matter. The kerogen quality of the analyzed samples can be considered as very good to fair; the TOC content ranges from 1.64 to 8.37 wt% with most of them containing between 2 and 4 wt%. The grain density of these examined samples is in the range of 2.3–2.63 g/cc. The TOC and density of the samples have an inversely proportional relationship whereas the TOC and the specific surface area (BET) has a positive correlation. The specific surface area (BET) of the examined samples is in the range of 1.97–9.94 m2/g. The examined samples are dominated by clay, primarily kaolinite and muscovite. Additionally, few samples have a higher proportion of quartz and calcite. The examined samples from the Middle East contain kerogen type III and IV. Only two samples (JF2-760 and SQ1-1340) contain type I and type II kerogen. Considering Tmax and Hydrogen Index (HI), all of the samples are considered immature to early mature. Rock–Eval (S2) and TOC plotting indicate that most of the samples have very poor source rock potential only with an exception of one (JF2-760), which has a fair-to-good source rock potential.

Organic geochemistry and petrology of the coals in the Laisong Formation, Naga Schuppen Belt, NE India: Inferences on hydrocarbon potential and depositional environment

The Oligocene Laisong Formation in the Naga Schuppen Belt is coal bearing along the Dimapur‐Kohima Road section, Nagaland. The coals are sulphurous and classified as lignite to sub‐bituminous ‘C’ based on various rank parameters. The coals are dominantly composed of vitrinite followed by inertinite and liptinite in order of abundance. The coals have high‐quality Type III kerogens derived mainly from angiosperm plants. The richness and quality of organic matter in the coal is excellent to act as a petroleum source rock. Most of the maturity parameters indicate that maturity ranges from immature to early mature. The biomarker parameters and facies critical maceral associations point to deposition of the coal‐bearing strata in non‐marine/terrestrial depositional environment under moist hydrodynamic conditions, possibly in an upper delta plain environment. However, the high sulphur content of the coal points to deposition in a lower delta plain environment. Comparison with other Palaeogene coal deposits of the same sedimentary basin shows that the Laisong coals contain lesser amount of liptinite macerals and much higher amount of sulphur than these deposits. All these deposits are of similar rank, however, the Laisong coals show marginally low thermal maturity from the viewpoint of hydrocarbon generation.