Petroleum Source Rocks Research Articles

Upper Jurassic to Lower Cretaceous source rocks in the Norwegian Barents Sea, part I: Organic geochemical, petrographic, and paleogeographic investigations

This study provides a subregional to regional characterization of organofacies changes within the two members of the Upper Jurassic to Lower Cretaceous Hekkingen Formation (i.e. Alge and Krill) by integrating geochemical and petrographic analysis with paleogeographic models.The gross kerogen composition of the Hekkingen Formation is dominated by terrestrial macerals. This preponderance of land-derived particles is more pronounced in the Krill Member than in the underlying Alge Member. There is a greater proportion of marine macerals within distal areas of the Hammerfest Basin and well 7218/1-S in the southern Bjørnøyrenna Fault Complex. This shift in the relative proportion of marine and terrestrial macerals is ascribed to changes in the location of the depositional sites with respect to the sources of the terrestrial materials.The Alge Member features the highest levels of total organic carbon (TOC ≥7 wt %), but the more discrete and organically poorer beds of the Krill Member still remain sufficiently rich to be considered petroleum source rocks (TOC ≥2 wt %). Hydrogen indices (HI) between 50 and 400 mg HC/g TOC recorded throughout the entire formation indicate that the kerogen within both members has similar oil and gas generation capabilities. These low to moderate HI values are indicative of immature Type III to II-III kerogens and are generally consistent with the high proportions of terrestrial macerals. Prior to thermal maturation, marine type II kerogens (i.e. ≤ 400 mgHC/gTOC) probably existed in the marine liptinite-rich rocks in the distal Hammerfest Basin and Bjørnøyrenna Fault Complex. At least three factors controlled the detected variability in geochemical parameters: dilution rates of organic matter, varying inputs of terrestrial versus marine organic matter, and the degree of preservation. The documented variability in organic-rich facies assists in reducing source rock risk in the study area, but also helps explorationists understand source rock distribution across other shelfal areas.

The Cretaceous succession of northeast Baffin Bay: Stratigraphy, sedimentology and petroleum potential

Eleven cored boreholes, with depths up to c. 360 m were drilled in north-east Baffin Bay, a frontier area offshore West Greenland by the vessel Joides Resolution. The cores were part of the Baffin Bay scientific shallow coring program, expedition 344S in 2012, funded by a consortium of eight petroleum companies. The main drilling target was a succession of dipping strata in the Kap York Basin that proved to be of Cretaceous age. Here we report the results of comprehensive core analyses involving lithofacies interpretation, palynological dating, palynofacies studies, isotope geochronology, organic geochemistry and reservoir characterization. The Lower Cretaceous succession comprises sandstones, mudstones and few thin coal beds of Albian age. Terrestrial material and a sparse and low diversity assemblage of brackish-water dinoflagellate cysts (dinocyst) species dominate the organic particles. The sedimentary environments range from floodplain to deep bay and suggest deposition in a large non-marine to brackish embayment. The kerogen type is immature to marginally mature, type III/IV, with very restricted potential for generation of petroleum or gaseous petroleum. The Upper Cretaceous sedimentary succession of Cenomanian–Turonian age consists of black marine mudstone with varying amounts of discrete sand layers. The amorphous organic material and marine dinocysts suggest that most of the succession was deposited in an anoxic–dysoxic to oxygen restricted palaeoenvironment, probably ranging from outer shelf and prodelta fringe to lower delta front. The organic richness and petroleum potential are variable. The black mudstones include organic rich intervals with TOC of 3–6%, HI of 200–350 and SPI value of 3.0, comparable to well-known petroleum source rock successions of this age worldwide. The δ13Corg curves for the Cenomanian–Turonian sections display values and trends characteristic of Oceanic Anoxic Event 2 (OAE2). A marine transgression between the Lower and Upper Cretaceous successions caused dramatic changes in depositional environments.

Lithospheric evolution, thermo-tectonic history and source-rock maturation in the Gippsland Basin, Victoria, southeastern Australia

A fully integrated 3D basin model was built to study the lithospheric structural evolution and the thermal history of the offshore part of the Gippsland Basin to investigate the type, timing and magnitude of its initial opening mechanism and their effects on source rocks. The applied workflow included seismic interpretation of major faults and magmatic features, seismic reinterpretation of existing main stratigraphic boundaries and adjustment of the basement topography. Different scenarios for a McKenzie-type basal heat flow evolution were tested based on a two-step inversion approach, which translates the thickness changes of lithospheric layers into basal heat flow. Finally, a crustal layer model was assigned to the existing 3D numerical basin model and the effects on thermal maturation of petroleum source rocks were investigated. The results of the calibrated inversion model suggest intense lithospheric stretching and mantle upwelling during the Early Cretaceous caused initial breakup and subsidence of the Gippsland Basin. This syn-rift phase was accompanied by increasing basal heat flow from initially ∼50 mW/m2 to a maximum of 80–90 mW/m2. The resulting upwelled Moho with an associated crustal thickness of locally only 8 km agrees with geophysical observations. Elevated paleogeothermal gradients between 50 and 60 °C/km prevailed from ca 120 to 80 Ma. Episodes of compression, uplift, erosion, and thermal subsidence resulted in fast and continuous cooling during the early post-rift and a constant basal heat flow of 45–50 mW/m2 since the Eocene. Two main pulses of petroleum generation were identified in the Paleocene and in the Miocene–Pliocene. This novel two-step crustal layer inversion method allows a detailed reconstruction of the thermal history of rift basins and can provide useful information about the maturation of petroleum source rocks. KEY POINTS A temperature history reconstruction of the Gippsland Basin is given based on a large-scale numerical 3D model. Tectonically induced strong variability in paleoheat flows is recognised. Strong maturation and petroleum generation developed during the Paleogene and Neogene.

Porosity and permeability of karst carbonate rocks along an unconformity outcrop: A case study from the Upper Dammam Formation exposure in Kuwait, Arabian Gulf

Diagenetic changes are a concern in carbonate petroleum reservoir management. One of the challenges is to determine whether the pore systems are related to diagenesis and/or depositions, and how associated mechanisms affect reservoir quality. The purpose of this study was to assess variations in porosity and permeability due to diagenetic processes in the paleokarst zone of the Middle Eocene Upper Dammam Formation in Kuwait. This zone is 14 m thick and exposed in a quarry in southern Kuwait. The exposed section is divided into three lithological units, described here from the bottom to top: chalky dolostone, karst dolostone, and karst carapace. These rocks have been affected by several diagenetic processes, including dolomitisation, dissolution, cementation, replacement, recrystallisation, and fracturing. Significant variations have been observed in porosity and permeability, both vertically and horizontally. In the chalky dolostone layer, the highest porosity and permeability were measured at 53 % and 6000 mD, respectively. The maximum porosity and permeability in the karst dolostone layer were 44.23 % and 1140 mD, respectively. The karst carapace had the lowest porosity (30 %) and permeability (100 mD). Majority of the porosities were of isolated mouldic or vuggy forms. Pores formed in the rock framework were vuggy, fractured, and more connected. They were formed at later stages by meteoric water dissolution, acidic gases produced during the thermal maturation of kerogen in the petroleum source rocks, or a combination of both processes. The results of this study may be applicable to analogous subsurface carbonate reservoir rocks.

Geochemical Investigation of Trace Metals in Crude Oils from Some Producing Oil Fields in Niger Delta, Nigeria

The concentrations of trace metals in crude oil samples obtained from eight producing fields from Niger Delta Nigeria were analyzed using a 700 model Perkin Elmer Atomic Absorption Spectrophotometer. Results showed the following ranges for the trace metals, Cu (0.01- 0.04 mg/kg); Fe (0.05 – 5.90 mg/kg); Ni (0.09 – 0.72 mg/kg); V (0.008 – 1.05 mg/kg). Pb and Zn were < 0.01 mg/kg. Trace metal ratios such as V/Ni; V/Fe and V/V + Ni were used to unravel the genetic correlation among the oils. Results showed that all the crude samples except sample from Nembe South-2 have a V/N ratio < 1 indicating the organic material that produced the petroleum source rock. A cross plot of V/Ni revealed two genetic families for the crude oils, derived from a terrestrial and marine origin. This was confirmed by the Ternary plot of V, Ni and Fe which discriminated the crude oils from the producing fields into two distinct groups. The V/(Ni+V) of < 0.5 shows that most of crude oil were deposited in an oxic environment. A cross-plot of V/(Ni+V) and V/Fe showed a weak correlation which suggests that it cannot be used as a substitute for the V/Ni ratio in determining the origin and depositional environment of crude oil samples. Therefore, in-depth knowledge of the concentration of trace metals especially vanadium and nickel within an environment during oil exploration is very essential in developing new oil locations.

Petroleum source rock characteriazation and hydrocarbon generation, Baku archipelago, South Caspian basin, Azerbaijan

Petroleum source rock characteriazation and hydrocarbon generation, Baku archipelago, South Caspian basin, Azerbaijan

Ogilvie Platform Composite Tectono-Sedimentary Element

Abstract The Ogilvie Platform Composite Tectono-Sedimentary Element (CTSE) occupies an area of about 68 000 km 2 in the northern part of the Yukon Territory of Canada, and includes all Paleozoic- and Triassic-aged strata between a base of Cambrian unconformity and a base of Jurassic and Cretaceous unconformity. This cratonic platform is composed of two lithologically distinct sedimentary successions: a lower suite of peritidal to shallow-subtidal, carbonate-dominated, Cambrian–Middle Devonian-aged units; and an upper succession of siliciclastic-dominated alluvial fan, shelf delta, nearshore, slope and basinal strata of Middle Devonian–Late Permian and Triassic age. The lower succession is composed of a synrift tectono-sedimentary element (TSE) and an overlying passive continental-margin TSE. The upper succession is composed of an Ellesmerian orogenic foreland TSE and a syn-epeirogenic TSE. The total discovered oil reserve within the Ogilvie Platform is estimated to be 1.757 × 10 6 m 3 (11.05 MMbbl) and the total discovered gas reserve is estimated to be 2.376 × 109 m 3 (83.7 Bcf) in four oil and gas pools. A variety of stratigraphic and structural trap types have been assessed to contain additional conventional hydrocarbon reserves, with a total mean potential of 33.4 × 10 6 m 3 (210.1 MMbbl) of oil and 33.4 × 10 9 m 3 (2.63 Tcf) of gas. The organic-rich shale and siltstone-dominated petroleum source-rock units, such as within the Road River Group, the Canol and Ford Lake formations, and organic-rich strata within the Hart River and Blackie formations, are also prospective for large reserves of unconventional oil and gas, and have yet to be formally assessed.

Tromsø–Bjørnøya Composite Tectono-Sedimentary Element, Barents Sea

Abstract The Tromsø–Bjørnøya Composite Tectono-Sedimentary Element (CTSE) in the southwestern Barents Sea comprises strata of Late Paleozoic–Paleocene age. Since the Paleozoic Caledonian Orogeny, the structural evolution of the CTSE is mainly related to extension, culminating in Late Jurassic–Early Cretaceous hyperextension. Some compressive deformation observed during Late Cretaceous–Paleogene times may relate to activity in the North Atlantic prior to the Early Eocene onset of seafloor spreading between Norway and Greenland. The sedimentary succession may be up to 14 km thick. It comprises Late Paleozoic continental facies, followed by carbonates, evaporites, and eventually cherts and marine clastic material. The overlying Triassic–Paleocene succession is entirely siliciclastic, reflecting Triassic–Middle Jurassic deltaic and shallow-marine conditions followed by deeper-marine conditions during Late Jurassic–Paleocene times. Primary reservoirs are encountered in the latest Triassic–Middle Jurassic succession, with secondary reservoirs found in the Late Jurassic–Early Cretaceous synrift succession, and in Paleocene strata. The primary source rock for petroleum is of Late Jurassic–Early Cretaceous age. Other source rocks include strata of Triassic and Barremian age, and a recently observed unit of Cenomanian–Early Turonian age.

Applying artificial intelligent and empirical techniques for prediction of total organic carbon content from wireline data: A case study from Pabdeh Formation in Mansuri oilfield, SW Iran

Total organic carbon (TOC) content is one of the most crucial parameters needed for petroleum source rock evaluation. In this study, artificial neural network (ANN) and empirically derived ΔlogR techniques were used to estimate organic richness of the Paleocene-Oligocene Pabdeh source rock in the Mansuri oilfield (SW Iran) using the wireline data. The ANN model trained by the Levenberg-Marquardt back propagation algorithm was employed for prediction of TOC content from the responses of the sonic, neutron, density and spectral gamma-ray well logs. The linear regression analysis between TOC values measured by Rock-Eval analysis and the corresponding ones predicted by ΔlogR and ANN methods was performed to validate the performance of each method. The ANN model is capable of predicting TOC contents with higher coefficient of determination (R2) value (0.7830) compared to ΔlogR technique (0.5091). Correspondingly, the mean squared error (MSE) value for the constructed neural network (0.1647) is lower than ΔlogR method (0.2410). Overall, it can be concluded that the proposed ANN model provides more accurate qualitative and quantitative predictions of organic richness, and can be reliably applied for high-resolution estimation of TOC contained in the Pabdeh source rock throughout the Mansuri oilfield.

Origin of Phosphate‐bearing Carbonate Concretions in the Upper Triassic Lacustrine Black Shales of the Southern Ordos Basin, China

AbstractCarbonate concretions are conspicuous in organic‐rich shales and are generally related to decomposition of organic matter. The black shales from the Chang 7 Member of the Upper Triassic Yanchang Formation of the southern Ordos Basin host abundant carbonate concretions, which provide a unique record of depositional and early diagenetic conditions of the paleo‐lake sediments. However, little attention has been given to the genesis and growth processes of the concretions in these lacustrine petroleum source rocks. New petrographic observations and geochemical analysis show that the concretions are composed of calcite, phosphate fossil fragments, K‐NH4‐feldspar, quartz, bitumen, and minor Fedolomite. Phosphate minerals, mainly carbonate fluorapatite (CFA), show pervasive replacement by calcite, most of which contains phosphorus, ranging in concentration from 0.26 to 2.35 wt%. This suggests that the phosphate minerals are the precursors for concretion growth. Positive δ13C (+5.6 to +12.4 &amp;#x2030; V‐PDB) signatures and the absence of pyrite indicate that microbial methanogenesis was the dominant driver for concretion growth, rather than bacterial sulfate reduction. Quartz, bitumen, and Fe‐dolomite are the last cements that occurred, at deep burial depths and high temperatures. The formation of phosphate minerals might have been induced by upwelling of phosphate‐enriched deep water in the Late Triassic paleolake, which promoted phytoplankton blooms and further enrichment of organic matter. Extremely slow sedimentation rates of fine‐grained detrital minerals, relative to dead organism accumulation, led to the high permeabilities of the organic‐rich sediments and rapid concretion growth during shallow burial. The close association of phosphate‐bearing carbonate concretions and organic‐rich shales reflects that upwelling played a critical role in the formation of the high‐quality petroleum source rocks in the Triassic paleo‐Ordos lake.

Interpretation and Reconstruction of Depositional Environment and Petroleum Source Rock Using Outcrop Gamma-ray Log Spectrometry From the Huai Hin Lat Formation, Thailand

Gamma ray logs are most useful in identifying subsurface lithology and interpreting depositional environments. This study highlights the use of outcrop gamma-ray logs along with outcrop observations and total organic carbon (TOC) analysis to provide the stratigraphic framework of the organic-rich rocks of Huai Hin Lat Formation in central Thailand. The study reveals five sedimentary facies including (1) structureless sandstone, (2) structured sandstone, (3) interbedded sandstone and siltstone, (4) interbedded mudstone and siltstone and (5) calcareous mudstone. These facies can be grouped into two facies associations; mudstone-dominated and sandstone-dominated facies associations. The depositional environment was interpreted as lacustrine basin-fill subdivided into deep lacustrine environment and sublacustrine fan associated with the turbidity currents. The total gamma-log characteristics are closely related to the lithologies controlled primarily by clay mineral compositions. Whist, the use of spectral gamma-ray can reveal more details on depositional environments and conditions. In this study, U concentrations is proven to be useful in highlighting organic-rich rocks in low K and Th concentration successions due to its ability to be fixed in clay minerals and organic materials under an anoxic condition. Thus, the U spectral gamma ray is suggested to combine with conventional gamma ray log for depositional environment and recognition of organic-rich rocks.

Paleoenvironments and source rock potential of Dorado North well in the Mannar Basin (Indian Ocean)

The Upper Cretaceous to Eocene sedimentary succession of the Dorado North exploration well in the Mannar Basin has been studied for paleoenvironment (organic matter richness, its composition, and depositional environment) and petroleum source rock potential. In this study, drillcore cuttings (n = 142) were analyzed using CHNS elementary analyzer. Results indicated that Lower Campanian sediments were depleted by total organic carbon content (TOC = 0.45%), under arid climate. The Lower Campanian to Upper Maastrichtian sedimentary sequence contains organic carbon rich (TOC = 1.64%) terrestrial (C/N ratio = 27.13) sediments. Consequently, this sedimentary sequence can be identified as a good source rock for gas generation. The formation of organic matter rich terrestrial sediments has been linked to sea-level changes and tectonic activities during the Late Cretaceous. Carbonate carbon contents are rich in the Lower Campanian to Upper Maastrichtian sedimentary sequence that indicates diversification of microorganisms under warm climatic conditions. The Paleocene to Eocene sedimentary sequence indicates poor to fair source rocks for possibly oil generation. However, the depositional environment was drastically changed from oxic (Early-Late Paleocene) to anoxic (Late Paleocene-Late Eocene) conditions. Consequently, the Eocene epoch is characterized by weak oceanic circulation in the Indian Ocean under greenhouse climate. In contrast, the deposition of carbonate platforms since the Late Paleocene (CaCO3 = 29.3%) can be related to the northward movement of the Indian plate into warmer tropical latitudes.

Sequence stratigraphy and organic geochemistry: An integrated approach to understand the anoxic events and paleoenvironmental evolution of the Ceará basin, Brazilian Equatorial margin

An organic geochemical investigation combined with sequence stratigraphy was performed in the Ceará Basin, an offshore basin located in Northeastern Brazil. The information available from 30 well logs (gamma-ray, resistivity, density), besides geochemical (TOC, and pyrolysis indexes) and isotopic (δ13C) data, aided the preparation of a dataset for this study. The application of sequence-stratigraphic methods helped classify and correlate seismic and organic facies. Four key petroleum source-rock units were identified, from the oldest to the youngest: (1) Mundaú Formation – top of the Rift Sequence (Berriasian-Aptian); (2) Paracuru Formation – Breakup Sequence (Aptian-Albian); (3) Itapajé Member of the Ubarana Formation – Continental Drift Sequence (Albian-Turonian), and (4) Uruburetama Member of the Ubarana Formation – Continental Drift Sequence (Turonian-Maastrichtian). The geochemical characteristics of the Mundaú Formation (high total organic carbon (TOC), hydrogen index (HI), relative hydrocarbon potential (RHP = (S1 + S2)/TOC)) point to a typical transgressive sequence. Six transgressive-regressive (T-R) cycles were recognized in the entire Paracuru Formation. The best geochemical marker is related to the top of the Paracuru Formation. This stratigraphic unit can be correlated to a major anoxic event and is the best source rock of this basin. Evaporitic facies found in this top section, maximum RHP values (anoxic conditions), and maximum flooding surfaces related to transgressive events characterize this interval. Moreover, the wide spatial cover of organic-rich rocks, carbon isotopic data, and the recognition of favorable characteristics for anoxia in other basins of the Equatorial Margin are suggestive of the Aptian-Albian Oceanic Anoxic Event (OAE-1b) occurring in the Ceará Basin. The Ubarana Formation represented by the Uruburetama Member and the Itapajé Member yields the least promising source rocks. However, high TOC values suggest the occurrence of the late Cenomanian–early Turonian Oceanic Anoxic Event (OAE-2), when organic-rich strata started to deposit in deep-water regions. The predominance of a regressive interval in the Uruburetama Member points to oxic or sub-oxic conditions. Additionally, the correlations between the Brazilian Equatorial Margin and its African counterpart, and the organic geochemical characterization allied to the definition of depositional systems for these regions proved to be useful for oil exploration.

PETROLEUM POTENTIAL OF MAE TEEP ORGANIC SEDIMENTS, NORTHERN THAILAND

The selected 7 organic sediment samples (3 oil shale samples from Upper Oil Shale, Lower Oil Shale and Oil Shale in Coal A sub-unit, 3 coal samples from Coal A, Coal B and Coal C sub-unit and 1 leonardite sample from Leonardite sub-unit) collected at the northern wall of Mae Teep coal mine were conducted the Hydrocarbon Analyzer with Kinetics (HAWK) pyrolysis in order to assess their petroleum source rock potential. The calculated HI, OI, PI, S2+S3 and Ro were then used to classify the kerogen type and to evaluate the thermal maturity stage of these 7 studied organic sediment samples. Results of the study indicate that all of the organic sediment sub-units of Mae Teep organic sediments have good to excellent hydrocarbon generation potential. HI vs Tmax and HI vs calculated Ro cross-plots results indicate that organic sediments of Coal A, Coal B, Coal C, Oil Shale in Coal A and Upper Oil Shale sub-unit are in the thermal immature stage, while the organic sediments of Lower Oil Shale and Leonardite sub-unit are in the early thermal mature stage. Mae Teep organic sediments are considered to be the high potential hydrocarbon source rock since they have high kerogen yield (S2) (21.49 - 69.8 mg HC/g rock) and their total hydrocarbon generation potential (S1+S2) are also high (22.13-72.12 mg HC/mg rock). These may contribute them to be a good to very good source rock if their maturity reaches the thermal mature stage.

Origins of hydrocarbons in the Geneva Basin: insights from oil, gas and source rock organic geochemistry

An extensive subsurface investigation evaluating the geothermal energy resources and underground thermal energy storage potential is being carried out in the southwestern part of the Swiss Molasse Basin around the Geneva Canton. Among this process, the evaluation of the petroleum source-rock type and potential is an important step to understand the petroleum system responsible of some oil and gas shows at surface and subsurface. This study provides a first appraisal of the risk to encounter possible undesired occurrence of hydrocarbons in the subsurface of the Geneva Basin. Upon the numerous source-rocks mentioned in the petroleum systems of the North Alpine Foreland Basin, the marine Type II Toarcian shales (Lias) and the terrigenous Type III Carboniferous coals and shales have been sampled from wells and characterized with Rock–Eval pyrolysis and GC–MS analysis. The Toarcian shales (known as the Posidonia shales) are showing a dominant Type II organic matter composition with a Type III component in the Jura region and the south of the basin. Its thermal maturity (~ 0.7 VRr%) shows that this source-rock currently generates hydrocarbons at depth. The Carboniferous coals and shales show a dominant Type III organic matter with slight marine to lacustrine component, in the wet gas window below the Geneva Basin. Two bitumen samples retrieved at surface (Roulave stream) and in a shallow borehole (Satigny) are heavily biodegraded. Relative abundance of regular steranes of the Roulave bitumen indicates an origin from a marine Type II organic matter. The source of the Satigny bitumen is supposedly the same even though a deeper source-rock, such as the lacustrine Permian shales expelling oil in the Jura region, can’t be discarded. The oil-prone Toarcian shales in the oil window are the most likely source of this bitumen. A gas pocket encountered in the shallow well of Satigny (Geneva Canton), was investigated for molecular and stable isotopic gas composition. The analyses indicated that the gas is made of a mixture of microbial (very low δ13C1) and thermogenic gas. The isotopic composition of ethane and propane suggests a thermogenic origin from an overmature Type II source-rock (> 1.6 VRr%) or from a terrigenous Type III source at a maturity of ~ 1.2 VRr%. The Carboniferous seems to be the only source-rock satisfying these constraints at depth. The petroleum potential of the marine Toarcian shales below the Geneva Basin remains nevertheless limited given the limited thickness of the source-rock across the area and does not pose a high risk for geothermal exploration. A higher risk is assigned to Permian and Carboniferous source-rocks at depth where they reached gas window maturity and generated large amount of gas below sealing Triassic evaporites. The large amount of faults and fractures cross-cutting the entire stratigraphic succession in the basin certainly serve as preferential migration pathways for gas, explaining its presence in shallow stratigraphic levels such as at Satigny.

Source rock potential, crude oil characteristics and oil-to-source rock correlation in a Central Paratethys sub-basin, the Hungarian Palaeogene Basin (Pannonian basin)

Eocene and Lower Oligocene rocks are potential source rocks for crude oil accumulations in the Hungarian Palaeogene Basin. To enhance the understanding of the hydrocarbon system, this study (i) assesses the petroleum potential of Palaeogene formations, (ii) characterises the source rock facies of the accumulated oils, and (iii) provides an oil-to-source correlation. Rock-Eval data of samples from three boreholes (W–1, W–9 and W–12) show that most Palaeogene formations are mature at depths exceeding 2.1–2.5 km. The coal-bearing Kosd Formation includes good to excellent gas- (and oil-) prone source rocks. The overlying Buda Marl Formation is typically organic matter-lean but contains oil-prone rocks with up to 2.3 wt% TOC and a fair petroleum potential in borehole W–9. The Tard Clay Formation in W–12 reaches up to 1.9 wt% TOC and shows HI values up to 440 mg HC/g TOC, characterising the deposits as good petroleum source rocks. Based on low TOC contents, the Kiscell Clay Formation is not considered a source rock. Molecular parameters of 12 crude oil samples indicate a shaly source rock deposited in a marine/brackish environment. Salinity stratification, causing the development of oxygen-depleted conditions, is likely. The organic matter is dominated by aquatic biomass, including algae, dinoflagellates and chemoautotrophic bacteria. Minor angiosperm-dominated organic matter was transported into the basin from the shoreline. Specific V-shaped compound-specific carbon isotope patterns of n-alkanes observed in crude oils and extracts from the Tard Clay prove the dominant source rock. Minor differences between biomarker ratios are related to vertical and lateral facies variations within the Tard Clay Formation. The accumulated oils are slightly more mature than the Tard Clay in borehole W–12.

A Green Approach of Leaching Trace Metals From Petroleum Source Rock

The extraction of trace metals (manganese, nickel, vanadium and molybdenum) from petroleum source rock using nonionic surfactant solutions with the assistance of oven heat was investigated. The results revealed that time, temperature and pH have significant influence on the extraction yields of the trace metals. The effect of sample/solvent ratio was significant for extraction of some trace metals. The optimum extraction temperature using both polyoxyethylene(23)dodecyl ether (Brij 35) and polyoxyethylene(10)dodecyl ether C12E10) solutions as extracting solvents was 150°C except nickel that had highest yield at 90°C when C12E10 solution was used. For both Brij 35 and C12E10, most of the trace metals had highest yields at 3 hr. The yields of the trace metals were more significant in acidic medium. The yields of the trace metals were significantly higher using Brij 35 than C12E10. Validation of the new oven-assisted nonionic surfactant extraction (OANSE) method using SGR-1b standard reference material revealed excellent recoveries for the trace metals except vanadium that had an average recovery, which indicates that the new method is very efficient for leaching of manganese (Mn), nickel (Ni) and molybdenum (Mo) from petroleum source rock while the recovery of vanadium can be improved in acidic medium. This study revealed that OANSE is efficient and readily available green analytical protocol for the determination of trace metals in source rock.

The Lithofacies of Pandua Formation Shale in the Andowia Area, North Konawe, Southeast Sulawesi and Its potential as Petroleum source rock

Research on the Late Miocene of Pandua Formation shale in Andowia area, Southeast Sulawesi is fundamental because it is considered to have the potential as a source rock in Manui Basin. This study aimed to determine the lithofacies and its potential as petroleum source rock using megascopic, petrographic, and total organic carbon analyses in Pandua Formation shale. Based on the megascopic and petrographic analysis of outcrops, the shale can be subdivided into 11 lithofacies consists of clayey shale, massive claystone, clastic detritus-rich claystone, massive mudstone, mica-rich mudstone, iron oxide-rich mudstone, low-angle laminated mudstone, massive siltstone, carbon-rich massive siltstone, laminated siltstone, and carbon-rich laminated siltstone. The results of the analysis of 19 samples of shale showed that the total organic carbon (TOC) content was classified as poor to excellent (&lt;0.5%- &gt;4%). The lithofacies with a high concentration of TOC are carbon-rich massive siltstone and carbon-rich laminated siltstone. Both lithofacies were categorized as potentially excellent source rock which the TOC value content is 5.78% and 5.74%.The result implies the better understanding of the depositional environment and hydrocarbon accumulation potential of the Manui basin for future exploration.

Potential of Petroleum Source Rock Brines as a New Source of Lithium: Insights from Basin–Scale Modeling and Local Sensitivity Analysis

Potential of Petroleum Source Rock Brines as a New Source of Lithium: Insights from Basin–Scale Modeling and Local Sensitivity Analysis

Paleoenvironmental controls on petroleum source rock formation in the syn-rift to early post-rift phase in the Miocene back-arc rift system of the northern Niigata and Yamagata areas

Paleoenvironmental controls on petroleum source rock formation in the syn-rift to early post-rift phase in the Miocene back-arc rift system of the northern Niigata and Yamagata areas