Petroleum Source Rocks Research Articles

Assessing the Geochemical Correlation Between Petroleum Source Rocks in the Brazilian Equatorial Margin Basins and Global Oceanic Anoxic Events

Assessing the Geochemical Correlation Between Petroleum Source Rocks in the Brazilian Equatorial Margin Basins and Global Oceanic Anoxic Events

How marine incursions affect the sedimentary environment and the quality of source rocks in the Upper Cretaceous Songliao Basin, NE China

The linkage between marine incursions and lacustrine petroleum source rock deposition has been studied worldwide. A variety of interpretations have been suggested to explain the influence of marine incursions on the quality of source rocks in the Upper Cretaceous Qingshankou Formation (K2qn), Songliao Basin. In this study, high-resolution of geochemical and sedimentary results of two drilled wells from the K2qn were presented to improve the understanding on this issue. 117 samples from Well GY8HC of the Qijia-Gulong Sag (brief as Gulong Sag) and 251 samples from Well ZY1 of the Sanzhao Sag, the Central Depression of the basin were analyzed to establish the evolution of paleoenvironment and the influence of marine incursions on organic matter enrichment in the two sags. All the evidence suggests that marine incursions have a positive effect on the quality of member 1 of the K2qn source rocks (K2qn1) in the Sanzhao Sag, which was probably due to the rising lake level and increasing salinity of the watermasses. The enhanced salinities could have inhibited lake overturn and oxygenation of bottom water, and thus created a favorable condition for the preservation of organic matter. In contrast, the K2qn1 source rock in the Gulong Sag was less affected by marine incursions, which is likely due to the Daqing placanticline blocking two sags. The lake water in the Gulong Sag was characterized as fresh-brackish with less mixing of seawater. Petrographic observation suggests that organic matter in the Gulong source rocks was mainly derived from lacustrine algal and microsporinite. This research provides novel insights into the linkage between marine incursions and the depositional environment during the formation of K2qn1 in the Songliao Basin.

Petroleum source-rock characterization and the depositional environment of Kimmeridgian–Tithonian sequences, Jaisalmer Basin, western Rajasthan, India

In hydrocarbon exploration, total organic carbon (TOC) content and Rock-Eval pyrolysis are commonly employed geochemical techniques that offer concise insights into kerogen type, effective source-rock identification and thermal maturity. In the current study, the data obtained from Rock-Eval pyrolysis has been used to define the source-rock quality, generative potential, kerogen type, maturity of the source sediments and kerogen kinetics of the Baisakhi–Bhadesar Formation of Kimmeridgian–Tithonian (154.7–145.6 Ma) age. Basinal level hydrogen index (HI), TOC content, source-rock maturity, transformation ratio and heat-flow maps have been generated by integrating the data from pyrolysis with previously available data from wells drilled in the basin. The TOC content of the Kimmeridgian–Tithonian sequence ranges from 0.03 to 12.71% in the studied samples, with an average TOC content of 1.28%, indicating good source-rock quality. The HI, in collaboration with T max and vitrinite reflectance (VR o ) data, demonstrates that the Baisakhi–Bhadesar Formation is characterized by type II, a mixture of type II/III and type III kerogen facies and exhibits good source-rock quality and poor to good generative potential in the basin. The studied samples are marginally mature to mature in nature ( T max , 430–450°C; VR o , 0.52–0.72%). A maturity analysis of the basin suggests that during the Late Jurassic most areas were under the oil window zone, except for the Bhakhari Tibba and Miajlar areas. The transformation ratio overlay for the Kimmeridgian–Tithonian source sequences shows better transformations of the source rock in the area of the Shagarh Sub-basin. Kerogen kinetics of the studied Baisakhi–Bhadesar Formation demonstrate that the activation energy ranges between 46 and 74 kcal mol −1 with the significant distribution of activation energy being 54 kcal mol −1 (42.07%), representing a strong heterogeneous type of organic matter in the sediments. Based on lithological, palaeontological and electrolog studies, a shallow-marine to nearshore environment of deposition with a sediment-input direction from the SE has been inferred for the Kimmeridgian–Tithonian sequences. The results of this study quantitatively establish the role of the Kimmeridgian–Tithonian sequence as a source rock, ultimately contributing to the generation of hydrocarbons in the basin along with spatial changes in the quality of source sediments in different parts of the basin.

Paleoenvironmental factors controlling organic-rich formations deposition in the Babouri-Figuil Basin (Northern Cameroon)

The Babouri-Figuil Basin is an intracratonic basin (half-graben) in northern Cameroon that is genetically connected to the Benue Trough from Nigeria, and is an area of interest in terms of petroleum prospectivity. Recent studies highlighted the presence of organic-rich formations in the basin. However, none of these works have identified factors that governed the accumulation of organic matter (OM) in the sediments. The main objective of this work is the characterization of these formations through palynofacies and organic geochemical techniques (total organic carbon - TOC, total sulfur, insoluble residue and biomarkers), in order to determine the organic facies, their depositional environments and the main drivers for organic enrichment in the basin. The current study reveals that black shale and massive claystone lithologies constitute the main organic-rich formations in the basin, with TOC reaching up to 26.08 wt%, being characterized by a dominance of bacterially-derived amorphous OM. Palynofacies and biomarker data revealed that these formations are positively associated with anoxic conditions and a partly highly saline and stratified lake water column. The deposition of organic-rich formations in the Babouri-Figuil Basin was mainly controlled by restriction conditions which developed in connection with the regional tectonic framework. The Lower Cretaceous rifting episode in the West and Central African Rift System (WCARS) basins led to the formation of accommodation space, a reduction in water levels, and the development of anoxic conditions within the basin, facilitating the deposition of organic-rich formations. Therefore, the organic enrichment of the Babouri-Figuil Basin has been predominantly controlled by its tectonic evolution, particularly during the syn-rift phase. This phase created favorable conditions for the deposition and preservation of OM, including the establishment of anoxic conditions. Additionally, the paleoclimate (arid conditions), the development of bacterial biomass, and the basin's paleogeography all played a significant role in this process. The organic-rich formations of the Babouri-Figuil Basin show characteristics of prospective petroleum source rocks (high organic content, high proportion of oil-prone kerogen, significant thickness and lateral extension). The combination of organic-rich formations with sandstone deposits above and extensive claystone/shale deposits on top can indicate the presence of an oil play in the basin. A detailed study with broader sampling is needed to investigate thoroughly the variation of organic facies and the influence of paleoenvironmental factors that control the deposition of thick source rock intervals.

Petroleum Potential Prospectivity of Muglad Basin, South Sudan: A Case of Source Rocks Characterisation in the Drilled Kaikang West-1 Well

This study focuses on Prospectivity of Petroleum Potential of Muglad basin, South Sudan, with the help of petroleum source rocks characterisation in the drilled Kaikang West-1 Well based on the organic matter quantity, quality, and the thermal maturation generation capability of the organic matter disseminated in the analysed rock samples. Muglad basin is a major petroliferous Western and Central African Rifts System (WCARS) member, with estimated reserves of 2,053 mm bbl. Muglad Basin comprises thick sandstones of Aradeiba and Bentiu Formations, considered to be the main petroleum prospectivity targets, with trapping mechanism being structural faults and lithological anticlines. The organic matter contents were determined directly from laboratory analyses of the source rock samples with the help of seismic and gamma ray profiles, total organic carbon (TOC wt %), maturity indices (OI, HI and PI), temperature maximum (Tmax °C), porosities and other sedimentological parameters. This study involved a series of analytical geochemistry and petro-physical studies to ascertain a number of effective source rock samples from the well cores which were then analysed in terms of TOC, OI, PI, HI, S2, S1 and Tmax to determine oil/gas prone samples (resource areas). These were then distinguished from strata with very high organic matter samples as well as very high TOC to help identify for possible source rock characterizations within the lithology pertaining to the well in terms of potential source-reservoir-seals combinations. The Rock-Eval pyrolysis data were useful in assessing and evaluating the type of organic matter, thermal maturity, and the generation capability of source rocks for hydrocarbon exploration rationale. The analyses revealed that some strata, within the sampled well data, have high hydrocarbon generation potential with the existence of commercial hydrocarbon production

Early stages of Type I-S kerogen formation revealed by Rock-Eval® 7S analysis of sediment from a modern halo-alkaline lake (Dziani Dzaha, Mayotte)

The Dziani Dzaha (Mayotte Islands, Indian Ocean) is a small, shallow, saline and hyperalkaline maar lake. Its surface waters are characterized by intense primary production, inducing the waters below 2 m depth to remain aphotic and anoxic all year round, at least until 2017, when a ∼5 m-long core was taken from the center of the lake. The recovered sediments were described and sampled at high resolution. They consist of laminated microbial mats, mixed with carbonate lenses or nodular beds, and rare silty detrital facies. The inorganic and organic carbon contents of 160 samples were analyzed using the Rock-Eval® method, including the Rock-Eval® 7S device which quantifies both total organic sulfur and total sulfur content, in addition to conventional Rock-Eval parameters. The Dziani Dzaha sediments are characterized by high TOC content (8.5 wt% on average and up to 27.9 wt%) and variable inorganic carbon content. HI values average 630 mg HC/g TOC and reach up to 834 mg HC/g TOC. TS content varies from 0.3 to 3.6 wt%, with TSorg/TOC ratios close to 0.01 at the top of the core and fluctuating downcore between 0.02 and 0.05. Interestingly, the pyrolysis thermal stability of sulfurized organic matter increases with depth, and the highest HI values are associated with highest Sorg content, sulfurization of organic matter being generally accompanied by reductive processes. The hydrogen- and organic-sulfur-rich sediments of Dziani Dzaha can be considered modern analogues of Type I and I-S petroleum source rock deposits, such as the Eocene Green River shales and Kimmeridgian Orbagnoux laminites, with remarkable facies and geochemical similarities. (258 words)

Northern Svalbard Composite Tectono-Sedimentary Element

Abstract The Northern Svalbard Composite Tectono-Sedimentary Element (CTSE) comprises Proterozoic, Early Paleozoic and Devonian sedimentary rocks preserved in northern Svalbard and on the adjacent shelf margin between complexes of metamorphic and crystalline basement rocks. The Northern Svalbard CTSE covers four main tectono-sedimentary elements: Tonian synrift, Neoproterozoic–Cambrian post-rift, Ordovician passive margin and late Silurian?/Devonian synextensional basins. The oldest documented sedimentary strata are greywacke and shale deposited after the Greenvillian Orogeny and assumed to be younger than 980–960 Ma. The present CTSE further includes Cambrian–Ordovician sedimentary rocks in Ny-Friesland and Nordaustlandet, while the dominant part of the CTSE are continental Old Red Sandstone sediments of the late Silurian?/Early Devonian Red Bay and Siktefjellet groups and the Early–Late Devonian Andreé Land Group onshore northern Spitsbergen. Locally, the Cambrian–Ordovician formations contain petroleum source rocks with moderate total organic carbon contents and relatively high hydrogen index values, suggesting a good potential for oil generation. There are possible reservoirs, seals and traps in some of the basins but the CTSE generally holds a very limited potential as a petroleum province, particularly as the region is under strict environmental protection.

Early Cretaceous climatic influences on organic matter enrichment in lacustrine shales: Insights from the Liupanshan Basin of northwestern China

Organic-rich petroleum source rocks are widespread in Early Cretaceous strata, but the related paleoclimatic conditions are still uncertain. Aptian-Albian lacustrine sediments from the Liwaxia and Madongshan formations in the Liupanshan Basin of northwestern China provide vital material to reveal correlations between the Early Cretaceous paleoclimate and the formation of organic-rich lacustrine shales. Outcrop samples were analyzed for total organic carbon (TOC), C/N ratio, CaCO3 content, lipid biomarkers, and compound-specific n-alkane carbon isotopes. Results show that organic matter (OM) of the Liwaxia Formation was mainly sourced from lacustrine plankton and deposited in a weakly stratified and suboxic water column under a hot and arid climate. Organic matter in the lower part of the Madongshan Formation was derived from a mixture of aquatic organisms and higher plants under a warm and humid climate; plant carbon sources were widely available, and the water column was strongly saline, stratified, and anoxic. Elevated temperatures and a less humid climate accompanied the deposition of the upper part of the Madongshan Formation. Higher plants were the primary OM source, and the carbon source became limited. The water column was hypersaline and stratified, and the bottom water was less anoxic. Abrupt changes in the OM inputs and depositional environments documented in the Madongshan Formation were ascribed to global climatic variations. A warm and humid climate during the Aptian-Albian transition enhances continental nutrient inputs and promotes the formation of reduced water conditions, which directly controls the formation of the coeval organic-rich shales in lacustrine basins in China.

Preliminary Study of Chemical Elements Distribution in Petroleum Source Rocks Donga and Yogou Formations of the Termit Sedimentary Basin (Est-Niger)

Preliminary Study of Chemical Elements Distribution in Petroleum Source Rocks Donga and Yogou Formations of the Termit Sedimentary Basin (Est-Niger)

Helium - Relationships to other reservoir gases and some implications for exploration: The New Mexico Example

Helium (He) is the second most abundant element in the universe after hydrogen but is relatively rare on earth. He occurs as two stable isotopes, 3He and 4He. 4He is the dominant isotope in crustal gases and is a radiogenic decay product of uranium and thorium mainly in granitic basement rocks. 3He is dominantly primordial and primarily originates from the earth’s mantle. 3He may also be formed by radiogenic decay of 6Li (Lithium) which may be found in argillaceous sediments deposited in evaporitic settings. Although He occurs in most natural gases, it almost always occurs in extremely low, subeconomic concentrations, less than 0.1%. It is rare in concentrations more than 1%. A very few small reservoirs have gases with more than 7% He. Other gases that constitute the dominant components of helium-bearing natural gases are nitrogen (N2), carbon dioxide (CO2), and methane (CH4). The highest He concentrations occur where the dominant gas is N2 but most He has historically been produced as a byproduct of gases that are hydrocarbons. Hydrocarbons are generated from petroleum source rocks. Their presence in a reservoir is dependent upon the presence of a mature source rock in the basin and a migration path between the source rock and the reservoir. Large accumulations of CO2 in the southwestern U.S. resulted from the degassing of rising Tertiary magmas and subsequent migration of the gases into crustal reservoirs. N2 appears to originate mostly from degassing of the mantle but may also be formed in some strata by the thermal maturation of kerogens or by diagenetic alteration of clays or organic compounds in red bed sequences. The presence of economic concentrations of He in reservoir gases is dependent not only on an adequate source of 4He generated from granitic basement rocks but also on accommodating flux rates of N2, CO2, and CH4. These gases differ in their origins, places of generation and rates of generation, migration and emplacement. While basement-derived 4He and N2 enter reservoirs at slow rates over long periods of geologic time, hydrocarbons and CO2 enter the reservoir over much shorter time periods and dilute the 4He and N2. Basement-derived gases may be characterized by differing N2:He ratios which may indicate greater rates of He production within the crust in some areas. Exploratory drilling for He on Chupadera Mesa in the late 1990’s and early 2000’s encountered He-rich gases in Lower Permian strata. Isotopic analyses suggest that 93% of Chupadera Mesa He originated from radiogenic decay in crustal rocks while 7% is derived from the mantle or with a possible contribution by evaporitic Permian shales. Marked differences in the CO2 concentrations in different strata indicate that some strata acted as carrier beds for magmatically-derived CO2 while strata with N2-rich and CO2-poor gases were isolated from CO2 sources.

Canadian Arctic–Beaufort Sea Rifted Margin Tectono-Sedimentary Element, SE Canada Basin

Abstract The Canadian Arctic–Beaufort Sea Rifted Margin (CARM) Tectono-Sedimentary Element (TSE) is located on the continental shelf and slope that lie to the west of the Canadian Arctic Archipelago and to the north of the Mackenzie Delta. The TSE comprises the rift succession deposited on the eastern and southern margins of the Amerasia Basin, coincident with the opening of this basin. The TSE strata range in age from the latest Triassic (Rhaetian) to Early Cretaceous (Albian). A major unconformity marks the base of the TSE, with underlying rocks consisting of moderately to highly deformed Proterozoic and Lower Paleozoic rocks that are regarded as basement. The TSE is overlain by the Canadian Arctic Prograded Margin (CAPM) TSE, with the boundary being a significant unconformity in landward areas. Well data are limited to the Beaufort–Mackenzie area, and reflection and refraction seismic data indicate that the succession is up to 4 km thick. The TSE is divided into four structural domains, with deformation increasing to the north. The Beaufort–Mackenzie Domain is dominated by extensional structures, with later contractional structures present in its western portion. The Southern Domain is extensional and characterized by normal faults with tilted fault blocks. The structure of the Central Domain is similar to that of the Southern Domain but may include broad folds formed during the Paleogene Eurekan Orogeny. The succession in the Northern Domain is likely to be strongly folded and cut by thrust faults of the Eurekan Orogeny. Cretaceous extrusive and intrusive basic rocks, related to magmatism in the northern Amerasia Basin, are present in both the Central and Northern domains. Petroleum source rocks, of both lacustrine and marine origin, may be present in the Jurassic portion of the succession and marine shales in the Lower Cretaceous succession. The potential for structural and stratigraphic traps in widespread sandstone units of alluvial fan to marine slope origin is high. The remote location of the TSE, however, makes it likely that it will not be a target for petroleum exploration in the foreseeable future.

Characterising the economic Proterozoic Glyde Package of the greater McArthur Basin, northern Australia

The greater McArthur Basin is an informal term for a Palaeo-to-Mesoproterozoic sedimentary system that consists of terranes from the McArthur Basin, Birrindudu Basin, and the Tomkinson Province. These spatially distant basins are interpreted to connect in the subsurface based on geophysical, lithological, and geochronological evidence. The coeval sedimentary units of the greater McArthur Basin were subdivided into non-genetic depositional ‘packages’ bookended by regional unconformities. In ascending order, these packages are the: Redbank, Goyder, Glyde, Favenc, and Wilton Packages. The ca. 1660–1610 Ma Glyde Package is the focus of this study and includes the economically important Barney Creek Formation, found in the McArthur Basin sensu stricto. The Barney Creek Formation hosts the world-class, sediment-hosted, Zn-Pb-Ag McArthur River deposit. Importantly, it is also a key petroleum source rock and unconventional hydrocarbon reservoir, containing Australia’s geologically oldest oil and gas discoveries and forming a part of the McArthur Petroleum Supersystem. Consequently, identifying chronostratigraphically similar units elsewhere in the greater McArthur Basin is important for explorers in finding analogous economic resources.In situ Rb–Sr geochronological results of the Barney Creek Formation shales sourced from borehole LV09001 yielded ages of 1634 ± 59 Ma and 1635 ± 67 Ma. Shale samples from Fraynes Formation in borehole Manbulloo S1 were dated at 1630 ± 57 Ma and 1636 ± 42 Ma using the same approach. These ages are in good agreement with U–Pb ages of tuffaceous layers from the same units, suggesting that they represent their early burial histories and not secondary, post-depositional events. These results indicate that the Fraynes Formation and the Barney Creek Formation are direct chronostratigraphic equivalents, with ages within analytical error of each other.In addition to the geochronological similarities, the δ13Ccarb,87Sr/86Sr, and δ88/86Sr isotopic constraints from both units also display parallel geochemical fingerprints up-section. These include a positive δ13Ccarb excursion of ∼2.0 ‰, a trend towards more crustal-dominated 87Sr/86Sr ratios, and a negative δ88/86Sr excursion of ∼-0.25 ‰. These findings further support the application of isotopic chemostratigraphy as a powerful tool to correlate distal carbonaceous rocks in the basin system. Importantly, these geochemical fingerprints also show that the McArthur Group and the Limbunya Group experienced similar changes in palaeoenvironments during the evolution of the basin system. However, trace element data collated in this study indicates that they may have recorded different, heterogeneous palaeoredox histories. Geochemical models based on redox-sensitive trace elements V and Mo suggest that the Fraynes Formation sustained a much more euxinic water column as opposed to the Barney Creek Formation. These differences may have implications for the accumulation and preservation of base metals and hydrocarbons within the sediment.

The Environment Effect on Differential Organic Matter Enrichment of the Lower Cambrian Shale in the Tarim Basin, NW China

AbstractThe early Cambrian shale is of an important petroleum source rock on the Earth. Due to few drilling data and poor seismic data, the organic matter enrichment of the Lower Cambrian shale is still an enigma in the Tarim Basin. Total organic carbon (TOC), major and trace element data of shale samples from five boreholes were experimented to decipher the mechanism of the organic matter enrichment in the early Cambrian shales. The results show that the shales deposited in the western restricted intraplatform have much higher TOC contents (3.2%–19.8%, on average 11.0%) than those from the eastern basin (2.2%–10.2%, on average 4.5%). The paleoproductivity proxies (Ba, Ba/Al, P/Al) in the western restricted platform are much higher than those in the eastern basin. The trace element indicators such as V/Cr, Ni/Co, Mo‐TOC and MoEF‐UEF suggest an anoxic environment across the basin, but a more restricted environment in the western intraplatform. It is concluded that the paleoproductivity rather than anoxic condition and hydrothermal activity have resulted in the differentiation of the organic matter enrichment from the western intraplatform to eastern basin in the early Cambrian shales, and restricted environment is favorable for paleoproductivity and preservation of organic matter.

Geophysical characterisation and improved delineation of coaly source rocks from integrated analysis of laboratory, well and seismic data

Coaly facies (coal, shaly coal and coaly mudstone) are proven petroleum source rocks in many sedimentary basins in New Zealand, Australia and Southeast Asia. Often these source rocks are mapped in the subsurface based on sparse well data and seismic amplitude character and their organic richness is estimated using average TOC (total organic content) values from well data. However, as the lateral distribution and organic richness of coaly facies are highly heterogeneous and the seismic amplitude response of facies is non-unique, delineation of coaly facies and TOC estimation away from wells are highly uncertain. To reduce this uncertainty, we characterised coaly facies in Cretaceous–Eocene intervals in Taranaki and Great South Basins using density, P-wave velocity, P-impedance and TOC data from 13 wells, supplemented with rock physics and TOC data of numerous coal samples collected from mines and outcrops around New Zealand. We then carried out a case study from the Paleocene–Eocene interval in the Maari 3D seismic survey area in offshore Taranaki Basin in which we develop a P-impedance model and delineate the coaly facies away from wells based on P-impedance character. Average P-impedance maps were analysed together with seismic amplitude character, structure maps and depositional environment maps to understand lateral and temporal variation of coaly facies. These maps were then converted to proxy-TOC maps using a relationship developed from the outcrop coal samples. The coaly facies show density <2.5 g/cc, P-wave velocity <4000 m/s, P-impedance <9000 m/s × g/cc and varied TOC character in the Cretaceous–Eocene interval.

The potential extent of Early Triassic Kockatea Shale equivalent source rocks in the Northern Carnarvon and Perth Basins, Western Australia

In the northern Perth Basin (Western Australia), the Early Triassic Kockatea Shale is the primary petroleum source rock. Possible source rocks in the Northern Carnarvon Basin are more varied and include the Upper Jurassic Dingo Claystone as well as the Early Triassic Locker Shale. Biomarker analyses were conducted on petroleum samples from these basins to understand the nature of the petroleum systems. Many of the analysed petroleum samples contain carotenoids (okenane, chlorobactane and isorenieratane) derived from photosynthetic sulfur bacteria, suggesting that their source rocks were deposited under conditions of photic zone euxinia (PZE) and/or derived from microbialites. In the northern Perth Basin, the major lithofacies contributing to the source rock are dark coloured mudstones deposited under PZE conditions and/or derived from microbialites. In the southern Perth Basin, the potential source rock is either Permian, Jurassic or Cretaceous in age as indicated by the low concentrations or absence of carotenoids and the Triassic biomarker n -C 33 alkylcyclohexane. There is also a possibility that the Lower Triassic Locker Shale is the source rock of petroleum in the Tubridgi field on the Peedamullah Shelf of the Northern Carnarvon Basin, based on the similarity of biomarkers to Perth Basin petroleum sourced from the Kockatea Shale. However, the possibility of charge from the Upper Jurassic Dingo Claystone cannot be entirely excluded. Supplementary material: biomarker dataset is available at https://doi.org/10.6084/m9.figshare.c.6452153

Geochemistry and petrology of petroleum source rocks in the Upper Cretaceous Qingshankou Formation, Songliao Basin, NE China

The Upper Cretaceous Qingshankou Formation in the Songliao Basin, NE China is known to contain excellent petroleum source rocks. In addition, it serves as a valuable record to study depositional conditions within the water column and climatic change. In this study, a large set of organic petrography, major and trace element geochemistry, as well as bulk and molecular organic geochemistry data obtained on 38 core samples of the first Member of the Qingshankou Formation (K2qn1) in the south central depression is reported. All rocks are thermally oil-mature, reaching the early to peak oil generation stage, indicated by the vitrinite reflectance (VRr) of approximately 0.8%. Two different types of lacustrine source rocks (units I and II) and two OM-rich layers within unit I are identified in the studied well. Basically, there is a lower unit 1, characterized by lower total organic carbon (TOC) content and an upper unit 2 characterized by higher TOC content. Furthermore, within unit 1, thin marine transgressive layers of approximately 1–2 m were identified. Generally, unit 1 is characterized by the lowest TOC and sulfur contents with average values of 1.31 wt% and 0.56 wt%, respectively. By contrast, unit 2 samples have significantly higher TOC (avg. 2.39 wt%) and sulfur contents (avg. 1.24 wt%). Samples, which represent the postulated marine transgressive events show the highest TOC (avg. 2.82 wt%) and sulfur contents (avg. 2.01 wt%). Unit 1 was mainly deposited in oxic-dysoxic and freshwater-brackish water column conditions based on multiple organic and inorganic geochemical proxies. By contrast, unit 2 and marine transgressive layers were deposited in less oxygenated and more saline environments. Source rocks from the K2qn1 generally show only minor terrestrial organic matter input. However, unit 1, containing type II-III kerogen, shows indications for a slightly more pronounced contribution from terrigenous higher plants than unit 2 and the marine transgressive layers, where the kerogen is almost exclusively derived from planktonic/algal and microbial organic matter. The low TOC content in unit 1 is attributed to multiple adverse factors for organic matter accumulation, including a relatively shallow, oxic-dysoxic, and weakly stratified water column and high dilution by terrigenous mineral matter. By contrast, more favorable conditions persisted during the deposition of marine transgressive layers and unit 2, e.g., a more reducing and stratified water column and lower dilution by terrigenous mineral matter.

Petroleum source rocks and hydrocarbon potential of Lower Paleozoik deposits in Laisky swell of Denisovsky trough, Timan-Pechora Petroleum Province (based on Kerlaiskaya-1 well data)

Petroleum source rocks and hydrocarbon potential of Lower Paleozoik deposits in Laisky swell of Denisovsky trough, Timan-Pechora Petroleum Province (based on Kerlaiskaya-1 well data)

Organic petrography and trace element geochemistry of organic black shales in the Kribi Campo sub-Basin, West Africa: Implication for petroleum source rock evaluation and depositional environment

The aim of this study was to characterise the maceral properties, depositional environment and petroleum source rock properties of black shales deposits of the lower Mundeck Formation of the Douala Kribi Campo sub-basin from organic petrography and trace element geochemical studies. The study showed that the Kribi Campo shales are typically dominated by the liptinite group of macerals, followed by vitrinite and the inertinite group respectively. The liptinite group is primarily represented by lamalginite, bituminite and solid bitumen, while vitrinite consists primarily of collotelinite, vitrodetrinite, and corpogelinite. The inertinite maceral group is the least abundant and is represented by fusinite, semifusinite, pyrolytic carbon, funginite and inertodetrinite. The constituents of the maceral in the shales point to a type II and III kerogen which are proficient of generating oil and gas. Based on vitrinite reflectance, the shales may be classified as being subbituminous A/B to subbituminous and A/high volatile bituminous C in rank. In terms of petroleum production, these shales are regarded as thermally immature with an indicated Tmax temperature (from programmed pyrolysis) of 421 °C.Trace element ratios of Sr/Ba for the studied shales shows values between 0.18 to 0.34 indicating that the shales were deposited in both fresh water and estuary environment. The estuary environment may have resulted from marine contamination to fresh water environment as this is seen only in one shale sample. The V/Ni and V/V+Ni ratio of the studied shales is >1 and ranges from 0.60–0.94 respectively, revealing their deposition in an anoxic environment.

Preliminary results of petroleum source rock evaluation of Mongolian Mesozoic oil shales

Jurassic and Cretaceous oil shale samples, collected from northern and central Mongolian basins, have been analyzed to determine their petroleum source rock potential. The contents of total organic carbon (TOC) and total sulfur, and source rock screening data were obtained by Rock-Eval pyrolysis. Cretaceous oil shales contain up to 17.4 wt.% TOC and Hydrogen Index (HI) values range from 638-957 mg HC/g TOC. Jurassic oil shale samples have similar TOC contents, ranging from 10.7 to 17.3 wt.%. HI values of Jurassic Tsagaan-Ovoo oil shale vary between 270-313 mg HC/g TOC. Average Tmax values of Cretaceous and Jurassic samples are 4370C and 4230C, respectively. This observed data indicates that both Jurassic and Cretaceous oil shales are excellent source rock. Cretaceous oil shales contain type I kerogen (highly oil prone), while Jurassic Tsagaan-Ovoo oil shale has mixed type II/III kerogen (mixed oil and gas prone). Based on Tmax and Production Index values, both Jurassic and Cretaceous oil shales are immature. Overall, the result of this study contributes organic geochemistry database of Mongolian oil shale and encourages source rock potential of both Jurassic and Cretaceous oil shale.

Перспективы нефтегазоносности нижнедевонских отложений гряды Чернышева (Тимано-Печорская нефтегазоносная провинция)

The Chernyshev Swell is one of the poorly studied and promising areas for the hydrocarbon (HC) exploration in the north of the Timan-Pechora Petroleum Province. Lower Devonian carbonate deposits as part of the Middle Ordovician-Lower Devonian petroleum complex are considered as a priority object for the HC exploration. The study of the Lower Devonian deposits in well core and outcrop showed that the reservoirs were represented mainly by fractured-cavern-pore and cavern-fractured dolomites. The porosity of the rocks reaches 9.3 % with a predominance values in the range of 0.5–1.5%. The permeability values up to 1.0×10–15 m2 are predominant, less often in the range of 1–10×10–15 m2. Such filtration and capacitive properties characterize them as low-capacity and low-permeable reservoirs. The best properties of reservoirs are associated with facies of carbonate shallows, small biostomes and biogerms. The petroleum source rocks are contained in the clay-carbonate unit of the Ovinparma Formation. The OM richest rocks (Corg — 1.08–1.88%) are characterized by the values of (S1+S2) generation potential — 2.18–8.65 mg HC/g rock and hydrogen index HI — 153–432 mg HC/g Corg, which classifies them as medium petroleum source rocks. Thus, the presence of reservoirs, petroleum source rocks and overlapping by the Upper Devonian regional seal is a favorable condition for the formation of HC deposits in the Lower Devonian.