Potential Hydrocarbon Source Rocks Research Articles

Opening up a window into ecosystems with Ediacara-type organisms: preservation of molecular fossils in the Khatyspyt Lagerstätte (Arctic Siberia)

The Khatyspyt Formation in Arctic Siberia is one of only two carbonate settings with Ediacara-type fossils. As a potential hydrocarbon source rock, it contains abundant molecular fossils that may help to expand our understanding of these ecosystems. Unfortunately, however, the molecular fossil record in geological materials is commonly biased by secondary processes such as thermal maturation, migration of bitumen compounds or surface contamination. In this study, we evaluate the preservation of molecular fossils in a sample from the Khatyspyt Formation and elucidate their paleobiological meaning. Our results reveal that the organic matter is remarkably immature (oil window maturity) and shows little effect of biodegradation. Petrographic observations, exterior/interior experiments, and the similarity between free bitumen, mineral-occluded bitumen, and kerogen pyrolysate point to the syngeneity of the molecular fossils. Abundant hopanes, cyclohexylalkanes, and methyl-branched alkanes indicate a bacterial source of the organic matter, likely including cyanobacteria and anaerobic bacteria. At the same time, a carbonaceous compression fossil on top of the sample and abundant steranes indicate the presence of eukaryotes. The steranes show typical distributions for the Ediacaran (i.e., dominance of stigmastane). Given the exceptional preservation of the body fossils, trace fossils, and molecular fossils, the Khatyspyt Formation can be considered a fossil lagerstatte sensu Seilacher (1970: Begriff und Bedeutung der Fossil-Lagerstatten. Neues Jahrbuch fur Geologie und Palaontologie, Monatshefte: 34–39). The combined analysis of sedimentary facies, paleontology (body, trace, and molecular fossils), and biogeochemistry will provide a more complete understanding of ecosystems with Ediacara-type fossils.

Total shale oil inventory from an extended Rock-Eval approach on non-extracted and extracted source rocks from Germany

Rock-Eval pyrolysis data are used for assessments of the quality and maturity of potential hydrocarbon source rock, but is also often applied among shale oil studies to estimate the so-called “total oil” for Oil In Place (OIP) calculations. However, for these approaches Rock-Eval may underestimate total oil due to a “carryover effect”, a bias which is particularly crucial for shale oil investigations.In this study we examined the total oil of marine to lacustrine source rocks from German shale oil formations using data from Rock-Eval combined with solvent extraction. Each source rock was analysed by Rock-Eval both non-extracted and extracted to obtain values for total oil (= [S1wholerock−S1extracted rock]+[S2wholerock−S2extracted rock]). Comparison of these two data sets revealed that for the individual formations in average 17–23% of the S2 fraction is extractable, herein termed “S2 oil”. This “S2 oil” increases the total oil amount compared to the conventional free oil (S1) by average factors of 2.2–3.6. For selected source rocks the molecular composition of the “S2 oil” was obtained by a specific approach: Rock-Eval analysis was terminated after S1-detection at 301°C, samples were retrieved, solvent extracted and analysed by gas chromatography. Depending on the type of organic matter and maturity, the “S2 oil” contains significant amounts of higher boiling hydrocarbons such as n-alkanes but also contributes to the unresolved complex mixture. It is to date unclear, how much of this “S2 oil” should be finally considered as technically mobilized shale oil.

Rock-Eval pyrolysis and organic petrographic analysis of the Maastrichtian coals and shales at Gombe, Gongola Basin, Northeastern Nigeria

The Gongola Basin forms one of the inland Cretaceous to tertiary sedimentary basins in Nigeria with relatively unknown petroleum system. In this study, the investigated source rock intervals of the Maastrichtian Gombe Formation are located at the Maiganga coal mine, near Gombe, Gongola Basin, Nigeria. The exposed part of the mine consists of about 35-m thick coarsening upward section with the basal part made up of coal and shale interbeds while the upper part consists of siltstone and sandstone and probably deposited in fluvio-deltaic environment. The coal and interbedded shale appear most prospective source rock facies in the formation and were evaluated with respect to their hydrocarbon source rock potential. The organic geochemical results showed high TOC for the coals (37.71–65.29 wt%) and moderate organic carbon concentration (1.19–4.81 wt%) for the shales. S2 values ranges from 57.96 to 103.21 mgHC/g rock and 0.51–6.22 mgHC/g rock for the coal and shales, respectively. The HI is less than 200 mgHC/gTOC in all the coal and shale samples suggesting Type III kerogen and predominant plant contributions from terrestrial sources. Consequently, gaseous hydrocarbon potential is exhibited in the source beds. The organic petrography shows vitrinite as dominant maceral followed by inertinites and liptinites with inorganic minerals like pyrite and kaolinite. The Tmax is less than 435 °C in all the samples indicating pre-oil window stage; this is corroborated by the Romax value ranging from 0.45 to 0.55 %. Plot of PI against Tmax indicates low level organic matter conversion while the vitrinite reflectance values suggest a sub-bituminous coal. The study suggests that the investigated coal and shale samples constitute good source rock and have potential for gas. The generally low HI in the coals and the associated shales indicate more allochthonous and hydrogen poor organic matters in the source beds. Maceral composition of the coals suggests wet swamp environment and predominance of arborescent vegetation type. At present level, the organic matters are immature to marginally mature deeper level equivalents might have generated gas.

BURIAL AND THERMAL HISTORY MODELLING OF THE MANNAR BASIN, OFFSHORE SRI LANKA

The Mannar Basin is a Late Jurassic – Neogene rift basin located in the Gulf of Mannar between India and Sri Lanka which developed during the break‐up of Gondwana. Water depths in the Gulf of Mannar are up to about 3000 m. The stratigraphy is about 4 km thick in the north of the Mannar Basin and more than 6 km thick in the south. The occurrence of an active petroleum system in the basin was confirmed in 2011 by two natural gas discoveries following the drilling of the Dorado and Barracuda wells, located in the Sri Lankan part of the Gulf. However potential hydrocarbon source rocks have not been recorded by any of the wells so far drilled, and the petroleum system is poorly known. In this study, basin modelling techniques and measured vitrinite reflectance data were used to reconstruct the thermal and burial history of the northern part of the Mannar Basin along a 2D profile.Bottom‐hole temperature measurements indicate that the present‐day geothermal gradient in the northern Mannar Basin is around 24.4 oC/km. Optimised present‐day heat flows in the northern part of the Mannar Basin are 30–40 mW/m2. The heat flow histories at the Pearl‐1 and Dorado‐North well locations were modelled using SIGMA‐2D software, assuming similar patterns of heat flow history. Maximum heat flows at the end of rifting (Maastrichtian) were estimated to be about 68–71 mW/m2.Maturity modelling places the Jurassic and/or Lower Cretaceous interval in the oil and gas generation windows, and source rocks of this age therefore probably generated the thermogenic gas found at the Dorado and Barracuda wells. If the source rocks are organic‐rich and oil‐ and gas‐prone, they may have generated economic volumes of hydrocarbons.

Bioturbating animals control the mobility of redox-sensitive trace elements in organic-rich mudstone

Bioturbating animals modify the original mineralogy, porosity, organic content, and fabric of mud, thus affecting the burial diagenetic pathways of potential hydrocarbon source, seal, and reservoir rocks. High-sensitivity, synchrotron rapid scanning X-ray fluorescence elemental mapping reveals that producers of phycosiphoniform burrows systematically partition redox-sensitive trace elements (i.e., Fe, V, Cr, Mn, Co, Ni, Cu, and As) in fine-grained siliciclastic rocks. Systematic differences in organic carbon content (total organic carbon >1.5 wt%) and quality (Δ13Corg~0.6‰) are measured between the burrow core and host sediment. The relative enrichment of redox-sensitive elements in the burrow core does not correlate with significant neo-formation of early diagenetic pyrite (via trace metal pyritization), but is best explained by physical concentration of clay- and silt-sized components. A measured loss (~–15%) of the large-ionic-radius elements Sr and Ba from both burrow halo and core is most likely associated with the release of Sr and Ba to pore waters during biological (in vivo) weathering of silt- to clay-sized lithic components and feldspar. In conclusion, this newly documented effect has significant potential to inform the interpretation of geochemical proxy and rock property data, particularly from shales, where elemental analyses are commonly employed to predict reservoir quality and support paleoenvironmental analysis.

Source rock potential of lignite and interbedded coaly shale of the Ogwashi–Asaba Formation, Anambra basin as determined by sequential hydrous pyrolysis

Outcrops in the Anambra Basin in southern Nigeria contain Paleogene Imo Shale (marine), the Neogene paralic Ogwashi–Asaba and the continental Benin Formations, representing equivalents of the subsurface successions in the Niger Delta Basin. Thirty-three samples of lignite and the interbedded coaly shale of the Ogwashi–Asaba Formation were investigated petrologically before Rock-Eval screening. Two selected samples of lignite and coaly shale were subjected to sequential hydrous pyrolysis (HP) at 330°C for 72h and at 355°C for 72h to characterize their oil and gas potential. The lignite sample has a Rock-Eval hydrogen index (HI) of 481mg/g TOC and a mean vitrinite reflectance of 0.36% Rom. The total amount of expelled oil generated in the sequential HP experiments is 259mg/g of original total organic carbon (TOCorig). This expelled waxy oil has abundant high-molecular-weight n-alkanes and an extremely high pristane/phytane ratio of 6.5, typical of crude oils generated from coals as observed in some onshore and shallow offshore accumulations of the Niger Delta. The overlying coaly shale has a lower HI of only 191mg/g TOC. The total amount of expelled oil generated in the sequential HP experiments is only 15mg/g TOCorig. This oil is not waxy and has a pristane/phytane of 2.6, which is more typical of a marine source rock. These results are contrary to the idea that coaly shale associated with coal is the main source of oil. The greater yields of expelled oil from the coal relative to the coaly shale are attributed to the higher liptinite content in the former and the possibility that the organic matter in the latter was oxidized prior to deposition. δ13C of the methane generated at 355°C for 72h is −39.5‰ for the lignite and −35.0‰ for the coaly shale. This suggests different methane precursors in these two lithologies. The data set reveals remarkable differences in the characteristics of the two types of source rocks in the Ogwashi–Asaba Formation and their potential to contribute a mixture of hydrocarbons derived from intervals that are stratigraphically only meters apart. These results suggest that coal and coaly shale within the thermally mature stratigraphic levels of the Agbada Formation in the sub-surface are potential source rocks for liquids and gaseous hydrocarbons in the Niger Delta.

Basin evolution and oil shale deposition during Upper Cretaceous in the Songliao Basin (NE China): Implications from sequence stratigraphy and geochemistry

The controlling factors of oil shale formation within the Upper Cretaceous Qingshankou and Nenjiang Formations of the Songliao Basin are investigated by petrological and geochemical methods. Sediment deposition was balanced by basin subsidence, resulting in the accumulation of Cretaceous strata of high thickness. Global sea level fluctuations have been related to periods of oil shale deposition within the basin. The results indicate a comparable depositional environment during oil shale formation within the two Upper Cretaceous strata with respect to palaeotectonic and palaeoclimate, but differences in the accommodation space during accumulation of the two formations. The larger accommodation space during deposition of the Nenjiang Formation resulted in the higher thickness and wider distribution of the oil shale members (total thickness: 11.2–32m; distribution area 4.48×103km2) within the basin, as compared to the oil shale of the Qingshankou Formation (total thickness: 2–19.3m; distribution area 1.3×103km2).Further differences exist with regard to the palaeoenvironment of oil shale formation and primary productivity. Deposition of the Qingshankou Formation 1st member and Nenjiang Formation 1st member took place within a saline-brackish lake under anoxic conditions in the bottom water. Preservation of organic matter is suggested to have been less favorable during deposition of the Nenjiang Formation 2nd member. Higher primary productivity is believed to be the responsible factor for the accumulation of organic-rich sediments in the Qingshankou Formation 1st member. The interplay of these two factors (i.e. preservation, productivity) leads to the formation of oil shale in the Qingshankou Formation (average TOC: 8.32%; TOCmax: 13.52%; average oil yield: 5.57%/) with better hydrocarbon source rock potential and slightly higher oil yield during pyrolysis as in the Nenjiang Formation (average TOC: 7.76%; TOCmax: 9.7%; average oil yield: 5.54%).Primary productivity is suggested as the main controlling factor on differences in oil shale quality and source rock potential between the two formations, whereas the variations in quality within each formation mainly depend on the preservation of organic matter. The high thickness, wide spatial distribution and excellent hydrocarbon potential of the Upper Cretaceous oil shales in the Songliao Basin are suggested to have been the result of large accommodation space, stable palaeoenvironmental conditions, and high primary productivity.

Source and Reservoir Rock Potential of Tertiary Units in the Kozaklı Basin, Central Anatolia, Turkey

The authors present the hydrocarbon source rock potential and reservoir properties of the Eocene Formations in the Central Anatolian Kozaklı Basin. Potential source and reservoir rocks in the Kozaklı basin include transgressive-regressive bank carbonates, fore-bank, deep-marine shales and sandstones, and coal and bituminous facies. The organic geochemical data of the Middle Eocene shales (Sarılar Formation) show that inadequate to marginal source rock qualities, and marginally mature to overmature characteristics, resulting from heat flow regime of the studied area. Alemli Member of the İncik Formation is good to excellent according to TOC wt% and immature to mature source rock from Tmax values. Sedimentological features and age data indicate that the Uzunlu Formation was deposited under the control of antecedent topography. Reservoir properties of the Uzunlu Formation and Keklicek member indicate that the carbonate unit is not adequate for reservoir rock. However, siliciclastics of the Sarılar Formation could be reservoir potential due to its high porosity and permeability values.

Hydrocarbon potential of Ordovician–Silurian successions in Akkas field, western desert of Iraq

The shale beds of the Khabour and Akkas Formations (Ordovician–Silurian) in Akkas field of western Iraq have been studied to determine their hydrocarbon-generation potential. The total organic carbon (TOC) values of the Khabour Formation were generally low and associated with low S2 and hydrogen index (HI) values indicating that this formation is not a hydrocarbon source, although this could reflect advanced thermal maturity. The gray-green shales of the upper part of the Akkas Formation also have low TOC and S2 values. On the other hand, the TOC, S2, and HI values of the black shales of the lower part of the Akkas Formation were high. The values indicate that the gray-green shales of the upper part of the Akkas Formation are not petroleum sources, whereas the black shales of the lower part can be regarded as potential hydrocarbon source rocks. Organic petrology studies reveal that marine amorphous organic matter is predominant, and no significant differences were observed between Khabour and Akkas samples in terms of organic-matter type. Molecular geochemical data also indicate that the kerogen of the two formations is of similar origin. The normal alkane distribution is unimodal, with a maximum at , indicating marine algal organic matter. Rock-Eval and biomarker data indicate that the organic matter of the black shales of the lower part of the Akkas Formation is early mature, whereas the Khabour Formation is highly mature in the Akkas field.

Local source rock palynology of ANL -1 and E -12 wells sediments offshore Niger delta, Nigeria: Implication for hydrocarbon prospectivity.

Local source rock potential of ANL-1 and E-12 well sediments in offshore, NigerDelta have been evaluated based on organic matter maturation studies to provideleads for hydrocarbon exploration. The studied wells display diverse palynoflora atdifferent stratigraphic levels and indicate variable palaeoecological conditions of thedepositional environment. E -12 well sediments are composed of the lower Agbadaformation and are thermally mature (TAI 2.8; 1932 -2238 m and TAI 3.0; 2410 –2603 m ), showing top of oil window and intense generation of liquid hydrocarbonwhile the upper part ( TAI 1.7; 1230 – 1770 m) and the overlying Benin formation(TAI 1.5; 681 – 1176 m) are thermally immature. Immature (TAI 1.3) thermal faciesis determined for depths: 216 – 1773 m (Benin formation) in the ANL -1 well, whilemature (TAI 2.7) thermal facies is determined for depths: 1863 – 2556 m and TAI3.0 is determined for depths 2583 – 3663m (Agbada formation) in the ANL – 1 well.Shale of the lower and upper part of Agbada formation in the ANL – 1 and E – 12indicates an optimum maturation level of a good hydrocarbon source rock potential.

Hydrocarbon potential, thermal maturation of the Jurassic sequences, and the genetic implication for the oil seeps in North Thrust Zone, North Iraq

The organic geochemistry is studied for the rocks of three Jurassic formations: Sargelu, Naokelekan, and Chia Gara from the north of Iraq. These rocks comprise bituminous carbonate and shale rocks. The hydrocarbon source rock potential is evaluated by using total organic carbon (TOC) and Rock-Eval Pyrolysis. The prevalence of high values of TOC (2.21–45.12 wt.%) associated with moderate to high values of HI (225–550 mg HC/g TOC), low OI (1–33 CO2/g TOC), and high S2 values (4.53–181.0) indicate very good to excellent source rock potential for these rocks with mostly type II kerogen and few mixed-type II/III kerogen of oil prone source rocks. This is supported by high values of S2/S3 ratios (>5). Tmax values range from 440 to 447 °C in agreement with the calculated R o values (0.76–0.90) infer early to peak thermally mature stage. Based on the TOC and pyrolysis data, the rocks of the three formations have indigenous hydrocarbon mature oil prone. The geochemical investigation of biomarker parameters were performed for oil samples from two oil seepages (Banik and Tawke) which are located in the same area using gas chromatography-mass spectrometry and stable carbon isotope measurements. The measured values of Pr/n-C17 for oil samples are low coupled with high values of Ph/n-C18 indicating marine organic matters with type II kerogen accumulated under marine reducing condition. The values and plots of δ13C (saturate and aromatic) also approve the prevalence of marine reducing condition. The source rocks for the oils of both seepages are interpreted to be carbonate rocks of Mesozoic age by the measured CV values which are 0.25. All these data are in consistent with marine carbonate source rocks for these oils. The paleoredox depositional environment for the source rocks is interpreted by the low value of Pr/Ph (0.74 in Banik) and high values of homohopane ratio C35S/C34S (1.21 in Banik and 1.13 in Tawke); the values of C29/C30 (norhopane/hopane >1) as well as the high sulfur content all indicate reducing condition during the deposition of the marine source rocks. The concentrations of C27, C28, and C29 reflect the prevalence of marine algal plankton organic matters. The measured Oleanane index equal zero which indicates age older than Lower Cretaceous for the source rocks. This documented by the calculated values of C28/C29 sterane ratio, and plots on Geomark Research database gives an age of Middle–Upper Jurassic for the source rocks. According to the characteristics of depositional environment of the source rocks, the paleoredox condition, and age estimation, the oils of Banik and Tawke could be derived from the rocks of Sargelu, Naokelekan, and Chia Gara Formations.

Palynofacies characterization for evaluation of hydrocarbon source rock potential of Lower Paleogene (Thanetian-Ypresian) sub-surface sediments of Barmer Basin, western Rajasthan, India

This paper deals with the hydrocarbon source rock evaluation and depositional environment of Lower Paleogene sub-surface sediments from borehole MMK-26 of Barmer Basin, Rajasthan. Hydrocarbon potential of these sediments are estimated on the basis of plant derived Sedimentary Organic Matter (SOM) analysis. The palynofacies analysis indicate that the sediments are rich in organic matter with amorphous organic matter constituting the majority of the SOM in the lower part of the borehole where as the phytoclasts dominate in the upper part. The dominance of sapropelic facies (Amorphous Organic Matter) at a depth of 152 m and below suggests that these sediments are a good source for hydrocarbon generation. Further the categorized palynofacies components are plotted on Tyson's Amorphous Organic Matter-Phytoclast-Palynomorph diagram which reveal that the studied sediments are characterized by type-II (oil generating) and type – III kerogen deposited in a dysoxic – anoxic shelf. Thermal Alteration Index (TAI) values were determined to asses the organic maturity of the sediments and a maturation value of 2.80–3.0 for the lower part of the bore core suggest that the sediments have attained an optimum maturation level to produce hydrocarbons. The increasing frequency of marine palynomorphs in association with continental components indicates a transgressive phase of sea level during the deposition of the studied sediments.

Petroleum Source Rock Assessments of the Upper Permian Strata in the Central Taurus Region of Turkey

This study presents the hydrocarbon source rock potential and organic maturity of the Upper Permian Tozara Formation in the Gazipaşa-Sugözü area in the central Taurus region. The Tozara Formation deposited oxic to dysoxic shelf conditions consists of algal limestone and organic matter-rich shales. In order to assess the hydrocarbon source rock potential of the Upper Permian lithologies, two different stratigraphic sections described and sampled for organic geochemical analyses and determination of mineralogical composition.

Lower Cretaceous black shales of the Western Carpathians, Czech Republic: Palynofacies indication of depositional environment and source potential for hydrocarbons

Uppermost Jurassic and Lower Cretaceous strata of the Silesian Nappe of the Outer Western Carpathians contain large amounts of shale, which can, under favourable conditions, become source rocks for hydrocarbons. This study analysed 45 samples from the area of Czech Republic by the means of palynofacies analysis, thermal alteration index (TAI) of palynomorphs and total organic carbon (TOC) content to determine the kerogen type, hydrocarbon source rock potential, and to interpret the depositional environment. Uppermost Jurassic Vendryně Formation and Lower Cretaceous Formations (Těšín Limestone, Hradiště and Lhoty) reveal variable amount of mostly gas prone type III kerogen. Aptian Veřovice Formation has higher organic matter content (over 3 wt.%) and oil-prone type II kerogen. Organic matter is mature to overmature and hydrocarbon potential predisposes it as a source of gas. Aptian black claystones of the Veřovice Fm. are correlatable with oceanic anoxic event 1 (OAE1).

Hydrocarbon Source Rock Potential of the Sinamar Formation, Muara Bungo, Jambi

DOI: 10.17014/ijog.v1i1.175The Oligocene Sinamar Formation consists of shale, claystone, mudstone, sandstone, conglomeratic sandstone, and intercalation of coal seams. The objective of study was to identify the hydrocarbon source rock potential of the Sinamar Formation based on geochemichal characteristics. The analyses were focused on fine sediments of the Sinamar Formation comprising shale, claystone, and mudstone. Primary data collected from the Sinamar Formation well and outcrops were analyzed according to TOC, pyrolisis analysis, and gas chromatography - mass spectometry of normal alkanes that include isoprenoids and sterane. The TOC value indicates a very well category. Based on TOC versus Pyrolysis Yields (PY) diagram, the shales of Sinamar Formation are included into oil prone source rock potential with good to excellent categories. Fine sediments of the Sinamar Formation tend to produce oil and gas originated from kerogen types I and III. The shales tend to generate oil than claystone and mudstone and therefore they are included into a potential source rock.

Paleo-productivity evolution across the Permian-Triassic boundary and quantitative calculation of primary productivity of black rock series from the Dalong Formation, South China

The change of the primary productivity across the Permian-Triassic boundary (PTB) remains controversial. In this study, records from two deep-water sections in South China (Xiakou and Xinmin sections) show the primary productivity decreased gradually from the latest Permian to the earliest Triassic, and five evolutionary stages Increase-Decrease-Recovery-Recession-Stagnation) can be observed from Clarkina changxingensis-C. deflecta to Hindeodus parvus-Isarcicella isarcica zones. Primary productivity decreased abruptly from the base of C. meishanensis zone. Besides, for adjusting to the deterioration of the oceanic environment, the primary producers in the oceanic surface had changed to acritarch and cyanobacteria, which were more tolerant of stressful environment. Then the producers were under huge stagnation in the H. parvus-I. isarcica zone. The values of quantitative calculation of the primary productivity from the black rock series in the Dalong Formation were very high, corresponding to that of an upwelling area in modern ocean, which shows that the strata of the Dalong Formation in the study region are potential hydrocarbon source-rocks. This result may come from the fact that South China craton was located at the equatorial upwelling area during the Permian-Triassic transitions. But organic matter contents were different in various sections because they could be affected by redox conditions and diagenesis process after burial.

Depositional Controls On Mudstone Lithofacies In A Basinal Setting: Implications for the Delivery of Sedimentary Organic Matter

Deep-water mudstones from ancient epicontinental settings are significant repositories for organic matter, but the detailed temporal variations of, and controls on, the abundance and type of organic matter (OM) is little studied. Using micro-petrographic and geochemical data from late Mississippian mudstones of the Widmerpool Gulf, UK, the processes that delivered fine-grained sediment to this basin during a glacioeustatic sea-level cycle are interpreted from detailed lithofacies analysis. Seven primary lithofacies are identified from core, which show specific and systematic variations in total organic carbon (TOC) content and bulk carbon isotope composition of organic material (δ13Corg). During sea-level highstands, thin-bedded carbonate-bearing mudstones are the dominant facies deposited, contain up to 6.6% TOC (average 4.6 ± 1.3%), and have mean δ13Corg of −28.5 ± 0.9‰. During phases of lower sea level, thin-bedded silt-bearing clay-rich mudstones with up to 4.1% TOC (average 2.3 ± 0.8%; mean δ13Corg: −28.2 ± 1.0‰) were interbedded with more organic-lean graded silt-bearing mudstones and sand-bearing silt-rich mudstones (average TOC: 1.7 ± 0.6%) derived from turbidity currents. The latter (mean δ13Corg: −26.2 ± 0.7‰) are closely linked to significant proportions of terrestrial plant material, while some rare plant debris- and sand-bearing mudstones produced from debris flows have more than 7.0% TOC and δ13Corg ≥ −26.0‰. The δ13C values of wood fragments ranged from −27.1‰ to −24.0‰ and therefore the δ13Corg is interpreted as a function of the ratio of marine and terrestrial organic matter. More negative values in the carbonate-bearing and the clay-rich mudstones indicate marine planktonic algae whereas the least negative values reflect greater contribution of terrestrial plant material. The data suggest that the marine conditions prevailed and supported marine planktonic algae throughout different sea-level stages. Marine OM was delivered to the sea floor by continuous hemipelagic settling whereas terrestrial OM was delivered by sediment density flows. Variations in bioproductivity and dilution by siliciclastics influenced the burial rate of marine OM. Organic-rich mudstones preserved in these marine basins are potential hydrocarbon source rocks, especially as unconventional (shale gas) reservoirs. Detailed microtextural and compositional analysis coupled with rigorous geochemical parameters as used in this study are important for the understanding of the source-rock potential of basinal mudstones, and of fine-grained organic-rich sediments in general.

Hydrocarbon source rock potential and elemental composition of lower Silurian subsurface shales of the eastern Murzuq Basin, southern Libya

A shallow borehole was drilled in lower Silurian (Rhuddanian–lower Aeronian) Tanezzuft Formation siliciclastic sediments at the eastern margin of the Murzuq Basin. Shale samples were retrieved from the borehole to study their source rock potential and trace element geochemical composition. Thirty shale samples analysed from borehole CDEG-2a reveal three geochemically distinct intervals. Shales from the top (23–38 m) interval are weathered and have negligible organic content. Shales from the middle (38–42 m) interval have moderate to good organic richness (0.6–1.7 wt.% TOC) with Hydrogen Index (HI) values up to 443 mg S2/g TOC. Shales from the bottom (42–51 m) interval have poor to moderate organic richness (0.07–0.8 wt.% TOC) with HI values up to 277 mg S2/g TOC. All samples have limited source rock potential and are immature to early mature for hydrocarbon generation. It is unlikely that they have ever been buried deeper than ∼2 km. Low TOC values (<2 wt.%) together with low concentrations of uranium (<10 ppm) indicate the absence of organic-rich black shale (‘hot shale’) source rocks in the studied interval.Inorganic geochemical redox proxies (Ce-anomaly, authigenic U, Th/U, V/Cr, Ni/Co, and V/Sc) indicate that the lower Silurian Tanezzuft Formation shales from borehole CDEG-2a were deposited under oxic bottom waters, explaining their relatively low TOC values. Deposition took place in a shallow marine environment, in a proximal position with regard to an early Silurian palaeo-shoreline. This combined Rock-Eval pyrolysis and whole-rock geochemical study provides new insights into the Silurian source rock distribution and hydrocarbon prospectivity in central North Africa.

New evidences for the formation of and for petroleum exploration in the fold-thrust zones of the central Black Sea Basin of Turkey

The central Black Sea Basin of Turkey is filled by more than 9 km (6 mi) of Upper Triassic to Holocene sedimentary and volcanic rocks. The basin has a complex history, having evolved from a rift basin to an arc basin and finally having become a retroarc foreland basin. The Upper Triassic–Lower Jurassic Akgol and Lower Cretaceous Caglayan Formations have a poor to good hydrocarbon source rock potential, and the middle Eocene Kusuri Formation has a limited hydrocarbon source rock potential. The basin has oil and gas seeps. Many large structures associated with extensional and compressional tectonics, which could be traps for hydrocarbon accumulations, exist. Fifteen onshore and three offshore exploration wells were drilled in the central Black Sea Basin, but none of them had commercial quantities of hydrocarbons. The assessment of these drilling results suggests that many wells were drilled near the Ekinveren, Erikli, and Ballifaki thrusts, where structures are complex and oil and gas seeps are common. Many wells were not drilled deep enough to test the potential carbonate and clastic reservoirs of the Inalti and Caglayan Formations because these intervals are locally buried by as much as 5 km (3 mi) of sedimentary and volcanic rocks. No wells have tested prospective structures in the north and east where the prospective Inalti and Caglayan Formations are not as deeply buried. Untested hydrocarbons may exist in this area.

Stable isotopes of organics and inorganics, clay mineralogy and chemical environment of an Aptian lacustrine succession in northeastern Brazil

Abstract The studied Aptian lacustrine succession of the continental Jatobá Rift Basin varies mainly between pure carbonates (predominantly laminated limestones), marls and shales, with some intercalations of presumably deltaic sandstone complexes. In accordance with geochemical data, the occurrence of dolomite indicates intensive microbial activity in a stratified water column with slightly enhanced salinity. Petrographic data prove mild weathering conditions. Aggregates of authigenic smectite observed in sandstones, probably representing transformed volcanogenic glass particles, strongly indicate explosive volcanic activity. Occasionally occurring dolomite seems to have been formed due to intensive microbial activity under moderately increased salinity conditions. Potential hydrocarbon source rocks containing Type I organic matter (OM) were deposited during various phases of the Aptian. Enhanced biological productivity is indicated by bulk organic geochemical data (C org , hydrogen index, extraction yield) and δ 13 C values of carbonates within peletoidal and laminated limestone layers. Carbon-isotope ratios of carbonates argue for OM cycling and remineralization. High δ 18 O values of carbonates are attributed to periods of lower lake levels. A major contribution of aquatic organisms (green algae, microalgae, zooplankton) and minor input from macrophytes and land plants to OM accumulation is indicated by n -alkane distributions, steroid composition and δ 13 C values of individual biomarkers. Microbial communities included heterotrophic bacteria and cyanobacteria, as well as purple and green sulphur bacteria. The sediments were deposited in an alkaline palaeolake. Highly reducing (saline) bottom water conditions and a stratified water column existed during OM accumulation of the Crato Formation. This is indicated by low pristane/phytane, gammacerane index, and the presence of β-carotane and aryl isoprenoids. Differences in OM composition and stable isotope data reflect the evolution of the basin from a stratified saline lake to a freshwater environment with limited potential for OM preservation.