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).     

Geochemistry and origin of organic-rich sediment veins in fractured granitic basement,Helmsdale, Sutherlandshire,UK

Black sediment veins up to 2 cm width penetrate the Caledonian Helmsdale Granite in the vicinity of the Helmsdale Fault, onshore Moray Firth. The black colour and geochemistry of the veins reflect a high content of organic carbon. Both Devonian and Jurassic shales are conceivable available sources, but sterane compositions relate the organic matter to the Jurassic shales. A content of extractable organic matter higher than in the shales suggests that the carbon in the veins represents oil rather than mechanically mobilized shale. The oil was present during sediment vein emplacement. The veins were emplaced forcefully, which may reflect high fluid pressure associated with post-Jurassic movement on the Helmsdale Fault.     

Depositional environments of Late Cretaceous Gongila and Fika formations,Chad (Bornu) Basin,Northeast Nigeria

Organic geochemical and palynofacies studies of 172 ditch cuttings samples of possible source rock shales from the Late Cretaceous Gongila and Fika formations in the Chad Basin of NE Nigeria were carried out to determine their paleoenvironments of deposition. Although dominated by amorphous organic matter, C/S ratios and molecular parameters suggest the mostly organic lean shales (TOC contents typically below 1.5%) were deposited in a normal marine environment. Levels of oxygenation influenced by water depth in the depositional environment appear to control organic richness and quality of the dark grey shales.The organic rich (TOC > 2.0%) upper part of the Fika Formation was deposited under anoxic conditions during the Late Cretaceous and could represent an Oceanic Anoxic Event. Mature intervals where such conditions prevailed would have generated liquid hydrocarbon, although none were sampled here.A trend of increasing organic richness towards the central part of the larger Chad Basin observed in this and other studies supports the development of organic rich marine shales (average TOC contents of 2–3%) of equivalent age in the Termit Basin where water depth would have been deeper and oxygen conditions at levels that permitted preservation of marine organic matter.     

Palynofacies investigation of Callovian (Middle Jurassic) sediments from DSDP Site 534, Blake-Bahama Basin,Western Central Atlantic

During the extension of Deep Sea Drilling Project (DSDP) Leg 76 a new and previously unpenetrated lithological unit composed mainly of claystones was cored above basalt basement at Site 534 in the Blake-Bahama Basin. The Callovian part of the new unit contains interbedded ‘black shales’ which were hitherto unexpected in this part of the section. This Paper presents a brief palynological examination of lithofacies-kerogen relationships in these sediments and shows that their organic content is almost entirely a function of the re-deposition of terrestial and marine organic matter versus the ambient redox conditions of the depositional environment. Allochthonous organic matter inputs are highest in the interbedded turbidites and decline progressively toward the pelagic black shales in which marine organic matter is comparatively well preserved. The significance of various kerogen and palynomorph indices are discussed. The study emphasizes the absolute necessity for sedimentologically-aware sampling in all palynological and geochemical work on lithologically heterogeneous sequences.     

Pore structure of Cambrian shales from the Sichuan Basin in China and implications to gas storage

The microstructure of black siliceous shale from the lower Cambrian Niutitang Formation, Sichuan Basin in China was investigated by the combination of field emission scanning electron microscope (FE-SEM) and argon ion beam milling. The nanometer-to micrometer-scale pore systems of shales are an important control on gas storage and fluid migration. In this paper, the organic porosity in shale samples within oil and gas window has been investigated, and the formation mechanism and diagenetic evolution of nanopores have been researched.FE-SEM reveals five pore types that are classified as follows: organic nanopores, pores in clay minerals, nanopores of framework minerals, intragranular pores in microfossils, and microfractures. Numerous organic nanopores are observed in shales in the gas window, whereas microfractures can be seen within the organic matter of shales in the oil window. Microfractures in oil window shales could be attributed to pressure buildup in the organic matter when incompressible liquid hydrocarbon are generated, and the orientation of microfractures is probably parallel to the bedding and strength anisotropy of the formation. Pores in clay minerals are always associated with the framework of clay flakes, and develop around rigid mineral grains because the pressure shadows of mineral grains protect pores from collapse, and the increasing of silt content would lead to an increase in pressure shadows and improve porosity. Nanopores of rock framework are probably related to dissolution by acidic fluids from hydrocarbon generation, and the dissolution-related pores promote permeability of shales. Porosity in the low-TOC, low-thermal-maturity shales contrast greatly with those of high-TOC, high-thermal-maturity shales. While the high-TOC shales contain abundant organic microporosity, the inorganic pores can contribute a lot to the porosity of the low-TOC shales.     

Organic geochemistry of late Cenozoic sediments from the subtropical South Atlantic Ocean

Organic matter has been characterized in samples of Pleistocene, Pliocene, and Miocene sediments from seven Deep Sea Drilling Project sites in the subtropical South Atlantic Ocean. Organic carbon concentrations average 0.3% for most samples, and n-alkanoic acid, n-alkanol, and alkane biomarkers indicate extensive microbial reworking of organic matter in these organic-carbon-lean sediments. Samples from the easternmost parts of the South Atlantic contain an average of 4.1% organic carbon and reflect the high productivity associated with the Benguela Current. Lipid biomarkers show less microbial reworking in these sediments. Eolian transport of land-derived hydrocarbons is evident at most of these oceanic locations.     

Reconnaissance study of organic geochemistry and petrology of Paleozoic-Cenozoic potential hydrocarbon source rocks from the New Siberian Islands,Arctic Russia

A reconnaissance study of potential hydrocarbon source rocks of Paleozoic to Cenozoic age from the highly remote New Siberian Islands Archipelago (Russian Arctic) was carried out. 101 samples were collected from outcrops representing the principal Paleozoic-Cenozoic units across the entire archipelago. Organic petrological and geochemical analyses (vitrinite reflectance measurements, Rock-Eval pyrolysis, GC-MS) were undertaken in order to screen the maturity, quality and quantity of the organic matter in the outcrop samples. The lithology varies from continental sedimentary rocks with coal particles to shallow marine carbonates and deep marine black shales. Several organic-rich intervals were identified in the Upper Paleozoic to Lower Cenozoic succession. Lower Devonian shales were found to have the highest source rock potential of all Paleozoic units. Middle Carboniferous-Permian and Triassic units appear to have a good potential for natural gas formation. Late Mesozoic (Cretaceous) and Cenozoic low-rank coals, lignites, and coal-bearing sandstones also display a potential for gas generation. Kerogen type III (humic, gas-prone) dominates in most of the samples, and indicates deposition in lacustrine to coastal paleoenvironments. Most of the samples (except some of Cretaceous and Paleogene age) reached oil window maturities, whereas the Devonian to Carboniferous units shared a maturity mainly within the gas window.     

Sedimentary and residual gas geochemical characteristics of the Lower Cambrian organic-rich shales in Southeastern Chongqing,China

To study the sedimentary environment of the Lower Cambrian organic-rich shales and isotopic geochemical characteristics of the residual shale gas, 20 black shale samples from the Niutitang Formation were collected from the Youyang section, located in southeastern Chongqing, China. A combination of geochemical, mineralogical, and trace element studies has been performed on the shale samples from the Lower Cambrian Niutitang Formation, and the results were used to determine the paleoceanic sedimentary environment of this organic-rich shale. The relationships between total organic carbon (TOC) and total sulfur (TS) content, carbon isotope value (δ¹³C_org), trace element enrichment, and mineral composition suggest that the high-TOC Niutitang shale was deposited in an anoxic environment and that the organic matter was well preserved after burial. Stable carbon isotopes and biomarkers both indicate that the organic matter in the Niutitang black shales was mainly derived from both lower aquatic organisms and algaes and belong to type I kerogen. The oil-prone Niutitang black shales have limited residual hydrocarbons, with low values of S₂, I_H, and bitumen A. The carbon isotopic distribution of the residual gas indicate that the shale gas stored in the Niutitang black shale was mostly generated from the cracking of residual bitumen and wet gas during a stage of significantly high maturity. One of the more significant observations in this work involves the carbon isotope compositions of the residual gas (C₁, C₂, and C₃) released by rock crushing. A conventional δ¹³C₁–δ¹³C₂ trend was observed, and most δ¹³C₂ values of the residual gases are heavier than those of the organic matter (OM) in the corresponding samples, indicating the splitting of ethane bonds and the release of smaller molecules, leading to ¹³C enrichment in the residual ethane.     

Origins and maturity of organic matter in mid-Cretaceous black shales from ODP Site 1138 on the Kerguelen Plateau

We have conducted elemental, isotopic, and Rock-Eval analyses of Cenomanian–Santonian sediment samples from ODP Site 1138 in the southern Indian Ocean to assess the origin and thermal maturity of organic matter in mid-Cretaceous black shales found at this high-latitude location. Total organic carbon (TOC) concentrations range between 1 and 20 wt% in black to medium-gray sediments deposited around the Cenomanian–Turonian boundary. Results of Rock-Eval pyrolysis indicate that the organic matter is algal Type II material that has experienced modest alteration. Important contributions of nitrogen-fixing bacteria to the amplified production of organic matter implied by the high TOC concentrations is recorded in δ¹⁵N values between −5 and 1‰, and the existence of a near-surface intensified oxygen minimum zone that favored organic carbon preservation is implied by TOC/TN ratios between 20 and 40. In contrast to the marine nature of the organic matter in the Cenomanian–Turonian boundary section, deeper sediments at Site 1138 contain evidence of contributions land-derived organic matter that implies the former presence of forests on the Kerguelen Plateau until the earliest Cenomanian.     

Black shales in Ukraine – A review

As a result of a long-lasting and complex geological history, organic-matter-rich fine-grained rocks (black shales) with widely varying ages can be found on Ukrainian territory. Several of them are proven hydrocarbon source rocks and may hold a significant shale gas potential.Thick Silurian black shales accumulated along the western margin of the East European Craton in a foreland-type basin. By analogy with coeval organic-matter-rich rocks in Poland, high TOC contents and gas window maturity can be expected. However, to date information on organic richness is largely missing and maturity patterns remain to be refined.Visean black shales with TOC contents as high as 8% and a Type III-II kerogen accumulated along the axis of the Dniepr-Donets rift basin (DDB). They are the likely source for conventional oil and gas. Oil-prone Serpukhovian black shales accumulated in the shallow northwestern part of the DDB. Similar black shales probably may be present in the Lviv-Volyn Basin (western Ukraine).Middle Jurassic black shales up to 500 m thick occur beneath the Carpathian Foredeep. They are the likely source for some heavy oil deposits. TOC contents up to 12% (Type II) have been recorded, but additional investigations are needed to study the vertical and lateral variability of organic matter richness and maturity.Lower Cretaceous black shales with a Type III(-II) kerogen (TOC > 2%) are widespread at the base of the Carpathian flysch nappes, but Oligocene black shales (Menilite Fm.) rich in organic matter (4–8% TOC) and containing a Type II kerogen are the main source rock for oil in the Carpathians. Their thermal maturity increases from the external to the internal nappes.Oligocene black shales are also present in Crimea (Maykop Fm.). These rocks typically contain high TOC contents, but data from Ukraine are missing.     

Petrographic and geochemical characteristics of the lacustrine black shales from the Upper Triassic Yanchang Formation of the Ordos Basin,China: Implications for the organic matter accumulation

The lacustrine black shales in the Chang7 Member from the Upper Triassic Yanchang Formation of the Ordos Basin in Central China are considered one of the most important hydrocarbon source rocks. However, the mechanism of organic accumulation in the black shales remains controversial. To resolve the controversy, with the former paleontological data of Yanchang Formation and sedimentation rate data of the Chang7 black shales, we investigated the typical intervals of the Chang7 black shales (TICBS) which were obtained by drilling in Yaowan at the southern margin of the Ordos Basin and performed various sedimentary, isotopic and geochemical analysis, including the sedimentary petrography, pyrite morphology, total organic carbon (TOC) and total sulfur (TS), the ratio of pyritic Fe to total Fe (DOP_T), major and trace elements, together with pyritic sulfur isotopes (δ³⁴S_py). The high sulfur content, enrichment of redox-sensitive trace metals, and the lower sedimentation rate of the TICBS in addition to the presence of marine spined acritarchs and coelacanth fossils indicate that the TICBS were deposited in a lacustrine environment possibly influenced by seawater. The petrographic observations show a thick layer of black shale with interlayers of thin layered siltstone (silty mudstone) and laminated tuff, which were related to the turbidity currents and volcanism, respectively. The U/Th, C-S, and Mo-U covariations, pyrite morphology, DOP_T, combined with the δ³⁴S_py, suggest that the deposition occurred beneath the anoxic-sulfidic bottom waters, which was intermittently influenced by the oxygen-containing turbidity. The Ni/Al and Cu/Al possibly show extremely high to high primary productivity in the water column, which might be connected with the substantial nutrients input from seawater or frequently erupted volcanic ash entering the lake. In addition, the coincidence of an increased abundance of TOC with increased P/Al, Ni/Al, Cu/Al and U/Th, as well as relatively consistent Ti/Al suggest that the accumulation of the organic matter might be irrelevant to the clastic influx, and was mainly controlled by the high primary productivity and anoxic-sulfidic conditions. Further, the covariations of TOC vs. P/Al and TOC vs. Ba/Al indicate that the high primary productivity led to the elevated accumulation and burial of organic matter, while the anoxic to sulfidic conditions were likely resulted from an intense degradation of the organic matter during the early diagenesis. In summary, the organic matter accumulation is ultimately attributed to the high primary productivity possibly resulted from seawater or volcanic ash entering the lake.     

Multiple controls on the paleoenvironment of the Early Cambrian marine black shales in the Sichuan Basin,SW China: Geochemical and organic carbon isotopic evidence

In order to understand the paleoenvironment of the Early Cambrian black shale deposition in the western part of the Yangtze Block, geochemical and organic carbon isotopic studies have been performed on two wells that have drilled through the Qiongzhusi Formation in the central and southeastern parts of Sichuan Basin. It shows that the lowest part of the Qiongzhusi Formation has high TOC abundance, while the middle and upper parts display relative low TOC content. Redox-sensitive element (Mo) and trace elemental redox indices (e.g., Ni/Co, V/Cr, U/Th and V/(V + Ni)) suggest that the high-TOC layers were deposited under anoxic conditions, whereas the low-TOC layers under relatively dysoxic/oxic conditions. The relationship of the enrichment factors of Mo and U further shows a transition from suboxic low-TOC layers to euxinic high-TOC layers. On the basis of the Mo-TOC relationship, the Qiongzhusi Formation black shales were deposited in a basin under moderately restricted conditions. Organic carbon isotopes display temporal variations in the Qiongzhusi Formation, with a positive excursion of δ¹³C_org values in the lower part and a continuous positive shift in the middle and upper parts. All these geochemical and isotopic criteria indicate a paleoenvironmental change from bottom anoxic to middle and upper dysoxic/oxic conditions for the Qiongzhusi Formation black shales. The correlation of organic carbon isotopic data for the Lower Cambrian black shales in different regions of the Yangtze Block shows consistent positive excursion of δ¹³C_org values in the lower part for each section. This excursion can be ascribed to the widespread Early Cambrian transgression in the Yangtze Block, under which black shales were deposited.     

Organic geochemistry and petroleum potential of Early Cretaceous Garau Formation in central part of Lurestan zone,northwest of Zagros,Iran

Deposition of organic rich black shales and dark gray limestones in the Berriasian-Turonian interval has been documented in many parts of the world. The Early Cretaceous Garau Formation is well exposed in Lurestan zone in Iran and is composed of organic-rich shales and argillaceous limestones. The present study focuses on organic matter characterization and source rock potential of the Garau Formations in central part of Lurestan zone. A total of 81 core samples from 12 exploratory wells were subjected to detailed geochemical analyses. These samples have been investigated to determine the type and origin of the organic matter as well as their petroleum-generation potential by using Rock-Eval/TOC pyrolysis, GC and GCMS techniques. The results showed that TOC content ranges from 0.5 to 4.95 percent, PI and Tmax values are in the range of 0.2 and 0.6, and 437 and 502 °C. Most organic matter is marine in origin with sub ordinary amounts of terrestrial input suggesting kerogen types II-III and III. Measured vitrinite reflectance (Rrandom%) values varying between 0.78 and 1.21% indicating that the Garau sediments are thermally mature and represent peak to late stage of hydrocarbon generation window. Hydrocarbon potentiality of this formation is assessed fair to very good capable of generating chiefly gas and some oil. Biomarker characteristics are used to provide information about source and maturity of organic matter input and depositional environment. The relevant data include normal alkane and acyclic isoprenoids, distribution of the terpane and sterane aliphatic biomarkers. The Garau Formation is characterized by low Pr/Ph ratio (<1.0), high concentrations of C27 regular steranes and the presence of tricyclic terpanes. These data indicated a carbonate/shale source rock containing a mixture of aquatic (algal and bacterial) organic matter with a minor terrigenous organic matter contribution that was deposited in a marine environment under reducing conditions. The results obtained from biomarker characteristics also suggest that the Garau Formation is thermally mature which is in agreement with the results of Rock-Eval pyrolysis.     

Geochemistry and organic petrography of Cretaceous sediments of the Calabar Flank,southeastern, Nigeria

Detailed bulk geochemistry and organo-petrography of outcrop Cretaceous sediments (with no significant effects of weathering) from the Calabar Flank, southeast Nigeria were performed to understand the organic carbon source, accumulation and degradation, and paleo-climatic, paleoceanographic and paleoenvironmental conditions in West Africa during Early Cretaceous (Aptian) to Maastrichtian times. This study was based on microscopic, elemental analyses (organic carbon, nitrogen, iron and sulphur), Rock-eval pyrolysis and carbon-isotope analyses. In general, the Calabar Flank shales are characterised by highly variable total organic carbon (TOC) contents, which range between 0.1% in Aptian–Albian Mfamosing Limestone and 9.9% in the Awi Formation sediments. The organic matter (OM) is a mixture of immature to early-mature marine and terrigenous OM of types III and IV. This is indicated by low hydrogen indices (HI value (10–190 mg HC/g TOC), T_max (417–460 °C), vitrinite reflectance %R_o (0.39–0.62 %R_o), low to high C/N ratios (3.4–1158.0) and high amounts of terrigenous macerals (vitrinite + inertinite). Based on carbon isotope, C/N ratios and sulphate reduction index (SRI), OM degradation (up to 70%, SRI > 2.5) is most pronounced for shales deposited in a marine environment. The geochemical and petrographic data indicate that local factors such as low bioproductivity, down slope transport and redeposition of sediments from a fluvial–deltaic basin to nearshore facies, shallower, oxic and mildly oxygen-deficient environments, humid–arid paleogeographic conditions, specifically controlled the amount and quality of the OM during Aptian–Mastrichtian stages where marine sediments have been assumed to be deposited during the global anoxic events. Therefore, the order of the main factors controlling OM content in sediments are: input of terrigenous material transported from the land > low OM productivity by marine photoautotrophs > low preservation.     

Organic matter–apatite–pyrite relationships in the Botneheia Formation (Middle Triassic) of eastern Svalbard: Relevance to the formation of petroleum source rocks in the NW Barents Sea shelf

The Middle Triassic Botneheia Formation of eastern Svalbard (Edgeøya and Barentsøya) comprises an organic carbon-rich, fine-grained clastic succession (∼100 m thick) that makes the best petroleum source rock horizon in the NW Barents Sea shelf. The succession records a transgressive–regressive interplay between the prodelta depositional system sourced in the southern Barents Sea shelf (black shale facies of the lower and middle parts of the Muen Member) and the open shelf phosphogenic system related to upwelling and nutrient supply from the Panthalassic Ocean (phosphogenic black shale facies of the upper part of the Muen Member and the Blanknuten Member). The relationships between organic matter, authigenic apatite, and pyrite in these facies allow to characterize the relative roles of redox conditions and oceanic productivity in the organic carbon preservation. The accumulation of terrestrial and autochthonous marine organic matter in the black shale facies occurred under dominating oxic conditions and increasing-upward productivity related to early transgressive phase and retrogradation of the prodelta system. The phosphogenic black shale facies deposited in an oxygen-minimum zone (OMZ) of the open shelf environment during the late transgressive to regressive phases under conditions of high biological productivity, suppressed sedimentation rates, and changing bottom redox. The phosphatic black shales occurring in the lower and upper parts of the phosphogenic succession reveal depositional conditions indicative of the shallower part of OMZ, including high input of autochthonous organic matter into sediment, oxic-to-dysoxic (episodically suboxic and/or anoxic) conditions, intense phosphogenesis, and recurrent reworking of the seabed. The massive phosphatic mudstone occurring in the middle of the phosphogenic succession reflects the development of euxinia in the deeper part of OMZ during high-stand of the sea. High input of autochthonous organic matter in this environment was coupled with mineral starvation and intermittent phosphogenesis. In mature sections in eastern Svalbard, the petroleum potential of the Botneheia Formation rises from moderate to good in the black shale facies, and from good to very good in the phosphogenic black shale facies, attaining maximum in the massive phosphatic mudstone.     

The origin,type and preservation of organic matter of the Barremian–Aptian organic-rich shales in the Muglad Basin,Southern Sudan,and their relation to paleoenvironmental and paleoclimate conditions

Barremian–Aptian organic-rich shales from Abu Gabra Formation in the Muglad Basin were analysed using geochemical and petrographic analyses. These analyses were used to define the origin, type of organic matters and the influencing factors of diagenesis, including organic matter input and preservation, and their relation to paleoenvironmental and paleoclimate conditions. The bulk geochemical characteristics indicated that the organic-rich shales were deposited in a lacustrine environment with seawater influence under suboxic conditions. Their pyrolysis hydrogen index (HI) data provide evidence for a major contribution by Type I/II kerogen with HI values of >400 mg HC/g TOC and a minor Type II/III contribution with HI values <400 mg HC/g TOC. This is confirmed by kerogen microscopy, whereby the kerogen is characterized by large amounts of structured algae (Botryococcus) and structureless (amorphous) with a minor terrigenous organic matter input. An enhanced biological productivity within the photic zone of the water columns is also detected. The increased biological productivity in the organic-rich shales may be related to enhanced semi-arid/humid to humid-warm climate conditions. Therefore, a high bio-productivity in combination with good organic matter preservation favoured by enhanced algae sizes are suggested as the OM enrichment mechanisms within the studied basin.     

Pore characterization of organic-rich Lower Cambrian shales in Qiannan Depression of Guizhou Province,Southwestern China

Nine organic-rich shale samples of Lower Cambrian black shales were collected from a recently drilled well in the Qiannan Depression, Guizhou Province where they are widely distributed with shallower burial depth than in Sichuan Basin, and their geochemistry and pore characterization were investigated. The results show that the Lower Cambrian shales in Qiannan Depression are organic rich with TOC content ranging from 2.81% to 12.9%, thermally overmature with equivalent vitrinite reflectance values in the range of 2.92–3.25%, and clay contents are high and range from 32.4% to 53.2%. The samples have a total helium porosity ranging from 2.46% to 4.13% and total surface area in the range of 9.08–37.19 m²/g. The estimated porosity in organic matters (defined as the ratio of organic pores to the volume of total organic matters) based on the plot of TOC vs helium porosity is about 10% for the Lower Cambrian shales in Qiannan Depression and is far lower than that of the Lower Silurian shales (36%) in and around Sichan Basin. This indicates that either the organic pores in the Lower Cambrian shale samples have been more severely compacted than or they did not develop organic pores as abundantly as the Lower Silurian shales. Our studies also reveal that the micropore volumes determined by Dubinin–Radushkevich (DR) equation is usually overestimated and this overestimation is closely related to the non-micropore surface area of shales (i.e. the surface area of meso- and macro-pores). However, the modified BET equation can remove this overestimation and be conveniently used to evaluate the micropore volumes/surface area and the non-micropore surface areas of micropore-rich shales.     

Source rock characteristics and biostratigraphy of the Lower Silurian (Telychian) organic-rich shales at Akyaka, central Taurus region, Turkey

The Akyaka section in the central Taurus region in the southern part of Turkey includes the organic matter and graptolite-rich black shales which were deposited under dysoxic to anoxic marine conditions in the Early Silurian. A biostratigraphical analysis, based on graptolite assemblages, indicates that the sediments studied may well be referable to the querichi Biozone and early Telychian, Llandovery. A total of 15 samples have been subjected to Leco and Rock-Eval pyrolysis and graptolite reflectance measurements for determination of their source rock characteristics and thermal maturity. The total organic carbon content of the graptolite-bearing shales varies from 1.75 to 3.52 wt% with an average value of 2.86 wt%. The present Rock-Eval pyrolytic yields and calculated values of hydrogen and oxygen indexes imply that the recent organic matter type is inert kerogen. The measured maximum graptolite reflectance (G_Rmax %) values are between 5.04% and 6.75% corresponding to thermally over maturity. This high maturity suggests a deep burial of the Lower Silurian sediments resulting from overburden rocks of Upper Paleozoic to Mesozoic Upper Cretaceous and Middle-Upper Eocene thrusts occurred in the region.     

Origin of organic matter and paleoenvironment conditions of the Late Jurassic organic-rich shales from shabwah sub-basin (western Yemen): Constraints from petrology and biological markers

Late Jurassic organic-rich shales from Shabwah sub-basin of western Yemen were analysed based on a combined investigations of organic geochemistry and petrology to define the origin, type of organic matter and the paleoenvironment conditions during deposition. The organic-rich shales have high total sulphur content values in the range of 1.49–4.92 wt. %, and excellent source rock potential is expected based on the high values of TOC (>7%), high extractable organic matter content and hydrocarbon yield exceeding 7000 ppm. The high total sulphur content and its relation with high organic carbon content indicate that the Late Jurassic organic-rich shales of the Shabwah sub-basin were deposited in a marine environment under suboxic-anoxic conditions. This has been evidenced from kerogen microscopy and their biomarker distributions. The kerogen microscopy investigation indicated that the Late Jurassic organic-rich shales contain an abundant liptinitic organic matter (i.e., alginite, structureless (amorphous organic matters)). The presence of alginite with morphology similar to the lamalginite alga and amorphous organic matter in these shale samples, further suggests a marine origin. The biomarker distributions also provide evidence for a major contribution by aquatic algae and microorganisms with a minor terrigenous organic matter input. The biomarkers are characterized by unimodal distribution of n-alkanes, low acyclic isoprenoids compared to normal alkanes, relatively high tricyclic terpanes compared to tetracyclic terpanes, and high proportion of C₂₇ and C₂₉ regular steranes compared to C₂₈ regular sterane. Moreover, the suboxic to anoxic bottom water conditions as evidenced in these Late Jurassic shales is also supported based on relatively low pristane/phytane (Pr/Ph) ratios in the range of 0.80–1.14. Therefore, it is envisaged here that the high content of organic matter (TOC > 7 wt.%) in the analysed Late Jurassic shales is attributed to good organic matter (OM) preservation under suboxic to anoxic bottom water conditions during deposition.     

Geochemistry and organic petrology study of Kimmeridgian organic-rich shales in the Marib-Shabowah Basin,Yemen: Origin and implication for depositional environments and oil-generation potential

Kimmeridgian organic-rich shales of the Madbi Formation from the Marib-Shabowah Basin in western Yemen were analysed to evaluate the type of organic matter, origin and depositional environments as well as their oil-generation potential. Results of the current study establishes the organic geochemical characteristics of the Kimmeridgian organic-rich shales and identifies the kerogen type based on their organic petrographic characteristics as observed under reflected white light and blue light excitation. Kerogen microscopy shows that the Kimmeridgian organic-rich shales contain a large amount of organic matter, consisting predominantly of yellow fluorescing alginite and amorphous organic matter with marine-microfossils (e.g., dinoflagellate cysts and micro-foraminiferal linings). Terrigenous organic matters (e.g., vitrinite, spores and pollen) are also present in low quantities. The high contributions of marine organic matter with minor terrigenous organic matter are also confirmed by carbon isotopic values. The organic richness of the Kimmeridgian shales is mainly due to good preservation under suboxic to relatively anoxic conditions, as indicated by the percent of numerous pyritized fragments associated with the organic matter. The biomarker parameters obtained from mass spectrometer data on m/z 191 and m/z 217 also indicate that these organic-rich shales contain mixed organic matter that were deposited in a marine environment and preserved under suboxic to relatively anoxic conditions.The Kimmeridgian organic-rich shales thus have high oil and low gas-generation potential due to oil window maturities and the nature of the organic matter, with high content of hydrogen-rich Type II and mixed Type II-III kerogens with minor contributions of Type III kerogen.