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.     

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.     

Thermal maturity,source rock potential and kinetics of hydrocarbon generation in Permian shales from the Damodar Valley basin,Eastern India

This study investigates the source rock characteristics of Permian shales from the Jharia sub-basin of Damodar Valley in Eastern India. Borehole shales from the Raniganj, Barren Measure and Barakar Formations were subjected to bulk and quantitative pyrolysis, carbon isotope measurements, mineral identification and organic petrography. The results obtained were used to predict the abundance, source and maturity of kerogen, along with kinetic parameters for its thermal breakdown into simpler hydrocarbons.The shales are characterized by a high TOC (>3.4%), mature to post-mature, heterogeneous Type II–III kerogen. Raniganj and Barren Measure shales are in mature, late oil generation stage (Rr%_Raniganj = 0.99–1.22; Rr%_{Barren Measure} = 1.1–1.41). Vitrinite is the dominant maceral in these shales. Barakar shows a post-mature kerogen in gas generation stage (Rr%_Barakar = 1.11–2.0) and consist mainly of inertinite and vitrinite. The δ¹³C_org value of kerogen concentrate from Barren Measure shale indicates a lacustrine/marine origin (−24.6–−30.84‰ vs. VPDB) and that of Raniganj and Barakar (−22.72–−25.03‰ vs. VPDB) show the organic provenance to be continental. The δ¹³C ratio of thermo-labile hydrocarbons (C₁–C₃) in Barren Measure suggests a thermogenic source.Discrete bulk kinetic parameters indicate that Raniganj has lower activation energies (ΔE = 42–62 kcal/mol) compared to Barren Measure and Barakar (ΔE = 44–68 kcal/mol). Temperature for onset (10%), middle (50%) and end (90%) of kerogen transformation is least for Raniganj, followed by Barren Measure and Barakar. Mineral content is dominated by quartz (42–63%), siderite (9–15%) and clay (14–29%). Permian shales, in particular the Barren Measure, as inferred from the results of our study, demonstrate excellent properties of a potential shale gas system.     

The Mesozoic–Cenozoic organic facies in the Lower Tagus sub-basin (Lusitanian Basin,Portugal): Palynofacies and organic geochemistry approaches

Studies of the Mesozoic and Cenozoic sequence crossed by the Barreiro-4 borehole provide an improved understanding of the organic matter deposited in the Lower Tagus sub-basin (Lusitanian Basin, Portugal) and the implications for the potential source rock and depositional environment. This study focused on 43 samples (Middle Jurassic to Neogene) that were subjected to palynofacies and organic geochemistry analyses (Total Organic Carbon, Rock-Eval pyrolysis and molecular biomarker analysis). The palynofacies data indicate that the sequence contains mainly phytoclasts (non-opaque phytoclasts). However, the Middle Jurassic samples are dominated by Amorphous Organic Matter (AOM). Continental and/or marine palynomorphs are present in all the samples. The Cretaceous samples are characterized by small amounts of kerogen that have high contents of solid bitumen. The Total Organic Carbon (TOC) content is generally less than 1 wt.%. The Rock-Eval S1 and S2 parameters vary from 0.01 to 3.50 mgHC/g rock and 0.15 to 34.03 mgHC/g rock, respectively, with the highest values corresponding to the Cretaceous samples. The hydrogen index (HI) and oxygen index (OI) values range from 35 to 552 mgHC/g TOC and 4 to 180 mgHC/g TOC, respectively. The T_max values range from 416 to 437 °C. The biomarker analysis showed that n-alkanes with 15–30 carbon atoms are present and usually have a unimodal distribution with a predominance of low to medium molecular weight compounds. The CPI values range between 0.63 and 3.65, and the pristane/phytane ratios vary between 0.48 and 1.64, indicating alternation of oxic–anoxic conditions along the sequence. The distribution of terpanes shows small amounts of tricyclic and tetracyclic terpanes in most of the samples (except for some Cretaceous samples) and a predominance of pentacyclic terpanes. The amount of 17α (H),22,29,30-trisnorhopane (Tm) usually exceeds the amount of 18α (H),22,29,30-trinorneohopane (Ts). The 20S/(20S + 20R) and αββ/(ααα + αββ) ratios of the C29 steranes generally have values below the range of equilibrium, indicating an immature stage of the OM.     

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.     

Petroleum source rock characterisation and hydrocarbon generation modeling of the Cretaceous sediments in the Jiza sub-basin,eastern Yemen

Cretaceous sedimentary rocks of the Mukalla, Harshiyat and Qishn formations from three wells in the Jiza sub-basin were studied to describe source rock characteristics, providing information on organic matter type, paleoenvironment of deposition and hydrocarbon generation potential. This study is based on organic geochemical and petrographic analyses performed on cuttings samples. The results were then incorporated into basin models in order to understand the burial and thermal histories and timing of hydrocarbon generation and expulsion.The bulk geochemical results show that the Cretaceous rocks are highly variable with respect to their genetic petroleum generation potential. The total organic carbon (TOC) contents and petroleum potential yield (S₁ + S₂) of the Cretaceous source rocks range from 0.43 to 6.11% and 0.58–31.14 mg HC/g rock, respectively indicating non-source to very good source rock potential. Hydrogen index values for the Early to Late Cretaceous Harshiyat and Qishn formations vary between 77 and 695 mg HC/g TOC, consistent with Type I/II, II-III and III kerogens, indicating oil and gas generation potential. In contrast, the Late Cretaceous Mukalla Formation is dominated by Type III kerogen (HI < 200 mg HC/g TOC), and is thus considered to be gas-prone. The analysed Cretaceous source rock samples have vitrinite reflectance values in the range of 0.37–0.95 Ro% (immature to peak-maturity for oil generation).A variety of biomarkers including n-alkanes, regular isoprenoids, terpanes and steranes suggest that the Cretaceous source rocks were deposited in marine to deltaic environments. The biomarkers also indicate that the Cretaceous source rocks contain a mixture of aquatic organic matter (planktonic/bacterial) and terrigenous organic matter, with increasing terrigenous influence in the Late Cretaceous (Mukalla Formation).The burial and thermal history models indicate that the Mukalla and Harshiyat formations are immature to early mature. The models also indicate that the onset of oil-generation in the Qishn source rock began during the Late Cretaceous at 83 Ma and peak-oil generation was reached during the Late Cretaceous to Miocene (65–21 Ma). The modeled hydrocarbon expulsion evolution suggests that the timing of oil expulsion from the Qishn source rock began during the Miocene (>21 Ma) and persisted to present-day. Therefore, the Qishn Formation can act as an effective oil-source but only limited quantities of oil can be expected to have been generated and expelled in the Jiza sub-basin.     

Geochemical characteristics and hydrocarbon generation modeling of the Jurassic source rocks in the Shoushan Basin, north Western Desert, Egypt

The Shoushan Basin is an important hydrocarbon province in the Western Desert, Egypt, but the origin of the hydrocarbons is not fully understood. In this study, organic matter content, type and maturity of the Jurassic source rocks exposed in the Shoushan Basin have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. The Jurassic source rock succession comprises the Ras Qattara and Khatatba Formations, which are composed mainly of shales and sandstones with coal seams. The TOC contents are high and reached a maximum up to 50%. The TOC values of the Ras Qattara Formation range from 2 to 54 wt.%, while Khatatba Formation has TOC values in the range 1-47 wt.%. The Ras Qattara and Khatatba Formations have HI values ranging from 90 to 261 mgHC/gTOC, suggesting Types II-III and III kerogen. Vitrinite reflectance values range between 0.79 and 1.12 VRr %. Rock−Eval T_max values in the range 438-458 °C indicate a thermal maturity level sufficient for hydrocarbon generation. Thermal and burial history models indicate that the Jurassic source rocks entered the mature to late mature stage for hydrocarbon generation in the Late Cretaceous to Tertiary. Hydrocarbon generation began in the Late Cretaceous and maximum rates of oil with significant gas have been generated during the early Tertiary (Paleogene). The peak gas generation occurred during the late Tertiary (Neogene).     

The Cenomanian/Turonian oceanic anoxic event in the Razzak Field, north Western Desert, Egypt: Source rock potential and paleoenvironmental association

The Western Desert of Egypt is one of the world’s most prolific Jurassic and Cretaceous hydrocarbon provinces. It is one of many basins that experienced organic-rich sedimentation during the late Cenomanian/early Turonian referred to as oceanic anoxic event 2 (OAE2). The Razzak #7 oil well in the Razzak Field in the northern part of the Western Desert encountered the Upper Cretaceous Abu Roash Formation. This study analyzed 23 samples from the upper “G”, “F”, and lower “E” members of the Abu Roash Formation for palynomorphs, particulate organic matter, total organic carbon (TOC) and δ¹³C_org in order to identify the OAE2, determine hydrocarbon source rock potential, and interpret the depositional environment. The studied samples are generally poor in palynomorphs, but show a marked biofacies change between the lower “E” member and the rest of the studied samples. Palynofacies analysis (kerogen quality and quantity) indicates the presence of oil- and gas-prone materials (kerogen types I and II/III, respectively), and implies reducing marine paleoenvironmental conditions. Detailed carbon stable isotopic and organic carbon analyses indicate that fluctuations in the δ¹³C_org profile across the Abu Roash upper “G”, “F”, and lower “E” members correspond well with changes in TOC values. A positive δ¹³C_org excursion (∼2.01‰) believed to mark the short-term global OAE2 was identified within the organic-rich shaly limestone in the basal part of the Abu Roash “F” member. This excursion also coincides with the peak TOC measurement (24.61 wt.%) in the samples.     

Biomarkers of Middle to Late Jurassic marine sediments from a canonical section: New records from the Yanshiping area,northern Tibet

The Yanshiping section, which includes the Quemo Co, Buqu, Xiali, Suowa and Xueshan Formations (Yanshiping Group) exposes organic-rich Middle to Late Jurassic deposits in the Qiangtang Basin of northern Tibet. The biostratigraphic data, from bivalves, brachiopods as well as dinoflagellate cysts, define a Bajocian to Tithonian age. This study focuses on the biomarkers present in these mudstones and limestones to determine the sources, thermal maturity and depositional environment of the organic matter. Most samples show a clear dominance of short-chain (C₁₅–C₂₀) n-alkanes with a maximum at C₁₉ or C₁₉ with a secondary maximum at C₂₃ except for the sample BP01(22)S1 where the predominant range is C₂₂ to C₂₆ with a maximum at C₂₄, significant CPI and odd-to-even predominance. The hopanoids and steroids suggest that the sources of organic matter were dominated by phytoplankton, especially algae, as the primary source. Furthermore, the Pr/Ph, Pr/nC₁₇ and Ph/nC₁₈, with relatively low values plus high abundance of 17α(H)-hopanes, support deposition in dysoxic to reducing, relatively shallow-water depositional settings, and the presence of gammacerane indicates normal marine salinity and/or water-column stratification. All samples are fairly mature with respect to petroleum generation, a conclusion supported by maturity parameters such as C₃₁ 22S/(22S + 22R) hopanes and C₂₉ ααα20S/(20S + 20R) steranes.     

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.     

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.     

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.     

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).     

Middle and Upper Jurassic hydrocarbon potential of the Zagross Fold Belt,North Iraq

Structured organic matters of the Palynomorphs of mainly dinoflagellate cysts are used in this study for dating the limestone, black shale, and marl of the Middle Jurassic (Bajocian–Bathonian) Sargelu Formation, Upper Jurassic (Upper Callovian – Lower Oxfordian) Naokelekan Formation, Upper Jurassic (Kimeridgian and Oxfordian) Gotnia and Barsarine Formations, and Upper Jurassic – Lower Cretaceous (Tithonian-Beriassian) Chia Gara source rock Formations while spore species of Cyathidites australis and Glechenidites senonicus are used for maturation assessments of this succession. Materials' used for this palynological study are 320 core and cutting samples of twelve oil wells and three outcrops in North Iraq.Terpane and sterane biomarker distributions, as well as stable isotope values, were determined for oils potential source rock extracts of Jurassic-Lower Cretaceous strata to determine valid oil-to-source rock correlations in North Iraq. Two subfamily carbonate oil types-one of Middle Jurassic age (Sargelu) carbonate rock and the other of mixed Upper Jurassic/Cretaceous age (Chia Gara) with Sargelu sources as well as a different oil family related to Triassic marls, were identified based on multivariate statistical analysis (HCA & PCA). Middle Jurassic subfamily A oils from Demir Dagh oil field correlate well with rich, marginally mature, Sargelu source rocks in well Mk-2 near the city of Baiji. In contrast, subfamily B oils have a greater proportion of C₂₈/C₂₉ steranes, indicating they were generated from Upper Jurassic/Lower Cretaceous carbonates such as those at Gillabat oil field north of Mansuriyah Lake. Oils from Gillabat field thus indicate a lower degree of correlation with the Sargelu source rocks than do oils from Demir Dagh field.Palynofacies assessments are performed for this studied succession by ternary kerogen plots of the phytoclast, amorphous organic matters, and palynomorphs. From the diagram of these plots and maturation analysis, it could be assessed that the formations of Chia Gara and Sargelu are both deposited in distal suboxic to anoxic basin and can be correlated with kerogens classified microscopically as Type A and Type B and chemically as Type II. The organic matter, comprised principally of brazinophyte algae, dinoflagellate cysts, spores, pollen, foraminifera test linings, and phytoclasts in all these formations and hence affected with upwelling current. These deposit contain up to 18 wt% total organic matters that are capable to generate hydrocarbons within mature stage of thermal alteration index (TAI) range in Stalplin's scale (Staplin, 1969) of 2.7–3.0 for the Chia Gara Formation and 2.9–3.1 for the Sargelu Formation. Case study examples of these oil prone strata are; one 7-m (23-ft) thick section of the Sargelu Formation averages 44.2 mg HC/g S2 and 439 °C Tmax (Rock-Eval pyrolysis analyses) and 16 wt% TOC especially in well Mk-2 whereas, one 8-m (26-ft) thick section of the Chia Gara and 1-m (3-ft) section of Naokelekan Formations average 44.5 mg HC/g S2 and 440 °C Tmax and 14 wt% TOC especially in well Aj-8. One-dimension, petroleum system models of key wells using IES PetroMod Software can confirm their oil generation capability.These hydrocarbon type accumulation sites are illustrated in structural cross sections and maps in North Iraq.     

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.     

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.     

Enrichment and distribution of shale oil in the Cretaceous Qingshankou Formation,Songliao Basin,Northeast China

The Songliao Basin is a large-scale petroliferous basin in China. With a gradual decline in conventional oil production, the exploration and development of replacement resources in the basin is becoming increasingly important. Previous studies have shown that the Cretaceous Qingshankou Formation (K₂qn) has favorable geological conditions for the formation of shale oil. Thus, shale oil in the Qingshankou Formation represents a promising and practical replacement resource for conventional oil. In this study, geological field surveys, core observation, sample tests, and the analysis of well logs were applied to study the geochemical and reservoir characteristics of shales, identify shale oil beds, build shale oil enrichment models, and classify favorable exploration areas of shale oil from the Cretaceous Qingshankou Formation. The organic matter content is high in shales from the first member of the Cretaceous Qingshankou Formation (K₂qn¹), with average total organic carbon (TOC) content exceeding 2%. The organic matter is mainly derived from lower aquatic organisms in a reducing brackish to fresh water environment, resulting in mostly type I kerogen. The vitrinite reflectance (Ro) and the temperature at which the maximum is release of hydrocarbons from cracking of kerogen occurred during pyrolysis (T_max) respectively range from 0.5% to 1.1% and from 430 °C to 450 °C, indicating that the K₂qn¹ shales are in the low-mature to mature stage (Ro ranges from 0.5% to 1.2%) and currently generating a large amount of oil. The favorable depth for oil generation and expulsion is 1800–2200 m and 1900–2500 m, respectively as determined by basin modeling. The reserving space of the K₂qn¹ shale oil includes micropores and mircofractures. The micropore reservoirs are developed in shales interbedded with siltstones exhibiting high gamma ray (GR), high resistivity (Rt), low density (DEN), and slightly abnormal spontaneous potential (SP) in the well-logging curves. The microfracture reservoirs are mainly thick shales with high Rt, high AC (acoustic transit time), high GR, low DEN, and abnormal SP. Based on the shale distribution, geochemical characteristics, reservoir types, fracture development, and the process of shale oil generation and enrichment, the southern Taikang and northern Da'an are classified as two favorable shale oil exploration areas in the Songliao Basin.     

Could the conventionally known Abu Roash “G” reservoir (upper Cenomanian) be a promising active hydrocarbon source in the extreme northwestern part of Egypt? Palynofacies,palaeoenvironmental, and organic geochemical answers

In different areas of the Western Desert of Egypt, the Abu Roash “G” Member exhibits either a reservoir or source affinity. Thus, thirteen cutting samples covering the Abu Roash “G” Member were selected from the Nest-1A well at Matruh Basin to investigate its hydrocarbon source potential. Palynological age dating of the section that is calibrated with foraminifera and ostracodes enabled a proper identification of the “G” Member. Detailed analysis of the vertical distribution of particulate organic matter of this member shows two palynofacies types. PF-1 reflects an outer middle shelf depositional environment of prevailed reducing (suboxic-anoxic) conditions for the organic-rich shales of the lower “G” Member (samples 1–8). While, PF-2 reflects a minor regression that resulted in deposition of another organic-rich shales of the upper “G” Member (samples 9–13) in an inner middle shelf setting under the same prevailing reducing (suboxic-anoxic) conditions.Organic geochemical analysis reveals good to very good potential of the “G” Member as a hydrocarbon source rock (1.8–2.41, avg. 2.15 total organic content wt %). It also shows good to very good petroleum potential (PP: 4.8–11 , avg. 8 mg HC/g rock). Pyrolsis and palynofacies analyses show kerogen type II for the lower “G” Member (samples 1–8), which is characterized by high Hydrogen index (HI: 396 and 329 mg HC/g TOC at depths 1500 and 1560 m) and very high dominance of oil-prone material (amorphous organic matter “AOM”, marine palynomorphs, and sporomorphs) and very rare occurrence of gas-prone material (brown phytoclasts). The upper “G” Member (samples 9–13) shows kerogen type II-III, which is characterized by a lower HI value of 213 mg HC/g TOC at depth 1340 m and it contains fewer amounts of gas-prone material and relatively lower AOM and marine palynomorphs in comparison to the upper “G” Member. Maturation parameters T_max (430–433 °C), production index (PI: 0.1 mg HC/g rock), and thermal alteration index (TAI: 2+) indicate the lower “G” Member has already entered the early oil-window kitchen, and it is expected to produce oil. The upper “G” Member is expected to produce only oil with no gas shows, because it is marginally mature (T_max 426 °C, PI 0.2, TAI 2). The source potential index (SPI: 5.3 t HC/m²) of the “G” Member shows it as currently generating moderate quantities of oil in the area of Nest-1A well.Consequently, the organic-rich shales of the “G” Member are suggested here as a promising, active oil source rock in that extreme northwestern part of the Western Desert of Egypt. However, for commercial oil recovery from the Abu Roash “G” Member, it is highly recommended to explore the depocentre of Matruh Basin at about 150 km east the Nest-1A well.     

Late Cretaceous (Late Turonian,Coniacian and Santonian) petroleum source rocks as part of an OAE,Tarfaya Basin,Morocco

Late Turonian, Coniacian and Santonian source rock samples from a recently drilled well (Tafaya Sondage No. 2; 2010) in the Tarfaya Basin were analyzed for quantity, quality, maturity and depositional environment of the organic matter (OM). To our knowledge such a thick sequence of organic matter-rich Turonian to Santonian source rocks was investigated in that great detail for the first time. Organic geochemical and organic petrological investigations were carried out on a large sample set from the 200 m thick sequence. In total 195 core samples were analyzed for total organic carbon (C_org), total inorganic carbon contents and total sulfur (TS) contents. Rock-Eval pyrolysis and vitrinite reflectance measurements were performed on 28 samples chosen on the basis of their C_org content. Non-aromatic hydrocarbons were analyzed on selected samples by way of gas chromatography–flame ionization detection (GC–FID) and GC–mass spectrometry (GC–MS). The organic matter-rich carbonates revealed a high source rock potential, representing type I kerogen and a good preservation of the organic matter, which is mainly of marine (phytoplankton) origin. HI values are high (400–900 mg/g C_org) and in a similar range as those described for more recent upwelling sediments along the continental slope of North Africa. TS/C_org ratios as well as pristane over phytane ratios indicate variable oxygen content during sediment deposition. All samples are clearly immature with respect to petroleum generation which is supported by maturity parameters such as vitrinite reflectance (0.3–0.4%), T_max values (401–423 °C), production indices (S₁/(S₁ + S₂) > 0.1) as well as maturity parameters based on ratios of specific steranes and hopanes.     

Organic geochemistry and reservoir characterization of the organic matter-rich calcilutite in the Shulu Sag,Bohai Bay Basin,North China

Although extensive studies have been conducted on unconventional mudstone (shales) reservoirs in recent years, little work has been performed on unconventional tight organic matter-rich, fine-grained carbonate reservoirs. The Shulu Sag is located in the southwestern corner of the Jizhong Depression in the Bohai Bay Basin and filled with 400–1000 m of Eocene lacustrine organic matter-rich carbonates. The study of the organic matter-rich calcilutite in the Shulu Sag will provide a good opportunity to improve our knowledge of unconventional tight oil in North China. The dominant minerals of calcilutite rocks in the Shulu Sag are carbonates (including calcite and dolomite), with an average of 61.5 wt.%. The carbonate particles are predominantly in the clay to silt size range. Three lithofacies were identified: laminated calcilutite, massive calcilutite, and calcisiltite–calcilutite. The calcilutite rocks (including all the three lithofacies) in the third unit of the Shahejie Formation in the Eocene (Es₃) have total organic carbon (TOC) values ranging from 0.12 to 7.97 wt.%, with an average of 1.66 wt.%. Most of the analyzed samples have good, very good or excellent hydrocarbon potential. The organic matter in the Shulu samples is predominantly of Type I to Type II kerogen, with minor amounts of Type III kerogen. The temperature of maximum yield of pyrolysate (T_max) values range from 424 to 452 °C (with an average of 444 °C) indicating most of samples are thermally mature with respect to oil generation. The calcilutite samples have the free hydrocarbons (S₁) values from 0.03 to 2.32 mg HC/g rock, with an average of 0.5 mg HC/g rock, the hydrocarbons cracked from kerogen (S₂) yield values in the range of 0.08–57.08 mg HC/g rock, with an average of 9.06 mg HC/g rock, and hydrogen index (HI) values in the range of 55–749 mg HC/g TOC, with an average of 464 mg HC/g TOC. The organic-rich calcilutite of the Shulu Sag has very good source rock generative potential and have obtained thermal maturity levels equivalent to the oil window. The pores in the Shulu calcilutite are of various types and sizes and were divided into three types: (1) pores within organic matter, (2) interparticle pores between detrital or authigenic particles, and (3) intraparticle pores within detrital grains or crystals. Fractures in the Shulu calcilutite are parallel to bedding, high angle, and vertical, having a significant effect on hydrocarbon migration and production. The organic matter and dolomite contents are the main factors that control calcilutite reservoir quality in the Shulu Sag.