Hydrocarbon source rock potential in the southwestern Gulf of Suez graben: Insights from organic geochemistry and palynofacies studies on well samples from the Ras El Bahar Oilfield

Palynological and biomarker characteristics of organic facies recovered from Cretaceous–Miocene well samples in the Ras El Bahar Oilfield, southwest Gulf of Suez, and their correlation with lithologies, environments of deposition and thermal maturity have provided a sound basis for determining their source potential for hydrocarbons. In addition to palynofacies analysis, TOC/Rock-Eval pyrolysis, kerogen concentrates, bitumen extraction, carbon isotopes and saturated and aromatic biomarkers enable qualitative and quantitative assessments of sedimentary organic matter to be made. The results obtained from Rock-Eval pyrolysis and molecular biomarker data indicate that most of the samples come from horizons that have fair to good hydrocarbon generation potential in the study area. The Upper Cretaceous–Paleocene-Lower Eocene samples contain mostly Type-II to Type-III organic matter with the capability of generating oil and gas. The sediments concerned accumulated in dysoxic–anoxic marine environments. By contrast, the Miocene rocks yielded mainly Type-III and Type-II/III organic matter with mainly gas-generating potential. These rocks reflect deposition in a marine environment into which there was significant terrigenous input. Three palynofacies types have been recognized. The first (A) consists of Type-III gas-prone kerogen and is typical of the Early–Middle Miocene Belayim, Kareem and upper Rudeis formations. The second (B) has mixed oil and gas features and characterizes the remainder of the Rudeis Formation. The third association (C) is dominated by amorphous organic matter, classified as borderline Type-II oil-prone kerogen, and is typical of the Matulla (Turonian–Santonian) and Wata (Turonian) formations. Rock-Eval T_max, PI, hopane and sterane biomarkers consistently indicate an immature to early mature stage of thermal maturity for the whole of the studied succession.     

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.     

Depositional environment and geochemical characteristics of the Lower Carboniferous source rocks in the Marsel area,Chu-Sarysu Basin,Southern Kazakhstan

There are two sets of carbonate source rocks in the Lower Carboniferous layers in Marsel: the Visean (C₁v) and Serpukhovian (C₁sr). However, their geochemical and geological characteristics have not been studied systematically. To assess the source rocks and reveal the hydrocarbon generation potential, the depositional paleoenvironment and distribution of C₁v and C₁sr source rocks were studied using total organic carbon (TOC) content, Rock-Eval pyrolysis and vitrinite reflectance (Ro) data, stable carbon isotope data, gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS) analysis data. The data were then compared with well logging data to understand the distribution of high-quality source rocks. The data were also incorporated into basin models to reveal the burial and thermal histories and timing of hydrocarbon generation. The results illustrated that the average residual TOC contents of C₁v and C₁sr were 0.79% and 0.5%, respectively, which were higher than the threshold of effective carbonate source rocks. Dominated by type-III kerogen, the C₁v and C₁sr source rocks tended to be gas-bearing. The two source rocks were generally mature to highly mature; the average Ro was 1.51% and 1.23% in C₁v and C₁sr, respectively. The source rocks were deposited in strongly reducing to weakly oxidizing marine–terrigenous environments, with most organic material originating from higher terrigenous plants and a few aquatic organisms. During the Permian, the deep burial depth and high heat flow caused a quick and high maturation of the source rocks, which were subsequently uplifted and eroded, stopping the generation and expulsion of hydrocarbons in the C₁v and C₁sr source rocks. The initial TOC fitted by the △logR method was recovered, and it suggests that high-quality source rocks (TOC ≥ 1%) are mainly distributed in the northern and central local structural belt.     

Assessment of thermal evolution of Paleozoic successions of the Holy Cross Mountains (Poland)

Poland is considered the most prospective country for shale gas production in Europe. Hydrocarbon generation/expulsion scenarios, drawn in the latest intensive exploration phases, tend to overestimate maturation levels when compared with brand new data acquired after recent drillings. We tested an integrated workflow to correlate published and original thermal maturity datasets for the Paleozoic to Jurassic successions cropping out in the Holy Cross Mountains. These successions, when preserved in subsurface, host the major source rocks in the area. The application of the workflow allowed us to highlight the burial and thermal evolutionary scenarios of the two tectono-stratigraphic blocks of the Holy Cross Mountains (Łysogòry and Kielce blocks) and to propose this approach as a tool for reducing levels of uncertainty in thermal maturity assessment of Paleozoic successions worldwide. In particular, published datasets including colour alteration indexes of Paleozoic microfossils (conodont, acritarchs) and vitrinite and graptolite reflectance data, show differences in levels of thermal maturity for the Łysogòry (mid mature to overmature) and Kielce (immature to late mature) blocks. Original data, derived from optical analysis, pyrolysis, and Raman spectroscopy on kerogen, and X-Ray diffraction on fine-grained sediments, mostly confirm and integrate published data distribution. 1D thermal models, constrained by these data, show burial and exhumation events of different magnitude, during the Late Cretaceous, for the Łysogòry (maximum burial depths of 9 km) and Kielce (burial depths of 6 km) blocks that have been related to the Holy Cross Fault polyphase activity. In the end, Palynomorph Darkness Index and Raman spectroscopy on kerogen, for Llandoverian and Cambrian rocks, turned out to be promising tools for assessing thermal maturity of Paleozoic organic facies devoid of vitrinite macerals.     

Experimental investigation of thermal maturation on shale reservoir properties from hydrous pyrolysis of Chang 7 shale,Ordos Basin

Thermal maturity has a significant impact on hydrocarbon generation and the storage capacity within shales, but explicit and quantitative characterization of that impact on continental shales is scarce. To better understand how thermal maturation affects the organic and inorganic changes of the continental shale reservoirs, hydrous pyrolysis was performed to simulate the maturation process. TOC, Rock-Eval and adsorption isotherms tests were used to obtain various geochemical parameters of the shale solid residues. The results indicate that with pyrolysis temperature increasing from ambient temperature to 550 °C, the vitrinite reflectance increases from 0.5% to 2.5% Ro and the TOC (total organic carbon) loss weight reaches 25%. Regarding porosity, the fraction of micro-to meso-pores in the shale increases with an increase in the pyrolysis temperature, whereas the macro-pores do not change significantly. The total amount of gas adsorption does not necessarily increase as the TOC is consumed, but the gas adsorption capacity per unit of TOC increases with increasing thermal maturity. Our finding provides theoretical modelling for identifying shale gas development prospective zones according to thermal maturity mapping and for predicting quantitatively the geochemical and inorganic changes that occur with thermal evolution.     

Evaluation of burial history, thermal maturity and source-rock assessment of the Upper Paleozoic succession of the eastern Taurus region, southern Turkey

The regional burial history pattern, thermal maturity variations and source rock assessment of the sedimentary succession in the eastern Taurus region, in the southern part of Turkey, have been studied on surface samples collected from the six different sections which represent the entire region. Organic petrography (Thermal Alteration Index) and geochemical data (TOC content, T_max and HI values) were obtained from transmitted-light microscopy and Rock-Eval pyrolysis.The Lower Paleozoic (Cambrian, Ordovician and Silurian) strata were not investigated and modeled in terms of the maturity and hydrocarbon source rock potential, because of their poor organic matter content and their over maturity resulting from great burial depth (more than 7630 m). Other Paleozoic strata, except the Lower Devonian Ayitepesi Formation, generally have the values of more than 0.5% TOC. Organic matter of the Middle Devonian Safaktepesi sediments are composed of highly terrestrial organic material (type III kerogen), while samples from other three formations (Gumusali, Ziyarettepe and Yigilitepe Formations), while samples from other organic matter (type II and type III kerogen). The average TAI values are as high as 3.4 (equivalent to 1.42 of R₀%) for Ayitepesi and as low as 2.75 (equivalent to 0.77 of R₀%) for Yigilitepe Formations. Time-temperature index values (TTI) indicate that Ziyarettepe and Yigilitepe sediments are marginally mature to mature, while the Devonian strata are overmature. There are minor discrepancies between ΣTTI values and geochemical data in terms of the organic maturity for Devonian strata. In contrast, the e is a consistency between those values for the Ziyarettepe and the Yigilitepe Formations. The onset of oil generation time in the region was initiated from as early as the Norian (216 Ma) to as late as the Lutetian (45 Ma).Regional variations in the level of thermal and source-rock maturities of the Upper Paleozoic sediments in the eastern Taurus region largely depend on burial depth.     

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).     

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.     

Barbados: maturation,source rock potential and burial history within a Cenozoic accretionary complex

A number of diagenetic properties were studied in sedimentary rocks exposed along a 25 km across-strike transect on Barbados, the crest of the Barbados accretionary complex. The island of Barbados consists of three structural levels: a lower (mostly Eocene or undated) basal complex composed of quartzose turbidites, hemipelagites and melange; an intermediate level (Eocene to Miocene) of nappes composed mostly of calcareous pelagite; and a Pleistocene coral cap. Diagenetic studies concentrated on the basal complex although preliminary data from the nappes are also presented. The following subjects were studied: (1) clay mineralogy (% illite interlayers in mixed-layer clays); (2) vitrinite reflectance; (3) organic type and maturation, by Rock-Eval pyrolysis; (4) thermal alteration index of spores and pollen; (5) dry bulk density; (6) silica mineralogy. Taken together, the data can be interpreted to indicate maximum temperatures attained during diagenesis of less than 80°C. Based on a uniform palaeogeothermal gradient of 15°C km^?1, and a temperature at the sediment/water interface of 10°C, maximum burial depths of basement complex rocks were about 2–5 km. Minimum possible burial depths are < 1 km. No across-strike changes in maturation are observed indicating that these trench-associated rocks were uplifted uniformly. Mudstones are typically rich in total organic carbon (> 1 %), and are immature. Organic matter was derived mostly from terrigenous or oxidized sources (type III kerogens), although some marine planktonic sources are indicated locally (type II kerogens). Organic matter is therefore primarily gas-prone.     

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.     

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).     

Source rock characteristics and hydrocarbon generation modelling of Upper Cretaceous Mukalla Formation in the Jiza-Qamar Basin,Eastern Yemen

The Upper Cretaceous Mukalla coals and other organic-rich sediments which are widely exposed in the Jiza-Qamar Basin and believed to be a major source rocks, were analysed using organic geochemistry and petrology. The total organic carbon (TOC) contents of the Mukalla source rocks range from 0.72 to 79.90% with an average TOC value of 21.50%. The coals and coaly shale sediments are relatively higher in organic richness, consistent with source rocks generative potential. The samples analysed have vitrinite reflectance in the range of 0.84–1.10 %Ro and pyrolysis T_max in the range of 432–454 °C indicate that the Mukalla source rocks contain mature to late mature organic matter. Good oil-generating potential is anticipated from the coals and coaly shale sediments with high hydrogen indices (250–449 mg HC/g TOC). This is supported by their significant amounts of oil-liptinite macerals are present in these coals and coaly shale sediments and Py-GC (S₂) pyrograms with n-alkane/alkene doublets extending beyond nC₃₀. The shales are dominated by Type III kerogen (HI < 200 mg HC/g TOC), and are thus considered to be gas-prone.One-dimensional basin modelling was performed to analysis the hydrocarbon generation and expulsion history of the Mukalla source rocks in the Jiza-Qamar Basin based on the reconstruction of the burial/thermal maturity histories in order to improve our understanding of the of hydrocarbon generation potential of the Mukalla source rocks. Calibration of the model with measured vitrinite reflectance (Ro) and borehole temperature data indicates that the present-day heat flow in the Jiza-Qamar Basin varies from 45.0 mW/m² to 70.0 mW/m² and the paleo-heat flow increased from 80 Ma to 25 Ma, reached a peak heat-flow values of approximately 70.0 mW/m² at 25 Ma and then decreased exponentially from 25 Ma to present-day. The peak paleo-heat flow is explained by the Gulf of Aden and Red Sea Tertiary rifting during Oligocene-Middle Miocene, which has a considerable influence on the thermal maturity of the Mukalla source rocks. The source rocks of the Mukalla Formation are presently in a stage of oil and condensate generation with maturity from 0.50% to 1.10% Ro. Oil generation (0.5% Ro) in the Mukalla source rocks began from about 61 Ma to 54 Ma and the peak hydrocarbon generation (1.0% Ro) occurred approximately from 25 Ma to 20 Ma. The modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the Mukalla source rocks began from 15 Ma to present-day.     

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.     

Paleoenvironment and sea-level change in the early Cretaceous Barents Sea—implications from near-shore marine sapropels

The late Volgian (early "Boreal" Berriasian) sapropels of the Hekkingen Formation of the central Barents Sea show total organic carbon (TOC) contents from 3 to 36 wt%. The relationship between TOC content and sedimentation rate (SR), and the high Mo/Al ratios indicate deposition under oxygen-free bottom-water conditions, and suggest that preservation under anoxic conditions has largely contributed to the high accumulation of organic carbon. Hydrogen index values obtained from Rock-Eval pyrolysis are exceptionally high, and the organic matter is characterized by well-preserved type II kerogen. However, the occurrence of spores, freshwater algae, coal fragments, and charred land-plant remains strongly suggests proximity to land. Short-term oscillations, probably reflecting Milankovitch-type cyclicity, are superimposed on the long-term trend of constantly changing depositional conditions during most of the late Volgian. Progressively smaller amounts of terrestrial organic matter and larger amounts of marine organic matter upwards in the core section may have been caused by a continuous sea-level rise.     

Thermal evolution of the Kuh-e-Asmari and Sim anticlines in the Zagros fold-and-thrust belt: Implications for hydrocarbon generation

Mixed layer clay minerals, vitrinite reflectance and geochemical data from Rock-Eval pyrolysis were used to constrain the burial evolution of the Mesozoic–Cenozoic successions exposed at the Kuh-e-Asmari (Dezful Embayment) and Sim anticlines (Fars province) in the Zagros fold-and-thrust belt. In both areas, Late Cretaceous to Pliocene rocks, show low levels of thermal maturity in the immature stages of hydrocarbon generation and early diagenetic conditions (R0 I–S and R_o% values < 0.5). At depths of 2–4 km, T_max values (435–450 °C) from organic-rich layers of the Sargelu, Garau and Kazhdumi source rocks in the Kuh-e-Asmari anticline indicate mid to late mature stages of hydrocarbon generation. One dimensional thermal models allowed us to define the onset of oil generation for the Middle Jurassic to Eocene source rocks and pointed out that sedimentary burial is the main factor responsible for measured levels of thermal maturity. Specifically, the Sargelu and Garau Formations entered the oil window prior to Zagros folding in Late Cretaceous times, the Kazhdumi Formation during middle Miocene (syn-folding stage), and the Pabdeh Formation in the Late Miocene–Pliocene after the Zagros folding. In the end, the present-day distribution of oil fields in the Dezful Embayment and gas fields in the Fars region is primarily controlled by lithofacies changes and organic matter preservation at the time of source rock sedimentation. Burial conditions during Zagros folding had minor to negligible influence.     

Generation characteristics of Mesozoic syn- and post-rift source rocks,Bonaparte Basin,Australia: New insights from compositional kinetic modelling

Potential source rocks on the Laminaria High, a region of the northern Bonaparte Basin on the North West Shelf of Australia, occur within the Middle Jurassic to Lower Cretaceous early to post-rift sequences. Twenty-two representative immature source rock samples from the Jurassic to Lower Cretaceous (Plover, Laminaria, Frigate, Flamingo and Echuca Shoals) sequences were analysed to define the hydrocarbon products that analogous mature source rocks could have generated during thermal maturation and filled the petroleum reservoirs in the Laminaria High region. Rock-Eval pyrolysis data indicate that all the source rocks contain type II–III organic matter and vary in organic richness and quality. Open system pyrolysis-gas chromatography on extracted rock samples show a dominance of aliphatic components in the pyrolysates. The Plover source rocks are the exception which exhibit high phenolic contents due to their predominant land-plant contribution. Most of the kerogens have the potential to generate Paraffinic–Naphthenic–Aromatic oils with low wax contents. Bulk kinetic analyses reveal a relatively broad distribution of activation energies that are directly related to the heterogeneity in the kerogens. These kinetic parameters suggest different degrees of thermal stability, with the predicted commencement of petroleum generation under geological heating conditions covering a relatively broad temperature range from 95 to 135 °C for the Upper Jurassic−Lower Cretaceous source rocks. Both shales and coals of the Middle Jurassic Plover Formation have the potential to generate oil at relatively higher temperatures (140–145 °C) than those measured for crude oils in previous studies. Hence, the Frigate and the Flamingo formations are the main potential sources of oils reservoired in the Laminaria and Corallina fields. Apart from being a reservoir, the Laminaria Formation also contains organic-rich layers, with the potential to generate oil. For the majority of samples analysed, the compositional kinetic model predictions indicate that 80% of the hydrocarbons were generated as oil and 20% as gas. The exception is the Lower Cretaceous Echuca Shoals Formation which shows the potential to generate a greater proportion (40%) of gas despite its marine source affinity, due to inertinite dominating the maceral assemblage.     

Petroleum generation characteristics of heterogeneous source rock from Chia Gara formation in the Kurdistan region,northern Iraq as inferred by bulk and quantitative pyrolysis techniques

This study is the first attempt which provides information regarding the bulk and quantitative pyrolysis results of the Chia Gara Formation from the Kurdistan region, northern Iraq. Ten representative early-mature to mature samples from the Chia Gara Formation were investigated for TOC contents, Rock Eval pyrolysis, pyrolysis-GC and bulk kinetic parameters. These analyses were used to characterize the petroleum generated during thermal maturation of the Chia Gara source rock and to clarify the quantity of the organic matter and its effect on the timing of petroleum generation.Pyrolysis HI data identified two organic facies with different petroleum generation characteristics; Type II–III kerogen with HI values of >250 mg HC/g TOC, and Type III kerogen with HI values < 100 mg HC/g TOC. These types of kerogen can generate liquid HCs and gas. This is supported by the products of pyrolysis–gas chromatography (Py–GC) analysis of the extracted rock samples. Pyrolysis products show a dominance of a marine organic matter with variable contributions from terrestrial organic matter (Types II–III and III kerogen), and produces mainly paraffinic-naphthenic-aromatic low wax oils with condensate and gas.Bulk kinetic analysis of the Chia Gara source rock indicates a heterogeneous organic matter assemblage, typical of restricted marine environments in general. The activation energy distributions reveal relatively broad and high values, ranging from 40 to 64 kcal/mol with pre-exponential factors varying from 2.2835 E+12/sec to 4.0920 E+13/sec. The predicted petroleum formation temperature of onset (TR 10%) temperatures ranges from 110 to 135 °C, and peak generation temperatures (geological T_max) between 137 °C and 152 °C. The peak generation temperatures reach a transformation ratio in the range of 42–50% TR, thus the Chia Gara source rock could have generated and expelled significant quantities of petroleum hydrocarbons in the Kurdistan of Iraq.     

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.     

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.