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.     

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.     

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).     

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.     

Petroleum retention in the Mandal Formation,Central Graben,Norway

Upper Jurassic organic matter-rich, marine shales of the Mandal Formation have charged major petroleum accumulations in the North Sea Central Graben including the giant Ekofisk field which straddles the graben axis. Recent exploration of marginal basin positions such as the Mandal High area or the Søgne Basin has been less successful, raising the question as to whether charging is an issue, possibly related to high thermal stability of the source organic matter or delayed expulsion from source to carrier.The Mandal Formation is in part a very prolific source rock containing mainly Type II organic matter with <12 wt.-% TOC and HI < 645 mg HC/g TOC but Type III-influenced organofacies are also present. The formation is therefore to varying degrees heterogeneous. Here we show, using geochemical mass balance modelling, that the petroleum expulsion efficiency of the Mandal Formation is relatively low as compared to the Upper Jurassic Draupne Formation, the major source rock in the Viking Graben system. Using maturity series of different initial source quality from structurally distinct regions and encompassing depositional environments from proximal to distal facies, we have examined the relationship between free hydrocarbon retention and organic matter structure. The aromaticity of the original and matured petroleum precursors in the Mandal source rock plays a major role in its gas retention capacity as cross-linked monoaromatic rings act on the outer surface of kerogen as sorptive sites. However, oil retention is a function of both kerogen and involatile bitumen compositions. Slight variations in total petroleum retention capacities within the same kerogen yields suggest that texture of organic matter (e.g. organic porosity) could play a role as well.     

Palynology,palynofacies analysis,depositional environments and source rock potential of Lower Cretaceous successions in southern Iraq

A diverse and well-preserved non-marine and marine palynomorph assemblage was recovered from the Lower Cretaceous Yamama, Ratawi and Zubair formations in southern Iraq.A distinctive monospecific assemblage of the dinocyst Subtilisphaera in the Ru-19 Well, in addition to its frequent occurrence in other wells in the Zubair Formation, reflects an ecologically stressed, marginal-marine environment. This assemblage constitutes the first record of the Subtilisphaera ecozone in Iraq and Arabian realm and indeed only the second one east of Morocco.The palynofacies composition of the studied rock units has been related to previous organic geochemical analyses. Each rock unit has its own palynofacies characteristics and in general, samples dominated by amorphous kerogen have the highest total organic carbon (TOC) and hydrogen index (HI), as is the case for some samples from the studied Yamama Formation and samples belonging to palynofacies PF2 from the Zubair Formation. Samples that are mostly retrieved from the Zubair Formation, containing abundant phyoclasts, have the lowest TOC and HI values.     

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.     

Hydrocarbon potential of the middle Eocene-middle Miocene Mesohellenic piggy-back basin (central Greece): A case study

Two depocentres, >4200 m and >3200 m thick, have been recognized in the Mesohellenic piggy-back basin of middle Eocene to middle Miocene age, where submarine fans have accumulated unconformably over an ophiolite complex. The hydrocarbon potential is indicated by the presence of kerogen types II/III with minor amounts of type I; the evidence is mostly for wet gas and gas, with minor oil. Source rocks are the middle Eocene to lower Oligocene Krania and Eptachori formations, of up to 2000 m total thickness, reaching maturation during the early Miocene. The source rocks consist of outer fan and basin plain deposits. They are conformably overlain by the lower member (late Oligocene) of the up to 2600 m thick Pentalophos Formation, which consists mostly of thick submarine sandstone lobes. Possible stratigraphically trapped reservoirs include the lower member of the Pentalophos Formation, which overlies source rocks, as well as limestones tectonically intercalated within the ophiolite complex, underlying the source rocks. Traps may have formed also on the western side of an internal thrust (Theotokos Thrust), which influenced the evolution of the depocentres.     

Evaluation of Eocene source rock for potential shale oil and gas generation in north Cambay Basin,India

Source rock potential of 108 representative samples from 3 m intervals over a 324 m thick shale section of middle Eocene age from the north Cambay Basin, India have been studied. Variation in total organic carbon (TOC) and its relationship with loss on ignition (LOI) have been used for initial screening. Screened samples were subjected to Rock-Eval pyrolysis and organic petrography. A TOC log indicated wide variation with streaks of elevated TOC. A 30 m thick organic-rich interval starting at 1954 m depth, displayed properties consistent with a possible shale oil or gas reservoir. TOC (wt%) values of the selected samples were found to vary from 0.68% to 3.62%, with an average value of 2.2. The modified van Krevelen diagram as well as HI vs. T_max plot indicate prevalence of Type II to Type III kerogen. T_max measurements ranged from 425 °C to 439 °C, indicating immature to early mature stage, which was confirmed by the mean vitrinite reflectance values (%R_o of 0.63, 0.65 and 0.67 at 1988 m, 1954 m, and 1963 m, respectively). Quantification of hydrocarbon generation, migration and retention characteristics of the 30 m source rock interval suggests 85% expulsion of hydrocarbon. Oil in place (OIP) resource of the 30 m source rock was estimated to be 3.23 MMbbls per 640 acres. The Oil saturation index (OSI) crossover log showed, from a geochemical perspective, moderate risk for producing the estimated reserve along with well location for tapping the identified resource.     

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.     

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.     

Kinetic simulation of hydrocarbon generation from lacustrine type I kerogen from the Songliao Basin: Model comparison and geological application

Eight lacustrine Type I kerogen samples from the Songliao Basin were pyrolyzed using the Rock-Eval equipment, and parallel first-order reaction models including the model with a single frequency factor and a discrete distribution of activation energies (SFF model) and the model with multiple frequency factors and a discrete distribution of activation energies (MFF model) were adopted to analyze kinetic characteristics of hydrocarbon generation of the Type I kerogen samples. The results show that the MFF and SFF models can satisfactory simulate hydrocarbon generation under laboratory conditions and the Type I kerogen shows relatively concentrated activation energy distributions (activation energies of MFF model range from 190 kJ/mol to 250 kJ/mol, activation energies of SFF model range from 220 kJ/mol to 240 kJ/mol), which indicates a homogeneous chemical bond structure of the Type I kerogen. The hydrocarbon generated curves from Type I kerogen were calculated by using the two models with a linear heating rate (3.3 K/Ma). It indicates that the hydrocarbon generation potentials (reaction fractions) are underestimated by using the SFF model during the kerogen thermal degradation for the components with chemical bond of lower and higher activation energies, while this problem can be avoided by using the MFF model. The calculated temperatures for 50% transformation ratio (TR) of all samples differ by as much as 20 °C. For the SFF model, the hydrocarbon generation curve obtained by using the weighted averaged kinetic parameters and the SFF model almost includes every curve calculated by using its own kinetic parameters. While the curve obtained by using the weighted averaged kinetic parameters and the MFF model cannot include every curve for all samples, it lies at the position of the averaged curve of all samples. The application of the MFF model in Songliao Basin shows that if TR 10% is taken as the onset of hydrocarbon generation, the threshold depth of hydrocarbon generation is about 1700 m, which is consistent with other geochemical parameters, such as S₁/TOC, S₁/(S₁ + S₂) and HC/TOC.     

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.     

Thermal maturity history and petroleum generation modelling for the Lower Cretaceous Abu Gabra Formation in the Fula Sub-basin,Muglad Basin,Sudan

Two petroleum source rock intervals of the Lower Cretaceous Abu Gabra Formation at six locations within the Fula Sub-basin, Muglad Basin, Sudan, were selected for comprehensive modelling of burial history, petroleum maturation and expulsion of the generated hydrocarbons throughout the Fula Sub-basin. Locations (of wells) selected include three in the deepest parts of the area (Keyi oilfield); and three at relatively shallow locations (Moga oilfield). The chosen wells were drilled to depths that penetrated a significant part of the geological section of interest, where samples were available for geochemical and source rock analysis. Vitrinite reflectances (Ro %) were measured to aid in calibrating the developed maturation models.The Abu Gabra Formation of the Muglad Basin is stratigraphically subdivided into three units (Abu Gabra-lower, Abu Gabra-middle and Abu Gabra-upper, from the oldest to youngest). The lower and upper Abu Gabra are believed to be the major source rocks in the province and generally contain more than 2.0 wt% TOC; thus indicating a very good to excellent hydrocarbon generative potential. They mainly contain Type I kerogen. Vitrinite reflectance values range from 0.59 to 0.76% Ro, indicating the oil window has just been reached. In general, the thermal maturity of the Abu Gabra source rocks is highest in the Abu Gabra-lower (deep western part) of the Keyi area and decreases to the east toward the Moga oilfied at the Fula Sub-basin.Maturity and hydrocarbon generation modelling indicates that, in the Abu Gabra-Lower, early oil generation began from the Middle- Late Cretaceous to late Paleocene time (82.0–58Ma). Main oil generation started about 58 Ma ago and continues until the present day. In the Abu Gabra-upper, oil generation began from the end of the Cretaceous to early Eocene time (66.0–52Ma). Only in one location (Keyi-N1 well) did the Abu Gabra-upper reach the main oil stage. Oil expulsion has occurred only from the Abu Gabra-lower unit at Keyi-N1 during the early Miocene (>50% transformation ratio TR) continuing to present-day (20.0–0.0 Ma). Neither unit has generated gas. Oil generation and expulsion from the Abu Gabra source rocks occurred after the deposition of seal rocks of the Aradeiba Formation.     

Late Eocene–early Miocene provenance evolution of the Crocker Fan in the southern South China Sea

There are many large-scale Cenozoic sedimentary basins with plentiful river deltas, deep-water fans and carbonate platforms in the southern South China Sea. The Crocker Fan was deposited as a typical submarine fan during the late Eocene–early Miocene, and stretches extensively across the entire Sarawak–Sabah of the northern Borneo area. However, systematic analyses are still lacking regarding its sediment composition and potential source suppliers. No consensus has been reached yet on the provenance evolution and sedimentary infilling processes, which seriously impeded the oil-and-gas exploration undertakings. By combining with sedimentary-facies identification, heavy mineral assemblages, elemental geochemistry and detrital zircon U-Pb dating, this paper aims to generalize an integrated analysis on the potential provenance terranes and restore source-to-sink pathways of the Crocker Fan. In general, the Crocker Fan was initially formed over the Cretaceous–lower/middle Eocene Rajang Group by an angular Rajang unconformity. The continual southward subduction of the proto-South China Sea resulted in magmatic activities and subsequent regional deformation and thrusting along the Lupar Line in the northern Borneo. The lowermost Crocker sequence is featured by a thick conglomerate layer sourced from in-situ or adjacent paleo-uplifts. From the late Eocene to the early Miocene, the Crocker Fan was constantly delivered with voluminous detritus from the Malay Peninsula of the western Sundaland. The Zengmu Basin was widely deposited with delta plain and neritic facies sediments, while the Brunei-Sabah Basin, to the farther east, was ubiquitously characterized by turbiditic sequences. The Crocker Fan successions are overall thick layers of modest-grained sandstones, which formed high-quality reservoirs in the southern South China Sea region.     

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.     

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.     

Organic geochemistry of the Silurian Tanezzuft Formation and crude oils,NC115 Concession,Murzuq Basin,southwest Libya

Thirty-six Silurian core and cuttings samples and 10 crude oil samples from Ordovician reservoirs in the NC115 Concession, Murzuq Basin, southwest Libya were studied by organic geochemical methods to determine source rock organic facies, conditions of deposition, thermal maturity and genetic relationships. The Lower Silurian Hot Shale at the base of the Tanezzuft Formation is a high-quality oil/gas-prone source rock that is currently within the early oil maturity window. The overall average TOC content of the Hot Shale is 7.2 wt% with a maximum recorded value of 20.9 wt%. By contrast, the overlying deposits of the Tanezzuft Formation have an average TOC of 0.6 wt% and a maximum value of 1.1 wt%. The organic matter in the Hot Shale consists predominantly of mixed algal and terrigenous Type-II/III kerogen, whereas the rest of the formation is dominated by terrigenous Type-III organic matter with some Type II/III kerogen. Oils from the A-, B- and H-oil fields in the NC115 Concession were almost certainly derived from marine shale source rocks that contained mixed algal and terrigenous organic input reflecting deposition under suboxic to anoxic conditions. The oils are light and sweet, and despite being similar, were almost certainly derived from different facies and maturation levels within mature source rocks. The B-oils were generated from slightly less mature source rocks than the others. Based on hierarchical cluster analysis (HCA), principal component analysis (PCA), selected source-related biomarkers and stable carbon isotope ratios, the NC115 oils can be divided into two genetic families: Family-I oils from Ordovician Mamuniyat reservoirs were probably derived from older Palaeozoic source rocks, whereas Family-II oils from Ordovician Mamuniyat–Hawaz reservoirs were probably charged from a younger Palaeozoic source of relatively high maturity. A third family appears to be a mixture of the two, but is most similar to Family-II oils. These oil families were derived from one proven mature source rock, the Early Silurian, Rhuddanian Hot Shale. There is a good correlation between the Family-II and -III oils and the Hot Shale based on carbon isotope compositions. Saturated and aromatic maturity parameters indicate that these oils were generated from a source rock of considerably higher maturity than the examined rock samples. The results imply that the oils originated from more mature source rocks outside the NC115 Concession and migrated to their current positions after generation.     

Quantitative modelling of hydrocarbon expulsion and quality grading of tight oil lacustrine source rocks: Case study of Qingshankou 1 member,central depression,Southern Songliao Basin,China

The quality of source rocks plays an important role in the distribution of tight and conventional oil and gas resources. Despite voluminous studies on source rock hydrocarbon generation, expulsion and overpressure, a quality grading system based on hydrocarbon expulsion capacity is yet to be explored. Such a grading system is expected to be instrumental for tight oil and gas exploration and sweet spot prediction. This study tackles the problem by examining Late Cretaceous, lacustrine source rocks of the Qingshankou 1 Member in the southern Songliao Basin, China. By evaluating generated and residual hydrocarbon amounts of the source rock, the extent of hydrocarbon expulsion is modelled through a mass balance method. The overpressure is estimated using Petromod software. Through correlation between the hydrocarbon expulsion and source rock evaluation parameters [total organic carbon (TOC), kerogen type, vitrinite reflectance (R_o) and overpressure], three classes of high-quality, effective and ineffective source rocks are established. High-quality class contains TOC >2%, type-I kerogen, R_o >1.0%, overpressure >7Mpa, sharp increase of hydrocarbon expulsion along with increasing TOC and overpressure, and high expulsion value at R_o >1%. Source rocks with TOC and R_o <0.8%, type-II₂ & III kerogen, overpressure <3Mpa, and low hydrocarbon expulsion volume are considered ineffective. Rocks with parameters between the two are considered effective. The high-quality class shows a strong empirical control on the distribution of tight oil in the Songliao Basin. This is followed by the effective source rock class. The ineffective class has no measurable contribution to the tight oil reserves. Because the hydrocarbon expulsion efficiency of source rocks is controlled by many factors, the lower limits of the evaluation parameters in different basins may vary. However, the classification method of tight source rocks proposed in this paper should be widely applicable.     

Low energy, low latitude wave-dominated shallow marine depositional systems: examples from northern Borneo

The depositional environments of the wave-dominant successions in the middle to late Miocene Belait and Sandakan Formations in northwestern and northern Borneo, respectively, were determined based on grain size distributions, sedimentary structures and facies successions, as well as trace and microfossil assemblages. Generally, progradational shoreface successions in the Belait Formation were deposited in very low wave energy environments where longshore currents were too weak to generate trough cross-bedding. Shoreface sands are laterally continuous for several km and follow the basin contours, suggesting attached beaches similar to the modern Brunei coastline. In contrast, trough cross-bedding is common in the coarser Sandakan Formation and back-barrier mangrove swamp deposits cap the progradational succession as on the modern northern Dent Peninsula coastline, indicating barrier development and higher wave energy conditions than in the Belait Formation. The Borneo examples indicate that barrier systems that include significant tidal facies form under higher wave energy conditions than attached beaches with virtually no tidal facies. Also, Borneo’s low latitude climate promotes back-barrier mangrove which reduces tidal exchange and reduces tidal influence relative to comparable temperate climate systems. The results of the study indicate that depositional systems on low energy, wave-dominated coasts are highly variable, as are the sand bodies and facies associations they generate.