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.     

Geochemistry,reservoir characterization and hydrocarbon generation potential of lacustrine shales: A case of YQ-1 well in the Yuqia Coalfield,northern Qaidam Basin,NW China

Ever since a breakthrough of marine shales in China, lacustrine shales have been attracting by the policy makers and scientists. Organic-rich shales of the Middle Jurassic strata are widely distributed in the Yuqia Coalfield of northern Qaidam Basin. In this paper, a total of 42 shale samples with a burial depth ranging from 475.5 m to 658.5 m were collected from the Shimengou Formation in the YQ-1 shale gas borehole of the study area, including 16 samples from the Lower Member and 26 samples from the Upper Member. Geochemistry, reservoir characteristics and hydrocarbon generation potential of the lacustrine shales in YQ-1 well were preliminarily investigated using the experiments of vitrinite reflectance measurement, maceral identification, mineralogical composition, carbon stable isotope, low-temperature nitrogen adsorption, methane isothermal adsorption and rock eval pyrolysis. The results show that the Shimengou shales have rich organic carbon (averaged 3.83%), which belong to a low thermal maturity stage with a mean vitrinite reflectance (R_o) of 0.49% and an average pyrolytic temperature of the generated maximum remaining hydrocarbon (T_max) of 432.8 °C. Relative to marine shales, the lacustrine shales show low brittleness index (averaged 34.9) but high clay contents (averaged 55.1%), high total porosities (averaged 13.71%) and great Langmuir volumes (averaged 4.73 cm⁻³ g). Unlike the marine and marine-transitional shales, the quartz contents and brittleness index (BI) values of the lacustrine shales first decrease then increase with the rising TOC contents. The kerogens from the Upper Member shales are dominant by the oil-prone types, whereas the kerogens from the Lower Member shales by the gas-prone types. The sedimentary environment of the shales influences the TOC contents, thus has a close connection with the hydrocarbon potential, mineralogical composition, kerogen types and pore structure. Additionally, in terms of the hydrocarbon generation potential, the Upper Member shales are regarded as very good and excellent rocks whereas the Lower Member shales mainly as poor and fair rocks. In overall, the shales in the top of the Upper Member can be explored for shale oil due to the higher free hydrocarbon amount (S₁), whereas the shales in the Lower Member and the Upper Member, with the depths greater than 1000 m, can be suggested to explore shale gas.     

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.     

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.     

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.     

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 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.     

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.     

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.     

Organic geochemistry of marine source rocks and pyrobitumen-containing reservoir rocks of the Sichuan Basin and neighbouring areas,SW China

Three bitumen fractions were obtained and systematically analysed for the terpane and sterane composition from 30 Paleozoic source rocks and 64 bitumen-containing reservoir rocks within the Upper Sinian, Lower Cambrian, Lower Silurian, Middle Carboniferous, Upper Permian and Lower Triassic strata in the Sichuan Basin and neighbouring areas, China. These bitumen fractions include extractable oils (bitumen I), oil-bearing fluid inclusions and/or closely associated components with the kerogen or pyrobitumen/mineral matrix, released during kerogen or pyrobitumen isolation and demineralization (bitumen II), and bound compounds within the kerogen or pyrobitumen released by confined pyrolysis (bitumen III). In addition, atomic H/C and O/C ratios and carbon isotopic compositions of kerogen and pyrobitumen from some of the samples were measured. Geochemical results and geological information suggest that: (1) in the Central Sichuan Basin, hydrocarbon gases in reservoirs within the fourth section of the Upper Sinian Dengying Formation were derived from both the Lower Cambrian and Upper Sinian source rocks; and (2) in the Eastern Sichuan Basin, hydrocarbon gases in Middle Carboniferous Huanglong Formation reservoirs were mainly derived from Lower Silurian source rocks, while those in Upper Permian and Lower Triassic reservoirs were mainly derived from both Upper Permian and Lower Silurian marine source rocks. For both the source and reservoir rocks, bitumen III fractions generally show relatively lower maturity near the peak oil generation stage, while the other two bitumen fractions show very high maturities based on terpane and sterane distributions. Tricyclic terpanes evolved from the distribution pattern C₂₀ < C₂₁ < C₂₃, through C₂₀ < C₂₁ > C₂₃, finally to C₂₀ > C₂₁ > C₂₃ during severe thermal stress. The concentration of C₃₀ diahopane in bitumen III (the bound components released from confined pyrolysis) is substantially lower than in the other two bitumen fractions for four terrigenous Upper Permian source rocks, demonstrating that this compound originated from free hopanoid precursors, rather than hopanoids bound to the kerogen.     

Thermal maturity of Miocene organic matter from the Carpathian Foredeep in the Czech Republic: 1D and 3D models

A three-dimensional reconstruction of burial and palaeogeothermal conditions is presented for Miocene sediments of the Carpathian Foredeep beneath the Outer Western Carpathians fold and trust belt in the eastern part of the Czech Republic. The sedimentary units involved include autochthonous Paleozoic sequences, Miocene deposits of the Carpathian Foredeep and of the Western Carpathian nappe system. Reservoir rocks with economic oil and gas accumulations occur in the fractured crystalline basement and in the Neogene Carpathian Foredeep. The studied Vizovice area, is characterized by rocks representing both Variscan and Carpathian orogenic cycles. The 3D thermal maturity and subsidence model presented allows the significance of both tectonic events to be evaluated. The model, calibrated by vitrinite reflectance from eight boreholes proved that eroded units related to the Variscan orogeny approach, in amount, those eroded during the Carpathian orogeny. The thickness of the eroded rocks does not exceed 300 m in either case. Vitrinite reflectance data from representative core samples of the Miocene organic matter show that R_r values increase with depth from 0.36 to 0.58%. A re-evaluation of archival data on the quantity and quality of organic matter shows that total organic carbon ranges from 0.20 to 2.92 wt%, and residual hydrocarbons (S₂) from 0.04 to 8.48 mg HC/g rock. These results lead to the conclusion that Neogene Unit II that was interpreted as coastline-through to shallow-marine deposition environment within the Carpathian Foredeep in the Czech Republic is potential source rock for hydrocarbon accumulations.     

A new TOC,Rock-Eval,and carbon isotope record of Lower Jurassic source rocks from the Slyne Basin,offshore Ireland

This paper presents an integrated assessment of total organic carbon, Rock-Eval pyrolysis, carbonate δ¹³C and δ¹⁸O, and total organic carbon δ¹³C record of Upper Sinemurian–Aalenian age from the Slyne Basin (well 18/25-1), offshore Ireland. Total organic carbon (up to 5.2 wt%) and Rock-Eval pyrolysis data highlights the Portree Shale Formation Equivalent (Lower–?Middle Toarcian) as a mature (T_max ∼440 °C) source rock dominated by type II kerogens. This interval is more than 90 m thick.In a previously unexplored paleogeographical domain regarding stable carbon isotopes, the δ¹³C record shows positive values during the Upper Sinemurian, a negative trend followed by a minor positive trend during the uppermost Sinemurian–Lower Pliensbachian, a negative trend during the lowermost Lower Toarcian, and then the return to more positive δ¹³C values. Despite the biostratigraphic uncertainty, the coarse resolution of the dataset, and the complex assessment of diagenetic effects, we suggest that the δ¹³C record of the studied well records the Raricostatum Zone positive CIE, the Sinemurian-Pliensbachian Boundary Event, and the negative CIE associated with the T-OAE. The T-OAE positive CIE is not clearly defined in the obtained dataset. The slight post T-OAE negative CIE recovery to more positive values and the continuation of a relatively high organic content is coeval with a regional organic matter preservation interval observed in several Northern-European locations.These new datasets and their interpretation add to the understanding of the paleoenvironmental dynamics during the Early–?Middle Jurassic in the Northern European domain and opens new possibilities for hydrocarbon exploration in Ireland's offshore.     

Bitumen biomarkers in the Mid-Proterozoic Ilímaussaq intrusion, Southwest Greenland - A challenge to the mantle gas theory

GC and GC/MS/MS analysis on rock extracts has shown that the bitumen in the peralkaline Ilímaussaq intrusion, previously assumed to be abiogenic, is biotic in origin. A biotic origin is in accordance with previously published stable carbon isotopic data on bituminous matter in the rocks. The biomarker distribution in the bitumen, including the less common bicadinanes, resembles that of oil seeps on the central West Greenland coast 2200 km farther north, whose source rocks and migration history are relatively well established. We use a recent re-construction of the subsidence and later exhumation of the West Greenland coastal region during the Mesozoic-Cenozoic (Japsen et al., 2006a, b) to anticipate that hydrocarbons migrated from deeper parts of the basin offshore west of Greenland. The rocks of Ilímaussaq were probably more deeply invaded than the surrounding granites due to their higher proportion of corroded minerals, which may explain why bitumen has not been observed elsewhere in the area.Hydrocarbon gases (C1-C5) present in fluid inclusions were also analysed, after having been released by treatment with hydrochloric acid that resulted in an almost complete disintegration of the Ilímaussaq intrusion rocks. The acid extraction method proved generally more efficient than the crushing procedure applied by others, but gave similar results for the chemical composition of the gas (CH₄: 88-97%) and isotopic ratios (δ¹³C₄CH: −1.6 to −5.0‰; δ¹³CC₂H₆: −9.2 to −12.5‰), with the exception of hydrocarbons hosted in quartz, which showed significantly lower isotopic values for methane (Graser et al., 2008). Previous researchers have suggested an abiotic origin for these hydrocarbon gases, but we suggest a biotic origin for the majority of them, not just those in quartz, assuming that the isotopic ratio of the constituents have changed due to loss of gas by diffusion. The assumption of gas loss via diffusion is supported by published studies on micro-fissures in minerals typical of the Ilímaussaq and field investigations showing diffusive loss of gas from the peralkaline Khibina and Lovozero massifs on the Kola Peninsula, Russia, which are, in many respects of mineralogy and hydrocarbon content, similar to the Ilímaussaq intrusion.Both the hydrocarbon gases and bitumen in the Khibina and Lovozero massifs have been cited as prime examples of a deep mantle source, although the carbon isotopic ratio of the bitumen clearly pointed to an organic origin. The trends in carbon isotopic ratio of methane released with time from freshly exposed rocks also supports our hypothesis of ¹³C enrichment of the methane remaining within the rock. Thus, there is good evidence that the hydrocarbons in the Kola alkaline massifs are mostly biotic in origin, in which case the probability of finding economic hydrocarbon accumulations from a deep mantle source seems exceedingly small.     

Preliminary organic petrography of Palaeozoic rocks from the Grand Banks,Newfoundland

Samples of lower Palaeozoic bedrock from the Grand Banks of Newfoundland were examined using reflected light microscopy and Rock-Eval pyrolysis. These samples contained organic material which included bitumen (structureless organic material), acritarchs, chitinozoa, scolecodonts and graptolites. The reflectance of the organic material increased from acritarchs towards graptolites with bitumen showing a wide range of reflectance. Multiple phases of oil migration through one sample were inferred by examination of the bitumens: the lowest reflecting being more recent than the highest reflecting bitumen. Combined reflectance and Rock-Eval analysis indicate that these samples are mature to overmature. The two oldest samples (Arenig-Llanvirn, Ordovician) are assessed as mature and as having potential for generation of liquid hydrocarbons, but must be considered as mainly gas prone.     

Mineral carbon MinC(%) from Rock-Eval analysis as a reliable and cost-effective measurement of carbonate contents in shale source and reservoir rocks

The abundance of carbonate minerals in rocks is an important element for petroleum geochemists, geologists and engineers to consider during hydrocarbon exploration and production. Carbonate minerals can be related to the depositional environments of the source rocks and hence the type of organic matter that can be subsequently modified through diagenetic processes. The total carbonate content in shales can also be used to deduce their fracability as reservoir rock for shale gas/oil extraction. At present, mineralogical analysis by X-ray diffraction (XRD) is the most widely used technique in the oil and gas-related petrophysical and geochemical laboratories for identifying and quantifying carbonate minerals in rock samples. In contrast, the use of the total mineral carbon content parameter MinC (%) from Rock-Eval analysis has been limited despite (1) the parameter's effectiveness as demonstrated through instrument and methodology development; and (2) the presence of a large volume of Rock-Eval results due to its widespread use in the oil and gas industry.In this study, we acquired XRD and Rock-Eval analytical results on over nine hundred rock samples ranging from Ordovician to Cretaceous age from four petroleum sedimentary basins in Canada. Least-squares regression analyses produce empirical equations with R² values greater than 0.92 for the correlations between XRD total carbonate contents and the Rock-Eval MinC (%) values of six different suites of samples. This indicates that the MinC (%) values generated by Rock-Eval 6 and other instruments of similar capability can be used with confidence for estimating the amounts of total carbonates in sedimentary rock samples. While the correlation between the two types of carbonate content measurements is geology-specific, a global linear regression model (R² of 0.97) based on the large combined data set has been proposed for approximating the total carbonate abundances based on Rock-Eval MinC (%) values.     

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

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

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.     

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.     

Oil-bearing inclusions in vein quartz and calcite and,bitumens in veins: Testament to multiple phases of hydrocarbon migration in the Barrandian basin (lower Palaeozoic), Czech Republic

The petroleum charge history of the Barrandian basin was investigated by analysing quartz and calcite and organic phases that occur in veins and fractures cutting dolerite sills within the Liteň Formation (Silurian). The geochemical characteristics of fluid inclusions trapped in vein quartz and calcite, vein bitumens and adjacent potential source rocks when combined with burial and thermal history data reflect the presence of at least three separate hydrocarbon charge episodes. Solid highly reflecting (R_max = 0.92–1.49%) bitumen provides information on the first and oldest episode of oil migration. The precursor oil was probably derived relatively early during diagenesis from nearby organic-rich sediments and was subsequently thermally altered to form the solid bitumen.     

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.