Organic geochemical characteristics and oil generating potential of the Upper Jurassic Safer shale sediments in the Marib-Shabowah Basin,western Yemen

The organic rich Safer shales exposed in the north-central part of onshore Marib-Shabowah Basin are evaluated and their depositional environments are interpreted. Total organic carbon contents (TOC) of the shales range from 1.02–16.8 wt%, and yield hydrogen index (HI) values ranging from 130 to 820 mg HC/g TOC, consistent with mainly Type II with minor contributions from Type I and mixed Types II–III kerogens. The Safer shale samples have vitrinite reflectance values in the range of 0.5–1.0 R_o%, indicating early mature to peak mature stage for oil generation. T_max values range from 429–438 °C, which are in reasonably good agreement with vitrinite reflectance data. Kerogen microscopy shows that the Safer shales are characterized by high amounts of organic matter, consisting predominantly of yellow fluorescing amorphous organic matter and alginite of marine origin. This is supported by their high content of hydrogen rich Type II and I oil-prone kerogen.The biomarker distributions of the Upper Jurassic Safer extracts are characterized by dominant low to medium molecular weight compounds (n-C₁₄ to n-C₂₀), low Pr/Ph ratio (<1.0), high phytane/n-C₁₈ ratios (0.82–2.68), and predominant regular sterane C₂₇. All biomarker parameters clearly indicate that the organic matter was derived from marine algal inputs and deposited under anoxic (reducing) conditions. Hypersaline conditions also prevailed during deposition of these sediments, as indicated by the presence of gammacerane.     

Evaluation of Organic Matter,Hydrocarbon Source,and Depositional Environment of Onshore Warkalli Sedimentary Sequence from Kerala-Konkan Basin,South India

Multidisciplinary analysis of the carbonaceous sediments of Warkalli Formation (Mio-Pliocene) from the Warkalli cliff section has been done to assess the source of organic matter, palaeodepositional settings and the hydrocarbon potential. The n-alkane distribution from n-C₁₂ to n-C₃₃ along with bimodal distribution indicates significant organic matter contribution from microbial activity and higher plants. The contribution from angiosperm source vegetation is indicated by the oleanane type of triterpenoids. The hopanes distribution indicates the immature stage of the organic matter, which is in agreement with the T_max (av. 401 °C) and huminite reflectance (av. 0.28% R_r) values. The total organic carbon (TOC) contents vary between 0.8 and 6.72 wt. % in the studied sediments. Hydrogen index and oxygen index values range from 16 to106 mg HC/g TOC, and 113 to 344 mg CO₂/g TOC, respectively. The maceral content is low, being dominated by the detrohuminite submaceral and the mineral matter accounts for 68 to 77% of the total composition. The phytoclast group (63–87%) is dominant with subordinate amorphous organic matter (4–35%). The study shows that the sediments were deposited in a marginal suboxic basin with intermittent variations. All the parameters unequivocally suggest that the studied sequence holds the potential to generate gaseous hydrocarbons.     

Source rock potential of selected Cretaceous shales,Orange Basin,South Africa

Twenty Cretaceous shale samples from two wells in the Orange Basin of South Africa were evaluated for their source rock potential. They were sampled from within a 1400 m-thick sequence in boreholes drilled through Lower to Upper Cretaceous sediments. The samples exhibit total organic carbon (TOC) content of 1.06–2.17%; Rock-Eval S2 values of 0.08–2.27 mg HC/g; and petroleum source potential (SP), which is the sum of S1 and S2, of 0.10–2.61 mg HC/g, all indicating the presence of poor to fair hydrocarbon generative potential. Hydrogen index (HI) values vary from 7 to 128 mg HC/g organic carbon and oxygen index (OI) ranges from 37 to 195 mg CO₂/g organic carbon, indicating predominantly Type III kerogen with perhaps minor amounts of Type IV kerogen. The maturity of the samples, as indicated by T _max values of 428–446°C, ranges from immature to thermally mature with respect to oil generation. Measured vitrinite reflectance values (%Ro) of representative samples indicate that these samples vary from immature to mature, consistent with the thermal alteration index (TAI) (spore colour) and fluorescence data for these samples. Organic petrographic analysis also shows that amorphous organic matter is dominant in these samples. Framboidal pyrite is abundant and may be indicative of a marine influence during deposition. Although our Rock-Eval pyrolysis data indicate that gas-prone source rocks are prevalent in this part of the Orange Basin, the geochemical characteristics of samples from an Aptian unit at 3318 m in one of the wells suggest that better quality source rocks may exist deeper, in more distal depositional parts of the basin.     

Oil-generating potential of Tertiary coals and other organic-rich sediments of the Nyalau Formation,onshore Sarawak

The oil-generating potential of coals and other organic-rich sediments from the Late Oligocene–Early Miocene Nyalau Formation, the offshore extension of which is believed to be a major source rock, is evaluated. Coals of the Nyalau Formation are typically dominated by vitrinite, with moderate and low amounts of exinite and inertinite, respectively. Significant amounts of clay minerals are present in these coals and those containing between 15 to 65% mineral matter by volume are termed carbargilite. The samples analysed range from sub-bituminous to high-volatile bituminous rank, possessing vitrinite reflectance in the range 0.42% to 0.72%. T_max values range from 425°–450°C which is in good agreement with vitrinite reflectance data. Good oil-generating potential is anticipated from these coals and carbargilites with moderate to rich exinite content (15–35%). This is supported by their high hydrogen indices of up to 400 mgHC/gTOC, Py–GC (S2) pyrograms with n-alkane/alkene doublets extending beyond nC₃₀, and their being in the early to mid-mature oil-window range. Petrographically, the most significant evidence of the oil-generating potential of these coals is the generation of petroleum-like materials (exsudatinite) visible under the microscope. Exsudatinite is a secondary maceral, commonly considered to represent the very beginning of oil generation in coal, which is shown here to also have an important role to play in hydrocarbon expulsion. The precursor of exsudatinite in these coals is the maceral bituminite which readily expels or mobilizes to hydrocarbon-like material in the form of oil smears and/or exsudatinite as observed under the microscope. The maceral bituminite is considered to play a major generative role via early exsudatinite generation, which is considered to facilitate the overall expulsion process in coaly source rocks.     

Analysis of relationships between geochemical parameters of petroleum potential in related source and carbonaceous materials

A worldwide data set of 1,085 samples containing organic matter of the type II/III kerogen from Carboniferous to Cenozoic was used to analyse the evolution of the hydrogen index (HI), quality index (QI), and bitumen index (BI) with increasing thermal maturity. The HI_max, QI_max and BI_max lines were defined, based on statistical analysis and cross-plots of HI, QI and BI versus the vitrinite reflectance (%Ro) and T _max (°C). The constructed HI, QI and BI bands were broad at low maturities and gradually narrowed with increasing thermal maturity. The petroleum generation potential is completely exhausted at a vitrinite reflectance of 2.0–2.2 % and T _max of 510–520 °C. An increase in HI and QI suggests extra petroleum potential related to changes in the structure of the organic material. A decline in BI signifies the start of the oil window and occurs within the vitrinite reflectance range 0.75–1.05 % and T _max of 440–455 °C. Furthermore, petroleum potential can be divided into four different parts based on the cross-plot of HI versus %Ro. The area with the highest petroleum potential is located in “Samples and methods” with %Ro = 0.6–1.0 %, and HI > 100. Oil generation potential is rapidly exhausted at “Results and discussion” with %Ro > 1.0 %. This result is in accordance with the regression curve of HI and QI with %Ro based on 80 samples with %Ro = 1.02–3.43 %. The exponential equation of regression can thus be achieved: HI = 994.81e^?1.69Ro and QI = 1,646.2e^?2.003Ro (R ² = 0.72). The worldwide organic material data set defines two range of oil window represented by the upper and lower limits of the BI band: %Ro 0.75–1.95 %, T _max 440–525 °C, and %Ro 1.05–1.25 %, T _max 455–465 °C, respectively.     

Organic matter geochemistry and petrography of Late Cretaceous (Cenomanian-Turonian) organic-rich shales from the Belle Fourche and Second White Specks formations,west-central Alberta,Canada

Organic-rich mudstones with up to 10 wt% TOC from the upper portion of the Belle Fourche Formation and the lower part of the Second White Specks Formation in the Western Canada Sedimentary Basin were evaluated as source rocks. Both geochemistry and organic petrography indicate an open marine paleoenvironment with deposition of Type II kerogen based on the predominance of marine alginite and amorphous organic matter (OM), limited amounts of terrigenous vitrinite and inertinite macerals, the presence of marine fossils, and the low ratio of TOC to total sulfur (∼1.26). The prevalence of short-chain n-alkanes (n-C₁₃ to n-C₁₉), a predominance of C₂₈ αββ(H)-20S steranes, and small concentrations of oleanane confirm the dominantly algal and planktonic origin of OM. Alternating oxic to anoxic paleoenvironmental sedimentary conditions are proposed based on common bioturbation, abundant inoceramid prisms, and good organic richness. Biomarker distributions are consistent with intermittent anoxia, without unequivocal evidence for water column stratification or hypersalinity. The thermal maturity measured in seven sediment cores by different methods consistently indicates a westward increase in maturity according to vitrinite reflectance, T_max, and hopane and sterane biomarkers. Two cores are thermally immature (∼0.42 %Ro), one is early mature (∼0.65 %Ro), and four cores are within the oil window (∼0.78 to 0.89 %Ro). All thermally mature cores retain good to very good hydrocarbon potential (248 mg HC/g rock) and are dominantly oil-prone and minor gas-prone based on their maceral compositions. The upper Belle Fourche and lower Second White Specks Formations represent potential targets for unconventional light shale oil production.     

The petroleum generation potential and effective oil window of humic coals related to coal composition and age

A worldwide data set of more than 500 humic coals from the major coal-forming geological periods has been used to analyse the evolution in the remaining (Hydrogen Index, HI) and total (Quality Index, QI) generation potentials with increasing thermal maturity and the ‘effective oil window’ (‘oil expulsion window’). All samples describe HI and QI bands that are broad at low maturities and that gradually narrow with increasing maturity. The oil generation potential is completely exhausted at a vitrinite reflectance of 2.0–2.2%R_o or T_max of 500–510 °C. The initial large variation in the generation potential is related to the original depositional conditions, particularly the degree of marine influence and the formation of hydrogen-enriched vitrinite, as suggested by increased sulphur and hydrogen contents. During initial thermal maturation the HI increases to a maximum value, HI_max. Similarly, QI increases to a maximum value, QI_max. This increase in HI and QI is related to the formation of an additional generation potential in the coal structure. The decline in QI with further maturation is indicating onset of initial oil expulsion, which precedes efficient expulsion. Liquid petroleum generation from humic coals is thus a complex, three-phase process: (i) onset of petroleum generation, (ii) petroleum build-up in the coal, and (iii) initial oil expulsion followed by efficient oil expulsion (corresponding to the effective oil window). Efficient oil expulsion is indicated by a decline in the Bitumen Index (BI) when plotted against vitrinite reflectance or T_max. This means that in humic coals the vitrinite reflectance or T_max values at which onset of petroleum generation occurs cannot be used to establish the start of the effective oil window. The start of the effective oil window occurs within the vitrinite reflectance range 0.85–1.05%R_o or T_max range 440–455 °C and the oil window extends to 1.5–2.0%R_o or 470–510 °C. For general use, an effective oil window is proposed to occur from 0.85 to 1.7%R_o or from 440 to 490 °C. Specific ranges for HI_max and the effective oil window can be defined for Cenozoic, Jurassic, Permian, and Carboniferous coals. Cenozoic coals reach the highest HI_max values (220–370 mg HC/g TOC), and for the most oil-prone Cenozoic coals the effective oil window may possibly range from 0.65 to 2.0%R_o or 430 to 510 °C. In contrast, the most oil-prone Jurassic, Permian and Carboniferous coals reach the expulsion threshold at a vitrinite reflectance of 0.85–0.9%R_o or T_max of 440–445 °C.     

Organo-petrographic and geochemical characteristics of Gurha lignite deposits,Rajasthan,India:Insights into the palaeovegetation,palaeoenvironment and hydrocarbon source rock potential

The sedimentary sequence containing lignite deposits in Gurha quarry of the Bikaner-Nagaur Basin(Rajasthan)has been investigated.The samples from lignite and allied shale horizons were evaluated for petrographical,palynological,palynofacies and organic geochemical inferences,to depict the source flora and to reconstruct the palaeodepositional conditions prevailed during the sedimentation.An assessment for the hydrocarbon generation potential of these deposits has also been made.The results revealed the dominance of huminite macerals and phytoclasts organic matter(OM) indicating the existence of forested vegetation in the vicinity of the depositional site.A relatively high terrigenous/aquatic ratio(TAR) and the carbon preference index(CPI) are also suggesting the contribution of higher plants in the peat formation.However,the n-alkane distributions,maximizing at n-C17 and n-C29,showed inputs from the algal communities along with the higher plant derived organic matters.Recovered palynomorphs of the families Onagraceae,Meliaceae,Arecaceae,Rhizophoraceae,Rubiaceae,Ctenolophonaceae, etc.together with oleanene and ursane types of triterpenoids suggest the contribution from angiosperms source vegetation.Interestingly,the presence of Araucareaceae and Podocarpaceae pollen grains shows the existence of gymnosperms vegetation.Further,the presence of tetracyclic diterpanes;demethylated entbeyerane,sandaracopimarane,pimarane,and Kaurane type of compounds confirms the contribution of conifers.The variation in the values of the coefficient of non-equality(H:0.68%-7.56%),the standard deviation(8:0.04%-0.16%) and the coefficient of variability(V:16.10%-46.47%),also shows the heterogeneity in the source organic matter.The various petrographical indices,palynological entities,and geochemical parameters indicate that the peatforming vegetation was accumulated under a mixed environment and fluctuating hydrological settings.The interpretation of palynofacies data on APP(Amorphous organic matter-Phytoclast-Palynomorphs) diagram suggests that the accumulation of organic matter occurred in a dysoxic-suboxic condition in a proximal(to land)setting with the shift to an anoxic condition in distal setting towards the termination of sedimentation.The huminite(ulminite) reflectance(R_r) values(av.0.28%) showed a good relationship with average T_(max) value(414℃),suggesting the immaturity.The TOC content ranges of 13-59 wt.%,and HI values vary between 101 and 546 mg HC/g TOC in the studied samples.Collectively,the studied lignite and shale samples have the admixed kerogens(Type Ⅲ-Ⅱ) and exhibit the ability to generate the gaseous to oil hydrocarbons upon maturation.     

Geochemical evaluation and thermal modeling of the Eocene–Oligocene Pabdeh and Middle Cretaceous Gurpi Formations in the northern part of the Dezful Embayment

Rock–Eval pyrolysis analysis, burial history, and 1D thermal maturity modeling have allowed the evaluation of the source rock potential, thermal maturation state, and impacts of the Pabdeh and Gurpi Formations in Cretaceous–Miocene petroleum system in the Naft Safid (NS) and Zeloi (ZE) oilfields, North Dezful Embayment. The total organic carbon (TOC) content of the Pabdeh and Gurpi Formations ranges from 0.2 to 4.7 wt% and 0.3 to 5.3 wt%, respectively. S2 values of the Pabdeh Formation in the ZE and NS oilfields vary from 0.41 to 13.77 and 0.29 to 14.5 mg HC (Hydrocarbon)/g rock, with an average value of 4.48 and 4.14 mg HC/g rock, respectively. These values for the Gurpi Formation in the ZE and NS oilfields range from 0.31 to 16.96 and 0.26 to 1.44 mg HC/g rock, with an average value of 8.54 and 2.43 mg HC/g rock, respectively. The S2 versus TOC diagram reveals a fair to good hydrocarbon generation potential of the Pabdeh Formation and poor to fair potential of the Gurpi Formation. The high values of S2 (S2 > S1) for samples of the both formations in the ZE and NS oilfields show that the samples are not contaminated with petroleum generated from underlying source rocks. The samples of the Pabdeh Formation in the ZE oilfield are characterized by a relatively narrow range of activation energy values with principal activation energy of 46 kcal/mol and frequency factor of 5.27 × 10⁺¹¹ s^?1. It seems that the high sulfur content of the Pabdeh organic matter probably caused the frequency factor and principal activation energy to be lower than usual. Hydrogen index (HI) values of the Pabdeh and Gurpi Formations in the ZE oilfield vary from 71 to 786 and 97 to 398 mg HC/g TOC, with an average value of 310 and 277 mg HC/g TOC, respectively. These values in the NS oilfield range from 66 to 546 and 51 to 525 mg HC/g TOC, with an average value of 256 and 227 mg HC/g TOC, respectively. Plot of HI vs. T _max value indicates that the majority of the Pabdeh and Gurpi samples contain predominantly type II kerogen and their organofacies are directly related to the more homogeneous precursor materials. Based on thermal maturity modeling results, kinetic parameters, and Rock–Eval analysis, both formations in the ZE and NS oilfields are thermally mature and immature or early mature stage, respectively.     

Properties of thermally metamorphosed coal from Tanjung Enim Area, South Sumatra Basin, Indonesia with special reference to the coalification path of macerals

Thermally metamorphosed Tertiary age coals from Tanjung Enim in South Sumatra Basin have been investigated by means of petrographic, mineralogical and chemical analyses. These coals were influenced by heat from an andesitic igneous intrusion. The original coal outside the metamorphosed zone is characterized by high moisture content (4.13–11.25 wt.%) and volatile matter content (> 40 wt.%, daf), as well as less than 80 wt.% (daf) carbon and low vitrinite reflectance (VR_max = 0.52–0.76%). Those coals are of subbituminous and high volatile bituminous rank. In contrast the thermally metamorphosed coals are of medium-volatile bituminous to meta-anthracite rank and characterized by low moisture content (only < 3 wt.%) and volatile matter content (< 24 wt.%, daf), as well as high carbon content (> 80 wt.%, daf) and vitrinite reflectance (VR_max = 1.87–6.20%). All the studied coals have a low mineral matter content, except for those which are highly metamorphosed, due to the formation of new minerals.The coalification path of each maceral shows that vitrinite, liptinite and inertinite reflectance converge in a transition zone at VR_max of around 1.5%. Significant decrease of volatile matter occurs in the zone between 0.5% and 2.0% VR_max. A sharp bend occurs at VR_max between 2.0% and 2.5%. Above 2.5%, the volatile matter decreases only very slightly. Between VR_r = 0.5% and 2.0%, the carbon content of the coals is ascending drastically. Above 2.5% VR_r, the carbon content becomes relatively stable (around 95 wt.%, daf).Vitrinite is the most abundant maceral in low rank coal (69.6–86.2 vol.%). Liptinite and inertinite are minor constituents. In the high rank coal, the thermally altered vitrinite composes 82.4–93.8 vol.%. Mosaic structures can be recognized as groundmasss and crack fillings. The most common minerals found are carbonates, pyrite or marcasite and clay minerals. The latter consist of kaolinite in low rank coal and illite and rectorite in high rank coal. Change of functional groups with rank increase is reflected most of all by the increase of the ratio of aromatic C–H to aliphatic C–H absorbances based on FTIR analysis. The Oxygen Index values of all studied coals are low (OI < 5 mg CO₂/g TOC) and the high rank coals have a lower Hydrogen Index (< 130 mg HC/g TOC) than the low rank coals (about 300 mg HC/g TOC). T_max increases with maturity (420–440 °C for low rank coals and 475–551 °C for high rank coals).Based on the above data, it was calculated that the temperature of contact metamorphism reached 700–750 °C in the most metamorphosed coal.     

Geochemical Evaluation of the Permian Ecca Shale in Eastern Cape Province,South Africa: Implications for Shale Gas Potential

Shale gas has been the exploration focus for future energy supply in South Africa in recent time. Specifically, the Permian black shales of the Prince Albert, Whitehill, Collingham, Ripon and Fort Brown Formations are considered to be most prospective rocks for shale gas exploration. In this study,outcrop and core samples from the Ecca Group were analyzed to assess their total organic carbon(TOC), organic matter type, thermal maturity and hydrocarbon generation potential. These rocks have TOC ranging from 0.11 to 7.35 wt%. The genetic potential values vary from 0.09 to 0.53 mg HC/g,suggesting poor hydrocarbon generative potential. Most of the samples have Hydrogen Index(HI) values of less than 50 mg HC/g TOC, thus suggesting Type-Ⅳ kerogen. Tmax values range from 318℃ to601℃, perhaps indicating immature to over-maturity of the samples. The vitrinite reflectance values range from 2.22% to 3.93%, indicating over-maturity of samples. Binary plots of HI against Oxygen Index(OI), and HI versus Tmax show that the shales are of Type II and mixed Type Ⅱ-Ⅲ kerogen.Based on the geochemical data, the potential source rocks are inferred as immature to over-matured and having present-day potential to produce gas.     

Source rock potential of the Middle Jurassic to Middle Pliocene,onshore Nile Delta Basin,Egypt

Organic geochemical characterization of cutting samples from the Abu Hammad-1 and Matariya-1 wells elucidates the depositional environment and source rock potential of the Jurassic and Lower Cretaceous successions and the Middle Miocene to Pleistocene section in the southern and eastern Nile Delta Basin. The burial and thermal histories of the Mesozoic and Miocene sections were modeled using 1D basin modeling based on input data from the two wells. This study reveals fair to good gas-prone source rocks within the Upper Jurassic and Lower Cretaceous sections with total organic carbon (TOC) averaging 2.7% and hydrogen index (HI) up to 130 mg HC/g TOC. The pristane/n-C₁₇ versus phytane/n-C₁₈ correlation suggests mixed marine and terrestrial organic matter with predominant marine input. Burial and thermal history modeling reveals low thermal maturity due to low heat flow and thin overburden. These source rocks can generate gas in the western and northern parts of the basin where they are situated at deeper settings. In contrast, the thick Middle Miocene shows fair source rock quality (TOC averaging at 1.4%; HI maximizing at 183 mg HC/g TOC). The quality decreases towards the younger section where terrestrial organic matter is abundant. This section is similar to previously studied intervals in the eastern Nile Delta Basin but differs from equivalents in the central parts where the quality is better. Based on 1D modeling, the thick Middle Miocene source rocks just reached the oil generation stage, but microbial gas, however, is possible.     

Hydrocarbons generation potential of the Jurassic–Lower Cretaceous Formation, Ajeel field, Iraq

Organic geochemical analysis and palynological studies of the organic matters of subsurface Jurassic and Lower Cretaceous Formations for two wells in Ajeel oil field, north Iraq showed evidences for hydrocarbon generation potential especially for the most prolific source rocks Chia Gara and Sargelu Formations. These analyses include age assessment of Upper Jurassic (Tithonian) to Lower Cretaceous (Berriasian) age and Middle Jurassic (Bathonian–Tithonian) age for Chia Gara and Sargelu Formations, respectively, based on assemblages of mainly dinoflagellate cyst constituents. Rock-Eval pyrolysis have indicated high total organic carbon (TOC) content of up to 18.5 wt%, kerogen type II with hydrogen index of up to 415 mg HC/g TOC, petroleum potential of 0.70–55.56 kg hydrocarbon from each ton of rocks and mature organic matter of maximum temperature reached (T_max) range between 430 and 440 °C for Chia Gara Formation, while Sargelu Formation are of TOC up to 16 wt% TOC, Kerogen type II with hydrogen index of 386 mg HC/g TOC, petroleum potential of 1.0–50.90 kg hydrocarbon from each ton of rocks, and mature organic matter of T_max range between 430 and 450 °C. Qualitative studies are done in this study by textural microscopy used in assessing amorphous organic matter for palynofacies type belonging to kerogen type A which contain brazinophyte algae, Tasmanites, and foraminifera test linings, as well as the dinoflagellate cysts and spores, deposited in dysoxic–anoxic environment for Chia Gara Formation and similar organic constituents deposited in distal suboxic–anoxic environment for Sargelu Formation. The palynomorphs are of dark orange and light brown, on the spore species Cyathidites australis, that indicate mature organic matters with thermal alteration index of 2.7–3.0 for the Chia Gara Formation and 2.9–3.1 for the Sargelu Formation by Staplin's scale. These characters have rated the succession as a source rock for very high efficiency for generation and expulsion of oil with ordinate gas that charged mainly oil fields of Baghdad, Dyala (B?aquba), and Salahuddin (Tikrit) Governorates. Oil charge the Cretaceous-Tertiary total petroleum system (TPS) are mainly from Chia Gara Formation, because most oil from Sargelu Formation was prevented passing to this TPS by the regional seal Gotnia Formation. This case study of mainly Chia Gara oil source is confirmed by gas chromatography–mass spectrometry analysis for oil from reservoirs lying stratigraphically above the Chia Gara Formation in Ajeel and Hamrine oil fields, while oil toward the north with no Gotnia seal could be of mainly Sargelu Formation source.     

Organic geochemistry and depositional environment of the Aptian bituminous limestone in the Kale Gümüşhane area (NE-Turkey): An example of lacustrine deposits on the platform carbonate sequence

The Jurassic–Lower Cretaceous aged carbonate sequence is widely exposed in the southern zone of Eastern Pontides. Aptian black bituminous limestone is found in the upper part of this sequence in the Kale area (Gümüşhane). This limestone contains faunal remains (e.g., gastropod, ostracod, characean stems and miliolid type benthic foraminifera) that indicate a freshwater, lacustrine depositional environment.The total organic carbon (TOC) values of the bituminous limestone samples range from 0.11–1.30% with an average TOC value of 0.54%. The hydrogen index (HI) varies from 119–448 mg HC/g TOC (average HI 298 mg HC/g TOC) indicating that the limestone contains gas prone as well as oil prone organic matter. Pyrolysis data prove that the organic matter content in the bituminous limestone consists of Type II kerogen. The average T_max value for bituminous limestone samples is 438 °C (434–448 °C). Bitumen/TOC ratios for bituminous limestone are 0.05 and 0.04. The T_max values and the ratios indicate that the bituminous limestone samples contain early mature to mature organic matter.Analysis of solvent extracts from the two richest bituminous limestones show a predominance of high carbon number (C₂₆–C₃₀) n-alkanes. The Pr/Ph ratio and CPI value are 1.34 and 0.96, respectively. C₂₉ is the dominant sterane, with C₂₉ > C₂₇ > C₂₈. The bituminous limestone samples have low C₂₂/C₂₁ ratios, high C₂₄/C₂₃ tricyclic terpane ratios and very low C₃₁R/C₃₀ hopane ratios (<0.25). These data are consistent with the bituminous limestones being deposited in a lacustrine environment.     

Palynofacies,organic geochemical analyses and hydrocarbon potential of some Upper Jurassic-Lower Cretaceous rocks,the Sabatayn-1 well,Central Yemen

The current work investigates the hydrocarbon potentiality of the upper Jurassic–lower Cretaceous rocks in the Marib-Shabwah Basin, Central Yemen, through the Sabatayn-1 well. Therefore, palynological and organic geochemical analyses were carried out on 37 ditch cutting and 12 core samples from the well. Palynofacies analysis of the Madbi (late Oxfordian–early Tithonian) and Nayfa (Berriasian–Valanginian) Formations sediments indicates deposition of their organic-rich shale, calcareous shale and marl in middle to outer shelf environments under dysoxic–anoxic conditions, containing mainly kerogen of types II to III. However, the shales of the lower Sabatayn (Tithonian) Formation were deposited in an inner shelf environment of prevailing dysoxic–suboxic conditions, and show kerogen types III to II. Regional warm and relatively dry palaeoclimate but with local humid conditions developed near the site of the well is thought to have prevailed during deposition of the studied well sediments. The geochemical analyses of the Madbi Formation show higher total organic carbon content (TOC) than the overlying Sabatayn and Nayfa formations: it is varies between 1.2 and 7, and with average 4 wt% TOC, and the obtained S2 values (～3–10, average 7 mg HC/g rock) indicates that the Madbi Formation is mainly good source rock. It shows a good petroleum potential of 4–11 mg HC/g dry rock, and the Rock-Eval pyrolysis indicates mainly kerogen types II to III (oil to gas prone) of hydrogen index values (132–258, and only one sample from Lam Member is of 360 and average 215 mg HC/g TOC). The thermal maturation parameters as T _max (425–440 °C), production index (average 0.13 mg HC/g rock) and thermal alteration index (2 to 2+) reflected that this formation is present at margin of maturation to early mature stage oil window. So, the Lam Member (upper part) of the Madbi Formation is considered the main hydrocarbon (oil and gas) source rock in the Marib-Shabwah Basin. Accordingly, we predict that the Meem Member is an active source for gas and oil accumulations in the overlying sandstone reservoir of the Sabatayn Formation in the Sabatayn-1 well.     

Natural gas potential of Neoproterozoic and lower Palaeozoic marine shales in the Upper Yangtze Platform,South China: geological and organic geochemical characterization

In this article, we describe the geological features of the Ediacaran (upper Sinian), lower Cambrian and lower Silurian shale intervals in the Upper Yangtze Platform, South China, and report on the gas potential of 53 samples from these major marine shale formations. Reflected light microscopy, total organic carbon (TOC) measurement, Rock-Eval, carbon isotope ratio analysis, thermovaporization gas chromatography (Tvap-GC), and open pyrolysis gas chromatography (open py-GC) were used to characterize the organic matter. Measured TOC in this research is normally >2% and averages 5%. TOC contents are roughly positively correlated with increasing geological age, i.e. lower Silurian shales exhibit generally lower TOC contents than lower Cambrian shales, which in turn commonly have lower TOC contents than Ediacaran shales. Kerogen has evolved to the metagenesis stage, which was demonstrated by the abundant pyrobitumen on microphotographs, the high calculated vitrinite reflectance (R_o = 3%) via bitumen reflectance (R_b), as well as δ¹³ C of gas (methane) inclusions. Pyrolysates from Tvap-GC and open py-GC are quantitatively low and only light hydrocarbons were detected. The lower Silurian shale generally exhibits higher generation of hydrocarbon than the lower Cambrian and Ediacaran shale. Cooles’ method and Claypool’s equations were used to reconstruct the original TOC and Rock-Eval parameters of these overmature samples. Excellent original hydrocarbon generation was revealed in that the original TOC (TOC_o) is between 5% and 23%, and original S1+S2 (S1_o+S2_o) is ranging from 29 to 215 mg HC/g rock.     

Organic geochemical study of Ypresian sediments at Jebel Ousselat,Tunisia

This new study was carried out in order to accurately characterize the geochemical pattern of Ousselat organic-rich facies from the Ypresian basin in central-northern Tunisia. It has been found that the organic matter is located towards the end of diagenesis/beginning of catagenesis. This assumption is supported by the relative low T _max values (429–439°C) and by steranes maturity parameters such as C₂₉ αα 20S/(20S + 20R), and C₂₉ ββ/(ββ + αα). High HI values and the abundance of saturates (1–83%) compared to aromatics (2–27%) are unequivocal evidence of type-II organic matter as indicated by a high abundance of cholestane and the predominance of short-chain n-alkanes centred at n-C₁₈ and at n-C₂₀. Total organic carbon (TOC) content and petroleum potential values suggest that the Ypresian period corresponds to an anoxic event which led to the accumulation and preservation of large quantities of organic matter with high primary production. Due to their geochemical characteristics, the Lower Eocene facies represent a new potential source rocks in central-northern Tunisia.     

Oil-generating coals of the San Juan Basin, New Mexico and Colorado, U.S.A.

Coal beds of the Upper Cretaceous Fruitland Formation in the San Juan Basin of northwestern New Mexico and southwestern Colorado have significant liquid hydrocarbon generation potential as indicated by typical Rock-Eval Hydrogen Indexes in the range of 200–400 mg hydrocarbon/g organic carbon (type II and III organic matter). Small, non-commercial quantities of oil have been produced from the coal beds at several locations. The oils are characterized by high pristane/phytane (ca 4) and pristane/n-C₁₇ ratios (ca 1.2), abundant C₂₁₊ alkanes in the C₁₀₊ fraction with a slight predominance of odd carbon-numbered n-alkanes, abundant branched-chain alkanes in the C₁₅₊ region, and a predominance of methylcyclohexane in the C₄----C₁₀ fraction. The oils are indigenous to the Fruitland Formation coals and probably migrated at thermal maturities corresponding to vitrinite reflectance values in the range 0.7–0.8%. Although the oils found to date are not present in commercial amounts, these findings illustrate the potential of some coals to generate and expel oil under conditions of moderate thermal heating.     

A possible shale gas prospect? First results of the organic composition and thermal maturity of the Carboniferous Namoi Formation,northern NSW,Australia

The Namoi Formation in the Werrie Syncline, north and west of Tamworth, is part of the well-preserved Devonian–Carboniferous fore arc in the New England Fold Belt. The formation is between 640–914 m thick and consists of dominant olive-green mudstones with lenses of sandstone and oolitic limestone. To assess shale gas prospectivity, we analysed five outcrop samples from the Namoi Formation in the Keepit area. Well-preserved aliphatic and aromatic hydrocarbon fractions do not show evidence of weathering or biodegradation. n-Alkanes in all samples have a unimodal distribution maximising at C₂₆ to C₂₈. Little odd-to-even n-alkane carbon number predominance and relatively low Pr/n-C₁₇ and Ph/n-C₁₈ ratios are consistent with a high thermal maturity. Based on the distribution of alkylnaphthalenes and alkylphenanthrenes, the Namoi Formation is in the gas window. Calibration of the methylphenanthrene index and ratio with vitrinite reflectance suggests a calculated reflectance around 2.1%, which given a normal geothermal gradient is equivalent to a maximum temperature of 205°C for the deepest burial of the formation. There is a dominance of parent polycyclic aromatic hydrocarbons (PAH) over alkylated PAHs, supporting a high thermal maturity. Some samples contain biomarkers suggestive of a marine depositional environment, including the C₃₀ sterane index and the C₃₁/C₃₀ hopane ratio. The Namoi Formation is a prospective shale-gas source, as it has been buried sufficiently to be well within the gas window. Where it is exposed at the surface gas will have been lost, but elsewhere it will be buried beneath other sediments and may still retain gas. Key exploration uncertainties include information on organic richness, lateral variation in thermal maturity, mineralogy, and porosity–permeability relationships.     

Evidence of bottom-redox conditions during oceanic anoxic event 2 (OAE2) in Wadi Bazina,Northern Tunisia (Southern Tethyan margin)

Detailed chemostratigraphy across the Cenomanian-Turonian boundary in northern Tunisia points to several prevailing paleoceanographic conditions during the deposition of organic-rich beds of Bahloul Formation. The sedimentological study shows that there is no correlation between color and CaCO₃ content because both dark and light-colored intervals of Bahloul Formation are carbonate-rich. Stable isotope analysis displays a positive carbon isotope excursion characterized by four significant peaks (I to IV) which are ranging from 3.2 to 3.5‰. These peaks represent episodes of elevated rates of organic carbon burial during the C/T oceanic anoxic event (C/T boundary OAE2). The Cenomanian-Turonian boundary could be situated between the third isotopic peak and the filament event. The total organic carbon (TOC) measurements show values ranging from 0.28 to 6.19% with average value of 3.5%. This indicates that the Bahloul Formation shale is a very good oil source rock. The Hydrogen Index (HI) values range from 359 to 698 mg HC/g TOC. The T _max values range from 390 to 438 °C. Binary diagrams HI vs. T _max indicate a type II with values falling within the immature organic-matter range. The concentrations major elements reveal low values of Ti and K. The correlation between Al and Ti and K shows a significant correlation pointing to homogeneous provenance. Primary productivity indicators (Cu, Ba, and Ni) record its association with organic matter. Redox-sensitive elements such as U, V, and Mo and the high values of V/(V + Ni) ratio indicate a strongly reducing environment which led to the better preservation of the organic matter.