Geochemical and Organic Petrological Characteristics of the Bituminous Carbonate Succession (Upper Cretaceous Shu'ayb Formation) in Northern Jordan: Implications for Organic Matter Input and Paleosalinity, Paleoredox, and Paleoclimatic Conditions.

Bituminous carbonate rocks of the Upper Cretaceous Shu'ayb Formation from the Ajloun outcrop in Northern Jordan were geochemically and petrologically analyzed in this study. This study integrates kerogen microscopy results with geochemical results (i.e., biomarker, stable carbon isotope, and major elemental compositions) to understand the organic matter (OM) inputs and to reveal the dispositional setting and its effect on the occurrence of OM. The Shu'ayb bituminous carbonate rocks have high total organic carbon (TOC) and sulfur (S) contents, with average values of 12.3 and 4.59 wt %, respectively, indicating redox conditions during their precipitation. The high abundance of alginite (i.e., lamalginite) in the Shu'ayb bituminous carbonate sediments is a further evidence for redox conditions. The finding of mainly marine-derived OM was also demonstrated by the biomarker distribution and carbon isotope composition. The biomarkers are represented by a narrow Pr/Ph ratio of up to 0.97, abundance of tricyclic terpanes, and high C27 regular sterane, indicating that the OM was primarily derived from phytoplankton algae, along with small amounts of land plant-derived materials, and were accumulated under reducing conditions. The studied Shu'ayb bituminous carbonate facies is composed of mainly calcium (CaO; average, 45.10 wt %), with significant amounts of silicon (Si2O3; avg., 9.35 wt %), aluminum (Al2O3; avg., 6.91 wt %), and phosphorus (P2O3; avg., 1.47 wt %) and low amounts of iron (Fe2O3) and titanium (TiO2) of less than 1 wt %, indicating that the detrital influx was low in an open water depth system with higher primary bioproductivity. The geochemical proxy suggests that the Shu'ayb bituminous carbonate facies was established in a saline water environment, with Ca/Ca + Fe and S/TOC values of more than 0.9 and 0.50, respectively, which could be attributed to the increase in reducing conditions of the water column. The chemical index of alteration values of more than 0.8 also indicate that the Shu'ayb bituminous carbonate facies formed during warm and humid climatic conditions, thereby resulting in intense subaerial weathering.

Molecular Compositions of Oil-Bearing Sandstones and Oil-Asphaltenes from the Kharir Oilfields in the Western Central Masila Basin, Yemen.

Oil-bearing sandstone samples were collected from the Lower Cretaceous sequence in the Kharir-2 exploration well, Kharir oilfields (Eastern Yemen). The current study integrates biomarker of the aliphatic hydrocarbon fraction of the extracted oil with a new finding from the molecular structure of the oil-asphaltene, in order to learn more about their properties, including organic matter (OM) input, depositional environment, and thermal maturity. The overall oil composition results show that the extracted oils have a high saturated hydrocarbon of up to 50% and significant levels of aromatic hydrocarbon and polar components, indicating generally paraffinic to naphthenic oil. This claim agrees with the molecular structure of the kerogen derived from the pyrolysis-gas chromatography result of the oil-asphaltene, which suggests that the extracted oils from the Lower Cretaceous sandstone reservoirs are mainly paraffinic-naphthenic-aromatic oils, exhibiting low wax content and originated from marine type II kerogen. The type II kerogen of the marine-source rock is also demonstrated by the bulk kinetic model of the oil-asphaltene for the extracted oils, with a broad range of Ea between 38 and 62 kcal/mol and a frequency factor (A) of 1.52-1.47 × 1013/1 s. The biomarker characteristics of the aliphatic fraction show that the extracted oils from the Lower Cretaceous sandstone reservoirs were generated from clay-rich source rock, containing OM origin of mainly marine and terrestrial OM input and deposited under suboxic environmental conditions. Furthermore, the maturity-sensitive aliphatic biomarker parameters indicate that the extracted oils were generated from mature source rock in the range of the peak-mature stage of the oil generation window. Oil-source rock correlation of various established biomarker proxies for OM origin, depositional environment, and lithology suggests that these extracted oils were possibly generated from a single source rock, and the Madbi clay-rich formation contributed to most of the extracted oil from the Lower Cretaceous sandstone reservoir rocks.

Geochemistry of Liquid Hydrocarbons and Natural Gases Combined with 1D Basin Modeling of the Oligocene Shale Source Rock System in the Offshore Nile Delta, Egypt.

The current study aims to integrate the geochemical characteristics of the Oligocene shale source rock system, oil, condensate, and natural gas samples in the Oligocene sandstone reservoirs from three exploration wells located in the offshore Nile Delta, East Mediterranean Sea, using organic geochemistry and a 1D basin modeling scheme. The Tineh shales exhibit total organic carbon values ranging between 0.90 and 1.89 wt %, along with hydrogen index values in the range of 54-240 mg hydrocarbon/g rock. The geochemical characterization suggests that the shale intervals of the Oligocene Tineh Formation contain type II-III and type III kerogens and, thereby, could be regarded as promising oil- and gas-prone source rocks with high contributions of gas generation potential. The study also reconstructs the 1D thermal and burial history models, showing that the Oligocene Tineh source rock system is in the main oil and wet gas generation phases from the late Miocene to the present time. The simulated basin models reveal the transformation (TR) of 10-50% kerogen to oil during the late Miocene-early Pliocene period and that the Oligocene Tineh source rock system has larger oil generation and expulsion competency, with a TR value of up to 65% during the early Pliocene-Pleistocene time period. The thermogenic gas was also formed during this time and continued to the present day. This study also investigated the presence of oil and condensate in the Oligocene sandstone reservoir samples and revealed that they were generated from mature source rock, ranging from moderately to highly mature stages. This source rock unit was deposited in fluvial to fluvial-deltaic environments under oxic mixed organic conditions and accumulated during the Tertiary time, as evidenced by the presence of the oleanane biomarker dating indicator. The molecular and isotope compositions of natural gases revealed that most of the natural gases in the Oligocene sandstone reservoir are mainly thermogenic methane gases that were generated from mainly mixed organic matter. The thermogenic methane gases were formed mainly from secondary cracking of oil and gas, with small contributions of primary kerogen cracking. The properties of natural gases together with oil and condensate in the Oligocene reservoir rocks suggest that most of the thermogenic methane gases and associated liquid hydrocarbons are derived primarily from the Oligocene shale source rock system and formed by primary kerogen cracking and secondary oil and oil/gas cracking in different thermal maturity stages. Therefore, the Oligocene Tineh Formation can be regarded as self-source generation and self-reservoir rock; hence, an intensive oil exploration and production program can be recommended whenever the Tineh source rock system is is well developed and deeply buried.

Organic Geochemistry and 1-D Basin Modeling of the Late Triassic Baluti Formation: Implication of Shale Oil Potential in the Kurdistan Region of Iraq.

This investigation looks at the Late Triassic Baluti Formation's organic geochemical, mineralogical, and petrographical characteristics from a single exploration well (TT-22) near the Taq Taq oilfield in northern Iraq. The Baluti Formation shale samples that were studied in the studied well have high total organic carbon (TOC %) values up to 4.92 wt % and mostly hydrogen-rich types I and II kerogen with a minor gradient to types II/III and III kerogen, indicating a good oil-source rock. The hydrogen-rich kerogen was also confirmed by various organic matter (OM) origins and depositional environment-related biomarkers. The biomarker indicators demonstrate that the Baluti shale was deposited under anoxic conditions and contains a variety of OM generated mostly from algae marine and other aqueous organic materials, along with some terrigenous land plants. The geochemical and optical maturity indicators show that most of the examined Baluti shale samples, with a deep burial depth of more than 4000 m, are thermally mature, thus defining peak-mature to late-mature stages of the oil generation window. According to the basin models, from the late Miocene to the present, between 10 and 59% of the kerogen in the Baluti shale source rock has been transformed into oil, which is consistent with the VR values between 0.77 and 1.08%. The presence of the oil crossover in these shale rocks with an oil saturation index of more than 100 mg HC/g rock supports the maximal oil generation from the Baluti source rock system. Additionally, there was little oil expulsion from the Baluti source rock system at the end of the late Miocene, with transformation ratio values below 60% (59%). Considering the more significant oil generation and little expulsion, a high pressure was generated and forced the brittle minerals of the Baluti shales (mainly quartz), creating a natural fracture system as recognized and observed in the thin section. This natural fracture system enhances the porosity system of tight shale rocks of the Baluti Formation, giving rise to a high probability of oil production using hydraulic fracturing stimulation.

Biomarker and isotopic characteristics of Miocene condensates and natural gases, West Delta deep marine concession, Eastern Mediterranean, Egypt.

The Western Delta Deep Marine Concession (WDDM) in the Eastern Mediterranean Sea is one of northern Africa's most recent petroleum-potential regions for gas and condensate exploration. The present study aims to determine the characteristics of the 15 natural gases and 5 associated condensate samples, using molecular compositions and isotopes from the Miocene reservoir rocks in the various wells located in the WDDM. The results of this study are also used to determine the gas-condensate correlation for their probable source rocks as well as the methane-generating mechanisms (i.e., thermogenic or microbiological). Results highlighted in this research reveal that most of the natural gases in WDDM are mainly thermogenic methane gases, with small contributions of biogenic methane gases that were generated from mainly mixed sources, with a high sapropelic organic matter input for biogenic gases. The thermogenic methane gases were formed from secondary oil and oil/gas cracking at the high maturity stage of the gas window. The biogenic gases are also contributed to the Miocene reservoirs, which are formed from the primary cracking of kerogen at low maturity stage by the action of CO2 bacterial reduction. In addition, the saturated and aromatic biomarker results show that the condensate samples were generated from clay-rich source rocks. This source unit of the Miocene condensates were deposited in a fluvial deltaic environmental setting, containing mixed kerogen type II/III and accumulated during the Jurassic-Cretaceous, as evidenced by the age dating indicators. The properties of the natural gases and associated condensates in the Miocene reservoir rocks suggest that most of the thermogenic methane gases, together with the condensate, are derived primarily from mature Jurassic-Cretaceous source rocks and formed by secondary oil and oil/gas cracking at the gas generation window, as demonstrated by the 1-D basin modelling results highlighted in the prior works. Therefore, most of the natural gases in WDDM are non-indigenous and migrated from more mature Jurassic-Cretaceous source rocks in the nearby Northern Sinai provinces or the deeper sequences in the offshore Nile Delta provinces.

Implications of Organic Matter Input, Sedimentary Environmental Conditions, and Gas Generation Potential of the Organic-Rich Shale in the Onshore Jiza-Qamar Basin, Yemen.

The Jiza-Qamar Basin is one of the most important exploration sedimentary basins in Yemen. For over a decade, the exploration of hydrocarbons has been occurring in this basin. Late Cretaceous age rocks are the most occurring organic-rich sediments in this basin, including coals, coaly shales, and shales. The studied organic-rich shale beds are from the Late Cretaceous Mukalla Formation and associated with coal seams. These organic-rich shales can serve as source rocks for hydrocarbon generation potential. The current study investigates the geochemical characteristics, including assessing the organic matter (OM) input, sedimentary environmental conditions, and hydrocarbon generation potential of the organic-rich shale within the Mukalla Formation from three well locations in the onshore Jiza-Qamar Basin using organic geochemistry, biomarker, and carbon isotope measurements. The studied shale samples have high OM content with total organic carbon values between 0.74 and 19.48 wt %. Furthermore, they contain mainly hydrogen-poor Types III and IV kerogen, indicating the presence of the gas-prone source rock. The presence of these types of kerogen indicates the abundance of vitrinite and inertinite macerals, as established by microscopic investigation. However, the studied organic-rich shales had biomarker features, including high Ph/Ph ratio between 3.82 and 7.46, high Tm/Ts ratio of more than 7, and high C29 regular steranes compared to C27 and C28 regular steranes. Apart from the biomarker results, the studied Mukalla shales are characterized by the abundance of land-derived OM that deposited in fluvial to fluvial deltaic environments under highly oxic conditions. The finding of the considerable concentration of terrigenous OM is probably confirmed by the bulk carbon isotope and maceral composition data. The maturity indicators show that the examined organic-rich shale samples in the studied wells exhibit low VR values of up to 0.71%, and thereby, they have not been yet reached the high maturity for gas generation. This low maturity level in the studied wells is probably attributed to shallow burial depth, exhibiting depth of up to 2835 m. Therefore, the substantial gas exploration operations from the organic-rich shale source rock system of the Late Cretaceous Mukalla Formation can be recommended in the deeper stratigraphic succession in the offshore Jiza-Qamar Basin.

Geochemical and Petrological Characterization of the Early Eocene Carbonaceous Shales: Implications for Oil and Gas Exploration in the Barmer Basin, Northwest India.

Carbonaceous shales of the Early Eocene Dharvi/Dunger Formation in the onshore Barmer Basin, northwest India were studied for the first time by integrating geochemical and organic petrological analyses. The carbonaceous shales of the Early Eocene Dharvi/Dunger Formation are characterized by a higher organic carbon content (TOC) of >10 wt % and consist mainly of a mixture of organic matter of types II and III kerogen, with exhibited hydrogen index values ranging between 202 and 292 mg HC/g TOC. The dominance of such kerogen is confirmed by the high amounts of huminite and fluorescent liptinite macerals. Consequently, the carbonaceous shales of the Early Eocene Dharvi/Dunger Formation are promising source rocks for both oil and gas generation potential, with oils of high wax contents, according to pyrolysis-gas chromatography results. The chemical and optical maturity results such as low values huminite/vitrinite reflectance, production index, and T max show that most of the examined carbonaceous shale rocks from the outcrop section of the Kapurdi mine have entered the low maturity stage of oil generation, exhibiting a range of immature to the very early-mature. Therefore, as highlighted in this study, the substantial abundance in hydrocarbon generation potential from these carbonaceous shales in the Dharvi/Dunger Formation may represent future conventional petroleum exploration in the southern part of the Barmer Basin, where the Dharvi/Dunger Formation has reached deeper burial depths.

Geochemical and organic petrographic characteristics of high bituminous shales from Gurha mine in Rajasthan, NW India.

A high bituminous shale horizon from the Gurha mine in the Bikaner sub-basin of the Rajasthan District, NW India, was studied using a collection of geochemical and petrological techniques. This study investigated the nature and environmental conditions of the organic matter and its relation to the unconventional oil-shale resources of the bituminous shale. The analyzed shales have high total organic carbon and total sulfur contents, suggesting that these shale sediments were deposited in a paralic environment under reducing conditions. The dominant presence of organic matter derived from phytoplankton algae suggests warm climatic marine environment, with little connection to freshwater enhancing the growth of algae and other microorganisms. The analyzed bituminous shales have high aquatic-derived alginite organic matters, with low Pr/Ph, Pr/n-C17, and Ph/n-C18 ratios. It is classified as Type II oil-prone kerogen, consistent with high hydrogen index value. Considering the maturity indicators of geochemical Tmax (< 430 °C) and vitrinite reflectance values less than 0.40%VRo, the analyzed bituminous shale sediments are in an immature stage of the oil window. Therefore, the oil-prone kerogen Type II in the analyzed bituminous shales has not been cracked by thermal alteration to release oil; thus, unconventional heating is recommended for commercial oil generation.