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Upper Cretaceous organic-rich carbonate rocks of the Abu Roash F (AR-F) Member represent both source rock and reservoir units and are considered as an unconventional reservoir rock at the Abu Gharadig Field (AGF), Western Desert, Egypt. This study aims to investigate the diagenetic history and its impact on the porosity and permeability of the AR-F unconventional reservoir rock using the sedimentological, petrographic, and petrophysical results for 24 core samples of the AR-F carbonate Member from well AG-121X, located in AGF, Western Desert, Egypt. The petrographic results show that the AR-F Member is composed mainly of mudstone, wackestone/packstone, and packstone microfacies. These microfacies and the richness of such marine assemblages, including planktic forams, calcispheres, pelagic bivalves, echinoderms, with rare pelecypods and ostracods suggest that the AR-F carbonate facies were deposited in mainly deep sea to deep shelf and slope marine settings. The studied AR-F carbonate facies have relatively low total porosity in the range of 0.95–2.33%, which includes mainly grain-based (intergranular and intragranular) and non-grain-based (fenestral, fracture, and dissolution) pores. The core laboratory measurements also show that the AR-F carbonate facies is impermeable rock, with values of up to 0.0039 mD. Therefore, the existence of different types of porosities and permeabilities pointed out that the reservoir quality of the AR-F carbonate facies at the AGF ranges from poor to very poor quality. This could be attributed to different stages of diagenesis, including eogenesis and mesogenesis. These deformation stages, on one hand, contributed to reducing and destroying the reservoir porosity and permeability by a series of processes like micritization, cementation, mechanical and chemical compaction, and less pronouncing pyritization and kaolinitic precipitation. On the other hand, dissolution and fracturing enhanced, in a limited way, the porosity. According to the findings of this study, the AR-F carbonate succession is suitable for further exploitation as an unconventional tight resource of oil reservoir potential. [ABSTRACT FROM AUTHOR]

Organic-rich shale rocks from the Paleocene–Eocene Palana Formation in western Rajasthan, India, were systematically investigated based on inorganic and organic geochemistry combined with microscopic examinations to evaluate the sedimentary paleoenvironmental conditions and volcanic activity and their impact on the high organic carbon accumulation. The Palana shales are categorized by high organic matter (OM) and sulfur contents, with total values up to 36.23 wt.% and 2.24 wt.%, respectively. The richness of phytoplankton algae (i.e., telalginite and lamalginite) together with redox-sensitive trace elements further suggests a marine setting and anoxic environmental conditions during the Paleocene–Eocene. The significant low oxygen conditions may contribute to enhancing the preservation of organic matter during deposition. The mineralogical and inorganic geochemical indicators demonstrate that the Palana organic-rich shale facies was accumulated in a warm and humid climate with moderate salinity stratification conditions in the water columns, thereby contributing to the high bioproductivity of the phytoplankton algae blooms within the photic zone. The presence of significant contents of zeolite derived from volcanic material together with silica minerals such as apophyllite and tridymite in most of the Palana organic-rich shales indicates a volcanic origin and supports hydrothermal activities during the Paleocene–Eocene period. These volcanic activities in this case are considered the influx of large masses of nutrients into the photic zone due to the ash accumulation, as indicated by the presence of the zeolites in the Palana shales. Therefore, the high bio-productivity associated with effective OM preservation led to the organic carbon accumulation in the Palana Formation during the Paleocene–Eocene. [ABSTRACT FROM AUTHOR]

Organic‐rich shale samples of the Late Cretaceous Mukalla Formation from the Al‐Fatk1 well in the offshore Jiza‐Qamar Basin, eastern Yemen, were examined using bulk organic geochemistry, microscopic examination, and biomarker measurements combined with 1‐D basin modelling, to evaluate the organic matter characteristics and their ability to generate gas. The studied Mukalla shale samples are characterized by their high organic matter content with total values of up to 14.50 wt.%, and contain mainly hydrogen‐poor Type III kerogen, indicating elevated gas generation potential. The hydrogen‐poor kerogen was also demonstrated by biomarker measurements combined with an abundance of land‐derived organic matter (i.e., vitrinite and inertinite) as established by microscopic investigation. The biomarkers of the studied organic‐rich shales were characterized by a high Pr/Ph ratio, abundance of C29 regular steranes, high C27 17α (H)‐22, 29, 30‐trisnorhopane compared with C27 18α (H)‐22, 29, 30‐trisnorneohopane, all providing evidence for the organic matter being derived primarily from higher land plant organic matter, deposited in fluvial deltaic environments under highly oxic conditions. The bulk carbon isotope data agree with the findings of terrigenous organic matter. The maturity indicators show that the examined organic‐rich shale samples have entered the main oil stage and are at the beginning of wet gas generation windows, exhibiting vitrinite reflectance values that range between 0.73% and 1.20%. Kerogen to gas conversion has been simulated by the basin models and shows that between 10% and 15% of kerogen has transformed into gas during the late Miocene until the present‐day, consistent with the wet gas generation window (1.00–1.20 %Ro). Substantial gas exploration potential may exist in the fluvial deltaic Mukalla source rock system in the deeper structural units of the Qamar‐Jiza Basin, where the Mukalla Formation has reached the high maturity level of the gas generation window. [ABSTRACT FROM AUTHOR]

This study examines the geochemical and petrological characteristics of 16 carbonate-rich (i.e., chalky marl, chalky limestone, and limestone) samples of the Upper Cretaceous Shu'ayb Formation in the Ajloun region, northern Jordan, to decipher the organic matter characteristics and predict the geological temperatures for oil generation. The carbonate-rich sediments under investigation exhibit high TOC (up to 12.39 wt%) and high hydrogen index (314–920 mg HC/g TOC), indicating Types I-II kerogens. The dominance of such hydrogen-rich kerogen is confirmed by the fluorescent alginite, amorphous organic matter (AOM), and bituminite organic matter. The studied organic facies are sulfur-rich and comprise of Type II organic matter, exhibiting the possibility of producing paraffinic oil with a low wax component, according to pyrolysis–gas chromatography. The broad distributions of activation energy (37–66 kcal/mol) in the bulk kinetic model of the analyzed samples show a mixture of organic matter (i.e., mainly marine-derived organic matter and minor land plant input). The kinetic models suggest that bulk petroleum formation began at relatively low geological temperatures between 104 and 116 °C, which corresponds to a vitrinite reflectance range of 0.58–0.66%. These activation energy distributions and low anticipated vitrinite reflectance values are largely compatible with the Type II-S kerogen organic facies, suggesting that the investigated Upper Cretaceous organic-rich carbonate may have produced sulfur-rich oils during the initial phases of kerogen conversion. [ABSTRACT FROM AUTHOR]

Five core sandstone and carbonate rock samples from the Cretaceous Harshiyat Formation containing oil stains were collected from two wells in the North Hadramaut High area (eastern Yemen) and geochemically analyzed by their sterane and terpane biomarker and stable carbon isotope (δ13C) compositions. This paper studied the geochemical characteristics of the oil stains and their relation to probable potential source rocks. The source rock characteristics include the origin of organic matter input; redox depositional conditions, lithology, and degree of thermal maturity were investigated. The saturated and aromatic hydrocarbon fractions of the analyzed oil stain samples have δ13C values in the range of − 26.5‰ – − 28.6‰ and − 26.3‰ – − 26.7‰, respectively. These δ13C values indicate that the oil stain samples originated from a mixed organic matter input in their source rock. The presence of mixed marine and terrestrial organic matter in the source rock is further concluded from biomarker distributions of n-alkane, isoprenoid, terpane, and sterane. These biomarkers and their ratio parameters suggest that the analyzed oil stain samples were sourced from clay-rich rock deposited in marine-reducing environmental conditions and likely contained mixed planktonic/bacterial organic matter and land plant inputs. Both saturated and aromatic maturity biomarkers suggest that the analyzed oil stains were from a mature source rock, equivalent to a moderate to peak-mature oil window. The environmental biomarker indicators of the studied oil stain samples correlated well with the shales in the Late Cretaceous Harshiyat Formation in the onshore Jiza-Qamar Basin (eastern Yemen), indicating that the analyzed oil stains were generated from a mature Harshiyat source rock in the onshore Jiza-Qamar Basin and subsequently migrated into the Cretaceous Harshiyat sandstone and limestone reservoirs in the North Hadramaut High area (eastern Yemen) through normal faults system. [ABSTRACT FROM AUTHOR]

This comprehensive study investigates the organic matter characteristics within the Late Cretaceous Rakopi and Taniwha formations, based on data from four exploration wells situated in New Zealand's Taranaki Basin. It employs a multifaceted approach, integrating bulk geochemical analyses, biomarker measurements and carbon isotopes to unveil the geological history of these formations. Analytical results include total organic carbon content, ranging from 7.27 to 75.78 wt%, and generation potentials spanning from 28.24 to 309.16 mg hydrocarbon/g rock. These observations underscore the source rock potential of these Late Cretaceous strata. These rocks show a mixed organic matter of hydrogen‐rich Type II and Type II/III kerogens, as evidenced by hydrogen index values (HI) between 237 to 428 mg hydrocarbon/g rock. These formations demonstrate promise potential for both oil and gas generation. Biomarker analysis uncovers distinct signatures, featuring a pristane/phytane (Pr/Ph) ratio ranging from 3.27 to 10.91, a Tm/Ts ratio surpassing 7 and elevated concentrations of C29 regular steranes relative to C27 and C28 regular steranes. These biomarker characteristics suggest a composite organic matter composition, influenced by terrigenous organic matter, likely deposited in oxygenated fluvial deltaic environments. Bulk carbon isotopic data corroborate these findings, highlighting the abundance of terrigenous organic matter. Collectively, these insights reveal that the coal and carbonaceous shale intervals in the examined wells are in the early stages of oil generation. Therefore, the Rakopi and Taniwha formations have not yet yielded commercially viable oil and/or gas quantities. In this case, these formations hold substantial promise for future exploration activities in relatively deep wells, with limited oil expulsion from coals. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Bituminous lime mudstone from the Late Tithonian--Early Barremian Naifa Formation was collected from five wells in the Shabwah depression of the southeastern Sabatayn Basin for basic organic geochemical analyses. The collected samples’ nannofossil contents were also studied. The current study preliminarily evaluated the nature of the organic matter regarding the richness and type of organic facies and their relation to oil generation potential. Most of the lime mudstone samples are organically rich and include favorable source rocks, as indicated by the high TOC content of up to 1 wt%. The presence of the warm-water index nannofossil taxa Watznaueria barnesae suggests warm climate conditions, thereby contributing to high bioproductivity that consequently enhanced organic richness. The samples are also hydrogen rich, with HI values between 302 and 740 mg HC/g TOC, resulting in two dominant organic facies of kerogen Types I and II, and are consistent with high bioproductivity of phytoplankton algae in warm-water conditions during deposition. Both geochemical maturity values Tmax and PI indicate that the bituminous lime mudstones are at different thermal maturity levels and range from immature to early mature stages of the oil generation window. This implies that the bituminous lime mudstones were not buried to a sufficient depth for commercial oil generation. Therefore, further exploration efforts in deeper parts of the Shabwah depression, particularly in the area around well Misah-01, are recommended. [ABSTRACT FROM AUTHOR]

Twenty-five cutting shale and coal samples from the Mid-Late Cretaceous Mukalla and Harshiyat formations in the Mintaq-01 well, Wadi Hajar of Southern Sabatayn Basin were investigated using organic geochemical methods. The geochemical results indicate that the analyzed shale and coal samples are fair to excellent source rocks, with TOC values between 0.50 and 53.13%. The analyzed samples also have Rock-Eval HI between 99 and 676 mg HC/g TOC, indicating types I/II and II/III kerogen and thus are oil and gas-prone source rocks. However, these Mid-Late Cretaceous sediments of the Wadi Hajar are still in an immature to very early mature stage, and they have not yet generated oil or gas. [ABSTRACT FROM AUTHOR]

The early Cretaceous Saar Formation includes potential petroleum-bearing source rocks in the onshore Masila Basin, eastern Yemen. The organic matter input, depositional environment conditions and petroleum generation potential from the Saar Formation shales were investigated using geochemical and organic petrological methods. The shales of the Saar Formation contain total organic carbon of 0.5–3.5 wt percent. The geochemical analysis of the organic matter indicated that these shales have fair to very good hydrocarbon source potential. The kerogen of the organic matter is dominated by Type II/III and Type III, referring to both oil- and gas-prone source rocks. The biomarker and bulk carbon isotope analyses of the organic matter suggested that the kerogens were constituted from a combination of marine and high land plant organic matter, and were preserved under suboxic depositional conditions. The geochemical and petrographic analyses of the shales (e.g., vitrinite reflectance (VRo), pyrolysis Tmax and biomarker maturity ratios) lead to the conclusion that the shales are generally immature to very early mature, particularly in shallower locations where the thermal alteration level of the organic matter is not strong enough to generate petroleum. Therefore, this work suggests that the mature source shale intervals of the Saar Formation existed in the deeper parts of the basin could reach a good maturity level that can produce potential hydrocarbons. Prediction of the potential migration pathways for hydrocarbons produced by deep shales could significantly aid in the future of petroleum exploration in the Masila Basin of Eastern Yemen. • Saar shale Formation in the onshore Masila Basin was analyzed. • The shales of Saar Formation are fair to very good source rock generation potential. • The shales are both oil- and gas-prone source rocks. • The shales are generally immature to very early-mature. [ABSTRACT FROM AUTHOR]

The Late Jurassic Meem Shale Member is widely exposed within the Sabatayn Basin, including in the Al-Jawf sub-basin. In this study, a total of 49 shale samples of the Meem Shale Member from two exploratory wells; Dahmar Ali−01 (28 samples in the depth range 1441–2351 m) and Kamaran-01 (21 samples in the depth range 2275–3011 m) in the south-eastern portion of the Al-Jawf sub-basin were studied as possible source rocks. Evaluation of source rock geochemistry including total organic matter (TOC) and Rock-Eval pyrolysis analyses was performed. The results of this study provided information regarding significant exploration of oil and gas resources from the Meem Shale Member in the Al-Jawf sub-basin. Both the incident light microscopic results and the Rock-Eval geochemical study have indicated that the analyzed shale samples contain predominantly Type III kerogen with minor contributions of Type I/II and IV, so as to they can generate both oil and gas. The values of hydrogen index (HI) are decreased with increasing thermal maturity and varied between 34 and 803 mg HC/g TOC. Based on the measured VRo% range of 0.63 and 2.00, the Meem shales are currently within the oil- and gas-generation window, thus, they are considered as shale-oil and -gas resource possible plays. The geochemical results were integrated with geological data of the Al-Jawf sub-basin and incorporated into a basin model to simulate petroleum generation and/or retention in the Meem Shale Member. The constructed basin models illustrated that the Meem Shale Member displayed a peak oil generation window during the Late Jurassic to Early Miocene, where large amounts of oil were generated, with a conversion ratio of 10–75 TR%. Further, the high heating rates from local volcanic rocks from the Early Miocene till date have caused gas generation from both of the original Type III kerogen and from secondary cracking of retained oil in the Meem Shale Member. However, the main contribution of gas generation within the Meem Shale Member came from secondary cracking processes through geologic time. The good thickness (736–910 m) of the organically-rich, high genetic potential and matured Meem Shale Member is expected to provide large amounts of oil and gas within the south-eastern portion of Al-Jawf sub-basin. Therefore, the Al-Jawf sub-basin can be considered as a rich oil and gas exploration province. • Meem shales samples from two wells in the South-eastern Al-Jawf sub-basin were analyzed. • The Meem shales contain Types I/II and III/V kerogen. • The shales are currently at oil and gas-window and large amounts of oil had generated during Late Jurassic to early Miocene. • The mass gas-generation was formed by primary and secondary cracking at high maturity during early Miocene. [ABSTRACT FROM AUTHOR]

Physical and geochemical properties were performed on three crude oils from Alif-01 well in the Marib sub-basin. The analyzed samples comprise medium specific gravity (37° API), reflecting mature source rocks. The thermal maturity of the analyzed oils is also indicated from the high content of aliphatic hydrocarbons (HC). The compositions of HC further suggest that analyzed oils belong to paraffinic oils. The n-alkane and isoprenoid distributions reveal that the analyzed oils are derived from marine source rock, containing mixed organic matter, with some terrestrial input and deposited under relatively reducing conditions. The features of the analyzed oils are consistent with the Madbi source rock characteristics in the basin. [ABSTRACT FROM AUTHOR]

Late Jurassic Safer shales in the Al-Jawf sub-basin are analyzed to evaluate the organic matter input, depositional conditions and petroleum generation potential. The shales have high organic matter, with TOC values of 1.0-13.5% and they contain predominantly Types II and III kerogen, referring to mainly oil- and gas-prone. These kerogens are indicative for dominate marine algal component and some terrestrial organic matter input as indicated from biomarkers. Moreover, the presence of the gammacerane also confirmed a high salinity stratification condition and suggests that the dominate Type II kerogen is rich-sulphur kerogen (Type II-S). The vitrinite reflectance (VRo%) and Rock-Eval pyrolysis Tmax data indicate that the analyzed shales are immature. [ABSTRACT FROM AUTHOR]

Two oil seep samples were collected from outcropping Jurassic Ayad Salt Dome of Shabwah depression. The results of this study have been used to provide information of the origin of the oil seeps and the type of organic matter and maturity of their potential source rock in the basin. Although these are surface oil seeps, their high saturated hydrocarbon content indicates that they are non-degraded oils, probably due to an arid environment of the thick salt sediments. The analyzed oil seep samples are characterized by full complement of n-alkanes, a very high component of phytane, relatively low CPIs of less than unity, and an unusually high content of aliphatic HCs. These features suggest that the analyzed oil seeps are generated from an algal marine organic matter in the source rock that deposited under highly anoxic hypersaline conditions and indicate a moderately low level of maturity. The geochemical characteristics of the analyzed oil seeps in this study are similar and consistent with the source rock characteristics of the Safer Member in the Sabatayn Basin. [ABSTRACT FROM AUTHOR]

Abstract This study is a part of the source rock geochemistry project in the onshore Sabatyen Basin, Yemen. The results of this study were used to improve our understanding of the petroleum resource potential of Al-Jawf sub-basin in the north-western part of the Sabatyen Basin. The shale samples of the Late Jurassic Arwa Member from two wells (Khyawan-01 and Himyar-01) were analyzed to evaluate the characterises of the organic richness, kerogen type, thermal maturity and petroleum generation potential in Al-Jawf sub-basin based on a compilation of geochemical and petrological data. The biomarker and stable isotope results were subsequently used to evaluate the organic source input and sedimentary environmental conditions during deposition of the Late Jurassic Arwa Member shales. The Arwa shales contain low to high organic matter, with variable TOC% values between 0.58 and 6.41, indicating fair to very good source rock generative potential. The Rock-Eval HI data are ranging from 73 to 816 mg HC/g TOC and display mainly Type III and II/III kerogens with a minor contribution of Types I/II kerogen, consistent with both oil and gas source rocks. The biological sources are predominately sapropelic organic matter, with significant contribution of higher plants input in the Arwa member shales as indicated from biomarkers and carbon isotope data and petrology study. The biomarker ratios of relatively low Pr/Ph, Pr/ n -C 17 and Ph/ n -C 18 values and relatively high values of HC 34 /HC 35 indicate suboxic environmental conditions during deposition of the Arwa Member shales. The analyzed Arwa shale samples have temperatures of maximum pyrolysis yield (T max) in the range of 417–457 °C and vitrinite reflectance between 0.30 and 0.56 %Ro, consistent with immature to early-mature source rocks. It is interesting to know that the Arwa shale samples with high contents of TOC% (>1), HI (>300 mg HC/g TOC) and high thickness of more than 1000 m indicate that the Late Jurassic Arwa Member hold significant exploration potential for oil in the deeper locations. Therefore, the hydrocarbon exploration processes should be focused on the known deeper location of the Arwa Member for predicting the mature source rock. Highlights • Arwa shales were classified as fair to good potential source rocks in Al-Jawf sub-basin. • The Arwa shales contain mixed organic matter and deposited under suboxic conditions. • The Arwa shales are considered to be both oil and gas source rocks. • The Arwa shales are still at immature to early-mature stages for oil-generation in the studied wells. [ABSTRACT FROM AUTHOR]

In this study, bituminous shale samples were collected from Late Jurassic sedimentary section in the Marib oilfields to study their petrologic and organic geochemical properties. The results of this study indicate that the Late Jurassic bituminous shales can be considered as an oil-source rocks in the Sabatayn Basin (NW Yemen). The analyzed Late Jurassic shales have high organic matter (TOC up to 10%) content of kerogen Types I/II. These kerogen types in the analyzed samples are consistent with the high dominance of alginite and amorphous organic matter. Open pyrolysis–gas chromatography results are generally consistent with the Rock-Eval results and further indicate that the analyzed shale samples contain Types I/II and II-S kerogen and generally can produce paraffinic oils with low to high wax content. Type II-S kerogen can produce oil with high sulphur content at low maturity level. The maturity data reflect immature and very early maturity stages of petroleum formation of the Late Jurassic bituminous shales. Therefore, the kerogen types in the Late Jurassic bituminous shales has not been altered by thermal maturity for oil generation, thus, artificial heating is required of kerogen cracking generate significant oil. [ABSTRACT FROM AUTHOR]

Abstract The Mukalla Formation is one of the important petroleum source rocks in the Jiza-Qamar Basin, Eastern Yemen. In this study, coal, coaly shale and shale samples from three wells (Al-Fatak-1, 16/G-1 and 16/E-1) in the offshore Jiza-Qamar Basin were studied. The organic matter richness, kerogen type, thermal maturity, and petroleum generation potential of the Mukalla organic-rich samples were investigated. The analysed Mukalla source rock samples are potentially rich in organic matter of 1.01–84.40% TOC, ranging from good to excellent source rocks. The Mukalla source rocks primarily contain Types II, II–III and III kerogen, anticipating generating mainly oil and gas. This is generally consistent with the pyrolysis–gas chromatography results and further indicates that the Mukalla source rocks can produce high wax oil and condensate/gas. The thermal maturity parameters reveal the Mukalla source rocks are in mature to late-mature and are capable of generating oil and wet gas at the present time. In addition, this study was integrated the geochemical, geo-thermal and geological data in term of basin modeling study to simulate the timing of hydrocarbon generation and expulsion from the Mukalla deltaic source rocks. The basin model results indicate that the oil generation commenced during the late Eocene to late Oligocene, with a conversion ratio of 10–50 TR%. Furthermore, based on TRs of more than 50%, the most of oil was expelled along the micro-fracturing of the Mukalla source rocks and then trapped in the Mukalla Formation itself during the latest Oligocene and continued to present-day. Highlights • The Mukalla Formation in the offshore Jiza-Qamar Basin is considered as a deltaic source rock. • Basin models were constructed from three wells in the offshore Jiza-Qamar Basin. • Mukalla source rocks reached the late oil-window in the present-day. • The oil was generated during late Eocene to late Oligocene, with a conversion ratio of 10–50%. • The oil was then expelled along the micro-fracturing of the Mukalla source rocks. [ABSTRACT FROM AUTHOR]

Integrated petrophysical and petrographic analyses were performed on the Kuhlan clastic rocks to evaluate the petrophysical reservoir properties, identify grain sorting along with the clay type and mineral volumes using well logs coupled with core data. Core samples were collected from two key wells and their results were used to determine the reservoir properties and bulk mineralogical composition and, additionally, to calibrate the well log results from three un-cored to the two cored wells. The Kuhlan clastic reservoir rocks have porosity values between 6% and 12%. These porosity values are mainly intergranular primary and secondary porosity. Permeability is likewise variable with values in the range of 78–304 mD. The Kuhlan reservoir rocks also have high hydrocarbon saturation exceeding 70%, with relatively high movable oil. These reservoir properties are achieved from log-derived and core porosity and permeability results. The lithology and mineral composition of the well logs and petrographic studies in this study indicate that the Kuhlan sandstone can be considered as an alternative reservoir rock in the basin. The Kuhlan Formation is primarily composed of sandstone that contains quartz, feldspar (i.e., orthoclase, plagioclase (albite) minerals and illite, and calcite cements. The quartz mineral is dominant followed by feldspar as the second most abundant mineral in this formation. The Kuhlan Formation sandstones are classified (based on standard rock classification schemes) into arkose, sub-arkose and feldspathic lithofacies. The results of petrographic analysis also indicate a continental block transitional source of the Kuhlan Formation sandstones. Petrographically, the Kuhlan sandstones are poorly sorted and range from fine to coarse-grained and contain high percentages of detrital quartz and feldspar-rich grains with a significant amount of rock fragments. The Kuhlan sandstones also contain a variable range of matrix and cement contents. Based on the results of this study, the reservoir quality of the Kuhlan sandstone ranges between good to poor reservoir quality. The Kuhlan Formation has arkosic and sub-arkosic sandstones that result in a good reservoir quality with a significant increase of the permeability and intergranular porosity. This is attributed to the coarse-grained texture, high percentages of detrital quartz, slightly well sorted texture and the low degree of matrix and cements. In contrast, the Kuhlan Formation feldspathic sandstone has poor reservoir quality due to the poor sorting texture, pore space occluding clayey groundmass, and carbonate cement. [ABSTRACT FROM AUTHOR]

In this study, four exploratory wells from the Mukalla-Sayhut Basin, Gulf of Aden are used for basin modeling study in order to simulate the petroleum generation and expulsion history of the Umm Er Radhuma Formation. The basin models illustrate that the Gulf of Aden is an extensional rift basin and initially developed during Oligocene as indicated by paleo-heat flow values. The heat flow reached peak heat-flow values of approximately 120–160 mW/m 2 at Early to Middle Oligocene time. This high paleo-heat flow had a considerable effect on the Paleocene Umm Er Radhuma source rock and cooking of the organic matter. The basin models also indicate that the Umm Er Radhuma Formation source rock had passed the peak-oil generation window during the late Oligocene (Chattian) age. Onset of oil-generation began during late Rupelian age (∼29 Ma), whereas the main oil was generated during the Chattian age (27-24 Ma). The models also show that the petroleum was expelled from the Umm Er Radhuma source rock since latest Oligocene (late Chattian, < 24Ma) time, with transformation ratio of more than 50%. These basin models suggest that the Umm Er Radhuma Formation is an effective source rock where significant amount of petroleum is expected to be generated and expelled to any nearby potential reservoir rocks within the Mukalla-Sayhut Basin. [ABSTRACT FROM AUTHOR]

The Miocene Salif Formation is an oil-source rock within the Tihamah Basin, southern Red Sea of Yemen. The Salif shale beds are characterized by high organic carbon content (TOC) up to 5.59% and high oil saturation index (OSI) (30 < OSI <260 mg HC/g TOC). However, most of the Salif shale samples exhibit OSI values of >100 mg HC/g TOC, indicating a thermally mature and oil-saturated source rock system with high oil-bearing potential. This finding is supported by the vitrinite reflectance values, representing mature oil generation window. Therefore, the shale oil potential of the Salif source rock system is studied for the first time by integrating geochemical data and geological information into a 1-D modelling scheme. The models reconstructed for the thermal and burial history infers that the Salif source rock system is located within the late oil-window from the Late Pliocene to present-day. Kerogen to oil conversion and the timing of petroleum generation and expulsion are also simulated by the 1-D models, showing that 10–50% of the total kerogen is converted into oil during the early Pliocene to the Pleistocene, which is consistent with the peak-late mature oil-window (0.70–1.26 %Ro). The models also exhibited that limited oil was expelled from the Salif source rock system since the Pleistocene-present-day as demonstrated by the TR ratio of up to 55%. The integration of source rock evaluation and modeling approach concludes that the Salif source rock provides a good potential for possible oil production, where suitable reservoir characteristics do occur. • Miocene Salif Formation is a main oil-source rock in the Tihamah Basin. • Salif source rock is currently at a peak to late mature of oil window. • Salif source rock system has a good oil-bearing capacity, with oil saturation index of >100 mg HC/g TOC. • Kerogen was converted into oil with TR ratio between 10% and 55% during the late Miocene until the present-day. [ABSTRACT FROM AUTHOR]

Understanding reservoir, source, seal, migration pathways and trap characterization is the first step towards better energy resource exploitation. Several studies have been conducted in recent decades on the reservoir characteristics of conventional resources. Unconventional resources, on the other hand, have received more attention as alternative future energy solutions to depleted conventional resources. Drilling, exploration, development, and production of conventional and unconventional resources pose technical challenges to the energy industry. This special issue attempts to address the most pressing technical challenges in developing conventional reservoirs (such as sandstone and carbonate reservoirs) as well as unconventional energy sources (e.g., shale gas, shale oil, tight gas sand, coal bed methane, geothermal and gas hydrates). The special issue is composed of 21 papers that are classified into six different groups related to the physical and mechanical properties of reservoirs, petroleum geochemistry, petroleum geology, geological modelling, unconventional resource evaluation and conventional reservoir evaluation. [ABSTRACT FROM AUTHOR]

A conventional organic geochemical study has been performed on the shale samples collected from the early Cretaceous Saar Formation from the Shabwah oilfields in the Sabatayn Basin, Western Yemen. The results of this study were used to preliminary evaluate the potential source-rock of the shales in the Saar Formation. Organic matter richness, type, and petroleum generation potential of the analysed shales were assessed. Total organic carbon content and Rock- Eval pyrolysis results indicate that the shale intervals within the early Cretaceous Saar Formation have a wide variation in source rock generative potential and quality. The analysed shale samples have TOC content in the range of 0.50 and 5.12 wt% and generally can be considered as fair to good source rocks. The geochemical results of this study also indicate that the analysed shales in the Saar Formation are both oil- and gas-prone source rocks, containing Type II kerogen and mixed Types II-III gradient to Type III kerogen. This is consistent with Hydrogen Index (HI) values between 66 and 552 mg HC/g TOC. The temperature-sensitive parameters such as vitrinite reflectance (%VRo), Rock-Eval pyrolysis T max and PI reveal that the analysed shale samples are generally immature to early-mature for oil-window. Therefore, the organic matter has not been altered by thermal maturity thus petroleum has not yet generated. Therefore, exploration strategies should focus on the known deeper location of the Saar Formation in the Shabwah-sub-basin for predicting the kitchen area. [ABSTRACT FROM AUTHOR]

In this study, oil shale samples were collected from Late Cretaceous Muwaqaar Chalk Marl Formation (MCM) in Jordan to study their petrologic and organic geochemical properties. Pyrolysis and bulk kinetic techniques were performed on the Late Cretaceous oil shales. The results of this study were used to characterize the different organofacie types in the Late Cretaceous oil shales and their effect on the petroleum type generated during thermal maturation and the temperature of petroleum generation. On the basis of the geochemical results, the analysed Late Cretaceous oil shales contain predominantly Type II and rarely Type I kerogens. These kerogens are consistent with the high dominate of sapropel organic matter (i.e., alginite and amorphous organic matter). A good correlation is noted between increasing abundance of organic matter and the kerogen type that was derived from an open pyrolysis–gas chromatography (Py–GC). The Py–GC data indicate the analysed oil shale samples contain heterogeneous organic matter of the kerogen Type II-S. It is interesting to know that this sulphur-rich kerogen (Type II-S) can generate high sulphur oils at low maturity ranges. This is consistent with the predicted temperature petroleum generation from bulk kinetic models. The bulk kinetic models in this study indicate that the main phase of petroleum formation from the thermally immature Late Cretaceous oil shales occur between 122 and 148 °C. These temperature values of the petroleum generation are generally consistent with the kerogen type II-S and further indicate that the analysed oil shale samples can generate sulfur-rich oils at early stage of kerogen cracking. [ABSTRACT FROM AUTHOR]

Middle Jurassic Sargelu Formation is an important oil-source rock in the Iraqi Kurdistan oilfields, northern Zagros Fold Belt. The Sargelu source rock is characterised by high organic matter and sulphur content with Type II-S kerogen, which can be expected to generate oil at low maturity stages. A 1D basin modelling was performed by integrating geological and geochemical data of the Sargelu source rock from six wells in the Kurdistan region, north Iraq. The basin modelling results was used to reconstruct the burial and thermal history and to simulate and predict the timing of petroleum generation and expulsion for the Middle Jurassic Sargelu source rock. Burial/thermal history models indicate that the Sargelu source rock had passed the peak-oil generation window during the Late Eocene to Late Miocene. Onset of oil-generation began during the Middle Eocene - Late Miocene (51-11 Ma), whereas the maximum rates of oil with limited gas were generated during the Late Eocene to Late Miocene (52-10 Ma). The models also show that the oil was expelled from the Sargelu source rock since Late Eocene to present-day (44-0 Ma), with transformation ratio higher than 50%. The subsequent high transformation ratio higher than 80% suggests that the generated oil was cracked to gas during the Early Oligocene and continued to present day. These basin modeling results also suggest that the Sargelu Formation acts as an effective oil-source where significant amount of petroleum is expected to be generated and expelled to any nearby prospect reservoir rocks in the Kurdistan region. [ABSTRACT FROM AUTHOR]

• Overall, Abu Roash (F) carbonate rocks indicate organic matter richness capable of oil generating. • Abu Roash (F) carbonates are currently dominated by high HI values of <300 mg HC/ g TOC and entering the oil-window maturity. • Abu Roash (F) carbonate-rich rocks in the deepest burial depth reached a TR ratio between 10 and 55%, indicating a high probability of oil production. • Abu Roash (F) carbonates have low porosities and poor permeability, requiring a hydraulic fracturing for commercial oil production. This paper systematically analyzes the organic geochemical, petrophysical, and petrographical properties combined with bulk kinetics modeling of the Abu Roash (F) organic-rich carbonate rocks in the Abu El Gharadig Field. The Abu Roash (F) carbonate-rich samples exhibit high organic content with total organic matter (TOC) values up to 3.04 wt%, and mainly Type II kerogen, with a slight gradient to Type II/III and III kerogens, reaching good to very good oil generation potential. This finding of hydrogen-rich kerogen and oil generation potential was also demonstrated by the abundance of fluorescent alginite, amorphous organic matter (AOM), and bituminite organic matter (OM) as established via ultra violet (UV) light microscopy. The maturity indicators demonstrate that most of the examined Abu Roash (F) carbonate-rich samples from the studied wells, with a deep burial depth of more than 3000 m, are thermally mature, thus defining an early mature to moderate-mature stage. The kinetic models suggest that the Abu Roash (F) carbonate-rich rocks in the deepest burial depth, with calculated vitrinite reflectance (%VRo) values in the range of 0.72–0.83 %, have reached kerogen transformation ratio (TR) in the range of 10–55 %, indicating a high probability of oil production. This finding is confirmed by the presence of the oil crossover in these rocks with an oil saturation index (OSI) of more than 100 mg HC/ g rock. The Abu Roash (F) organic-rich carbonates are intractable rocks as implied by low porosities (up to 2.33 %) and poor permeability in the range of 0.0017–0.0039 mD. The pores in these rocks have a wide range in size, including interparticle, fracture, and organic matter (OM) pores, as recognized in the thin section and scanning electron microscopy (SEM). The development of these pore types and their quality is mainly controlled by high mineralogical brittleness (i.e., carbonates) together with the high OM inputs. Based on the above characteristics, the Abu Roash (F) carbonate-rich rocks in the Abu El Gharadig Field are a candidate for unconventional tight oil reservoir potential, which typically require a form of hydraulic fracturing for possible oil production at deeper burial depths. [ABSTRACT FROM AUTHOR]

The Late Miocene Zeit Formation is exposed in the Red Sea Basin of Sudan and represents an important oil-source rock. In this study, five (5) exploratory wells along Red Sea Basin of Sudan are used to model the petroleum generation and expulsion history of the Zeit Formation. Burial/thermal models illustrate that the Red Sea is an extensional rift basin and initially developed during the Late Eocene to Oligocene. Heat flow models show that the present-day heat flow values in the area are between 60 and 109 mW/m 2 . The variation in values of the heat flow can be linked to the raise in the geothermal gradient from margins of the basin towards offshore basin. The offshore basin is an axial area with thick burial depth, which is the principal heat flow source. The paleo-heat flow values of the basin are approximately from 95 to 260 mW/m 2 , increased from Oligocene to Early Pliocene and then decreased exponentially prior to Late Pliocene. This high paleo-heat flow had a considerable effect on the source rock maturation and cooking of the organic matter. The maturity history models indicate that the Zeit Formation source rock passed the late oil-window and converted the oil generated to gas during the Late Miocene. The basin models also indicate that the petroleum was expelled from the Zeit source rock during the Late Miocene (>7 Ma) and it continues to present-day, with transformation ratio of more than 50%. Therefore, the Zeit Formation acts as an effective source rock where significant amounts of petroleum are expected to be generated in the Red Sea Basin. [ABSTRACT FROM AUTHOR]

Two sets of contrasting oil-prone source rocks have been evaluated and compared - marine shales of the Jurassic Madbi Formation from Masila Basin, Yemen and Cenozoic coals and organic-rich sediments of the Nyalau Formation from Sarawak, Malaysia. An assessment based on organic facies characteristics, has been carried out on these sediments to distinguish, characterise and evaluate source rocks deposited in marine versus coastal plain depositional settings. Good source rock potential is suggested by the high TOC values of Madbi shales and organic-rich sediments of the Nyalau Formation. This is supported by high hydrocarbon indices of 450-752 mgHC/gTOC for the Madbi shales and 295-516 mgHC/gTOC for the Nyalau Formation coaly shales and coals. The Madbi shales have vitrinite reflectance values ranging from 0.74-0.88 Ro% indicating an early mature to peak mature stage, while the Nyalau sediments have vitrinite reflectance values of 0.50-0.66%, suggesting early maturity. The Madbi shale is expected to be a better source rock for oil as indicated from its higher abundance of Types I and II kerogen, compared to the Nyalau Formation which is dominated by Types II-III and III kerogen. On the other hand, good oil/gas generating potential is anticipated from the coals and carbargilite/coaly shales of the Nyalau Formation, based on their liptinite-rich nature and the predominance of n-alkene/alkane doublets and aromatic compounds. Samples from Madbi and Nyalau Formations were characterized by a variety of biomarker parameters based on GC and GC-MS techniques. Distribution of organic facies parameters such as Tm/Ts, Pr/Ph, pristane/n-C17, phytane/n-C18, oleanane/C30 hopane ratios and abundance of regular sterane (C27, C28 and C29) appear to reflect variations in depositional conditions and/or source input. Although there is a mixture of land-derived and marine-derived organic matter in both sediments, the depositional conditions of these formations can be distinguished based on these biomarker parameters, whereby the Madbi shales display organic facies characteristics of suboxic marine depositional conditions while the Nyalau sediments are consistent with paralic deposition within suboxic to oxic conditions, typical of terrestrial coastal plain environments. [ABSTRACT FROM AUTHOR]

Calcareous shales and black limestones of the Jurassic Amran Group, located in the Sharab area (SW Yemen), were analysed based on organic and inorganic geochemical methods. The results of this study were used to reconstruct the paleoenvironmental and paleoclimatic conditions during Jurassic time and their relevance to organic matter enrichment during deposition of the Amran calcareous shale and black limestone deposits. The analysed Amran samples have present-day TOC and S total content values in the range of 0.25–0.91 wt % and 0.59–4.96 wt %, respectively. The relationship between S total and TOC contents indicates that the Jurassic Amran deposits were deposited in a marine environment as supported by biomarker environmental indicators. Biomarker distributions also reflect that the analysed Amran deposits received high contributions of marine organic matter (e.g., algal and microbial) with minor amount of land plant source inputs. Low oxygen (reducing) conditions during deposition of the Jurassic Amran deposits are indicated from low Pr/Ph values and relatively high elemental ratios of V/Ni and V/(V + Ni). Enrichment in the pyrite grains and very high DOP T and high Fe/Al ratios further suggest reducing bottom waters. This paleo-redox (i.e., reducing) conditions contributed to preservation of organic matter during deposition of the Jurassic Amran deposits. Semi-arid to warm climatic conditions are also evidenced during deposition of the Amran sediments and consequently increased biological productivity within the photic zone of the water column during deposition. Therefore, the increased bio-productivity in combination with good preservation of organic matter identified as the major mechanisms that gave rise to organic matter enrichment. This contradicts with the low organic matter content of the present-day TOC values of less than 1%. The biomarker maturity data indicate that the analysed Amran samples are of high thermal maturity; therefore, the low present-day TOC is attributed to the thermal effect on the original organic matter. This high thermal maturity level is due to the presence of volcanic rocks, which have invaded the Jurassic rocks during Late Oligocene to Early Miocene. [ABSTRACT FROM AUTHOR]

Coals, coaly shales and oil show samples from Late Cretaceous sections in the offshore Jiza-Qamar Basin (Yemen) were analysed using organic geochemical analyses to investigate the source of organic matter input and the genetic link between oils and potential source rocks in the basin. The coals and coaly shales have high TOC contents between 6.90 and 77.62 wt% and Hydrogen Index (HI) values are largely above 300 mg HC/g TOC, indicating that the Late Cretaceous coaly shales and coals as expected are organically rich, and predominantly contain Type III-II kerogens. The oil shows are classified as paraffinic–naphthenic–aromatic (P–N–A) oil with high wax contents, suggesting that the oils were generated from coal and coaly source rocks that were deposited in a deltaic–coastal environment. This is supported by bulk geochemical characteristics and biomarker compositions. A variety of biomarkers n -alkanes, regular isoprenoids, terpanes and steranes indicate that the oil shows were derived predominantly from source rock containing higher plant derived organic matter and were deposited in fluvial to deltaic environments under relatively oxic conditions. The biomarker characteristics and stable isotope compositions of the oils are similar to those of the Late Cretaceous coal and coaly shale rocks. The new data presented in this paper suggests genetic link between oil shows and coal/coaly shale rocks in the offshore Jiza-Qamar Basin and provides new evidence for the oil generative potential of the Cretaceous coals and coaly shales in the basin. [ABSTRACT FROM AUTHOR]

This paper comprehensively analyzes the geochemical, mineralogical and petrographical properties combined with bulk kinetics modeling of the Domanik organic-rich carbonate from various depth intervals in Kuzminovsky oilfield (well № 26 R), Volga-Ural Basin, Russia. The results show that, the Domanik carbonate-rich samples are characterized by high content of the total organic matter (TOC) up to 13.31 wt %, and contain mainly Type II kerogen with a slight II/III kerogen type, reaching very good to excellent oil generation potential. Moreover, the studied samples contain hydrogen-rich kerogen, which expected to generate paraffin, naphthene and aromatic (P–N-A) oil with low wax content as demonstrated by the Py-GC Pyrolysis combined with the abundance of fluorescent alginite, amorphous organic matter, and bituminite as established from investigations via microscope. The maturity indicators demonstrated that, most of the examined Domanik carbonate-rich samples, with a burial depth between 1726.5 m and 1784.9 m, have generally reached low thermal maturity stages; thus, defining an immature to moderate-mature of oil generation window. The results of the kinetic models suggested that, Domanik carbonate-rich rocks with vitrinite reflectance (VRo) values in the range of 0.60–0.71%, have reached relatively low kerogen transformation ratio in the range of 10–20%, indicating low probability oil generation. These finding are confirmed by the presence of low oil saturation index of less than 100 mg HC/g rock (19.64–69.97). In addition, the results of thin section, scanning electron microscopy (SEM) and micro-computed tomography (micro-CT) showed that the studied samples are characterized by low porosity (up to 3.29%) with a wide pores size range, including interparticle, cavities, cracks and organic matter pores. The development of these pore types and their quality in the studied samples is mainly controlled by high mineralogical brittleness (i.e., carbonate and quartz) together with the high organic matter inputs. Therefore, according to the obtained results, characteristics and observations, the Domanik Formation has a high potential for commercial oil production, which typically requires hydraulic fracturing followed by an in-situ retort, mainly by thermal methods such as steam injection and in situ combustion process. • Domanik Formation reached excellent petroleum generation with TOC values up to 13.31 wt %. • Domanik rocks have a total porosity of 2.35% and 3.29% as developed from interparticle, cavities, cracks and OM pore sizes. • Kinetic models result show that the peak of oil generation predicted at geological temperatures between 138 and 142 °C. • Domanik formation considered to be unconventional oil reservoir potential. • Domanik carbonate-rich rocks are suitable for conducting hydraulic fracturing for commercial oil production. [ABSTRACT FROM AUTHOR]

Crude oil samples from Cretaceous and Tertiary reservoir sections in the Zagros Fold Belt oil fields, southern Iraq were investigated using non-biomarker and biomarker parameters. The results of this study have been used to assess source of organic matter, and the genetic link between oils and their potential source rocks in the basin. The oils are characterized by high sulphur and trace metal (Ni, V) contents and relatively low API gravity values (17.4–22.7° API). This indicates that these oils are heavy and generated from a marine source rock containing Type II-S kerogen. This is supported by their biomarker distributions of normal alkanes, regular isoprenoids, terpanes and steranes and the bulk carbon isotope compositions of their saturated and aromatic hydrocarbons. The oils are characterized by low Pr/Ph ratios (<1), high values of the C 35 homohopane index and C 31 -22R/C 30 hopane ratios, relatively high C 27 sterane concentrations, and the predominance of C 29 -norhopane. These biomarkers suggest that the oils were generated predominantly from a marine carbonate source rock, deposited under reducing conditions and containing plankton/algal and microorganisms source input. The presence of gammacerane also suggests water column stratification during source rock deposition. The biomarker characteristics of the oils are consistent with those of the Middle Jurassic Sargelu carbonate as the effective source rock in the basin. Biomarker maturity data indicate that the oils were generated from early maturity source rocks. [ABSTRACT FROM AUTHOR]

Oil shales, located in Lajjun area (Central Jordan), were analyzed based on organic geochemistry, coupled with microscopical study to define the origin, type of organic matter input, and the influencing factors that govern organic matter (OM) enrichment, including the OM preservation conditions. Oil shales are thermally immature petroleum-source rocks for oil that require artificial heating to generate oil of commercial value. The analyzed oil shales have high total sulfur content values in the range of 2.08–4.06 wt%, and the organic carbon contents are also consistently high (>10%). The high total sulfur content and its relation with organic carbon values indicate that the Jordanian oil shales were deposited in a marine environment under reducing conditions. The organic matter input and paleoenvironmental conditions have also been evidenced from their biomarker distributions and microscopic study. The microscopical investigation indicated that the oil shales contain an abundant liptinitic organic matter (i.e., alginite, structureless (amorphous) and planktonic foraminifera). The presence of these liptinitic materials and planktonic foraminifera assemblages in the oil shale samples, further suggests a marine origin. Their biomarkers also provide evidence for a high contribution of marine plankton/algal and microorganisms and persevered under highly hypersalinity reducing conditions. The good preservation under reducing conditions contributes to the high amounts of organic matter enrichment during deposition of these oil shale sediments. Consequently, the Jordanian oil shales have very good oil generative potential, owing to high content of hydrogen rich Type I/II oil-prone kerogen. [ABSTRACT FROM AUTHOR]

Late Jurassic - Early Cretaceous shales of the Naifa, Safer, and Madbi formations were studied to evaluate source rock characterization. The results of the source rock were then incorporated into basin modeling to understand the timing of hydrocarbon (HC) generation and expulsion. The Late Jurassic - Early Cretaceous shales have low to high organic matter, with total organic carbon (TOC) values in the range of 0.50%-28.01%, indicating fair to excellent source rock potential. Main oil and gas are anticipated to be generated from the Naifa, Safer, and Lam shale samples with types I and (or) II and types II-III kerogens. In contrast, the Meem samples are dominated by type III kerogen (hydrogen index, HI < 200 mg HC / g TOC), and are thus considered to be gas prone. The Late Jurassic - Early Cretaceous shale samples have temperatures of maximum pyrolysis yield ( Tmax) in the range of 337-515 °C, consistent with immature to post-mature stages. The Tmax data also indicate that the Safer and Madbi shale samples have sufficient thermal maturity, i.e., peak-mature oil and gas window. The basin models indicate that the Naifa Formation is early-mature, and the onset oil generation began during the Early Miocene. The models also indicate that the main phase of oil generation in the Safer source rock began during the Late Eocene. In contrast, the Madbi source rock units had passed the peak oil generation window, and the oil was converted to gas during the Late Cretaceous to Late Eocene. The modeled HC expulsion history reveals that most oils are contributed by both Madbi units, with significant amounts of gas originating from the Meem unit. [ABSTRACT FROM AUTHOR]

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 ( S 1 + S 2 ) 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. [ABSTRACT FROM AUTHOR]

Late Cretaceous oil shales, located in the Yarmouk sub-basin (North Jordan), were analysed using techniques of organic and inorganic geochemistry, coupled with a microfossil study. Results of this study were used to reconstruct the paleoenvironmental and paleoclimatic conditions during the Late Cretaceous and to investigate their influence on organic matter enrichment of the oil shale deposits. The analysed oil shales have high TOC and S total content values in the ranges of 2.11–12.85 wt.% and 1.83–8.81 wt.%, respectively. The high S total content and its relation with TOC values indicate that the sulfur is associated with organic matter and that the oil shales were deposited in a marine environment under reducing conditions. This is shown by petrographic observation and supported by biomarker distributions. The microscopic investigation indicated that the oil shales contain abundant liptinitic materials (i.e. alginite and amorphous organic matter) and planktonic foraminifera. The presence of these sapropelic materials and planktonic foraminifera assemblages further suggests a marine origin. Biomarker distributions are also known to reflect dominantly marine plankton/algal and microorganisms source input. Water column stratification and low oxygen (reducing) conditions are indicated by narrow Pr/Ph values, relatively high V/Ni elemental ratios and the presence of gammacerane. Reducing conditions contribute to preservation of organic matter. Warm-water periods during the Late Cretaceous are also indicated by dominant occurrences of warm water index microfossil taxa. The warm climate combined with elevated phosphorus (P) are the major causes of excessive algae growth, and led to enhanced biological productivity within the photic zone of the water column during deposition of the oil shale deposits. This increased bio-productivity in combination with good preservation of organic matter are the main mechanisms of organic matter enrichment within the Late Cretaceous oil shales in the north Jordan. [ABSTRACT FROM AUTHOR]

This study uses organic geochemical and basin modelling results to examine the potential for thermogenic gas generation from oil-to-gas conversion of the organic-rich Lower Cretaceous Al Renk shales in the Melut Basin, South Sudan. The overall geochemical results show that the Al Renk shales are considered good gas-source rocks with total organic carbon (TOC) content >1 wt % and a low hydrogen index (i.e., HI < 150 mg HC/g TOC; mainly Type III kerogen). This finding contrasts with the source of organic matter and biomarkers related to the depositional environment. Based on biomarker indicators, the Al Renk shales contains a mixture of aquatic organic matter with some terrigenous land plants and was deposited under suboxic to relatively oxic settings in a lacustrine environment. The presence of mixed aquatic and terrigenous organic matter in lacustrine shale sediments suggests a mix of Types II and III kerogen as the original organic matter input during deposition. The geochemical and optical maturity indicators represent late-mature oil to gas generation windows, implying that the Al Renk shale has substantial thermogenic gas generation potential. Therefore, high thermal maturation is a crucial factor in drastically altering the original organic matter (OM) and decreasing HI values (conversion of kerogen to hydrocarbons). The kerogen to oil conversion and the subsequent cracking of the retained oil into thermogenic gas have been simulated by the burial/thermal/generation models in the Agordeed-1 well. These models show that nearly 10–50% of kerogen was transformed into oil during the Late Cretaceous (78–68 Ma), correlating with the early to peak mature of oil generation window (0.62–0.85 %Ro). Moreover, oil was expelled from the Al Renk source rock system during the Late Cretaceous to Late Eocene. From the Late Eocene until the present, significant amounts of residual oil were cracked into gas due to the maturation of the gas generation window (>1.30 Easy % Ro), which is ideal for wet gas generation. Consequently, the findings of this study advocate for conventional gas exploration in the Melut Basin's deeper stratigraphic succession, where the Al Renk Shale Formation has reached a high maturity level of the gas generation window. • Al Renk shales are favourable source rocks for petroleum generation potential. • Al Renk shales encompass a mixture of organic matter and were deposited in a lacustrine environment.. • Al Renk shales currently contribute to the generation of thermogenic gas. • Thermogenic gas is formed due to increased thermal maturation during the Late Eocene and continuing till today.. [ABSTRACT FROM AUTHOR]

Organic geochemical and basin modeling methods were used to investigate the potential of thermogenic gas generation from the source rock of the Miocene Salif Formation. The analyzed Salif shales were collected close to the intrusive volcanic rocks intersected by the Kathib-01 well in the offshore Tihamah Basin, Yemeni Red Sea. Generally, the analyzed Salif shale samples have total organic matter (TOC) values up to 3.4 wt %, overall, indicating organic matter richness capable of generating hydrocarbons. The analyzed Salif shale samples have low hydrogen index (HI) values of <200 mg HC/g TOC, indicating mainly Types IV and III kerogen. These results are in contrast with the presence of dominated hydrogen-rich Type-II kerogen in the Salif shales from the close location of the exploration wells e.g., Al-Auch-01, Al-Meethag −01 and Al-Meethag −02. Therefore, the drastic alteration of the original organic matter of Type II and decreasing HI values, as a result of conversion of kerogen to HCs in the studied well, is due to the high thermal maturation as indicated from thermal maturity indicators. The Salif shale samples in the studied well have reached the main stage of the gas generation window, implying that the Salif Formation has substantial thermogenic gas generation. The increase in thermal maturity in the studied well was caused by the presence of the intrusive volcanic rocks that extruded during the Pliocene age as a result of the regional uplift of rift shoulders. Based on the burial/thermal/generation model of the Kathib-01well, the conversion of kerogen to oil and the subsequent cracking of the retained oil into thermogenic gas has been simulated. During the early to late Pliocene age (5–2 Ma), 10 to about 60% of kerogen was converted to oil, matching the peak mature to late mature of oil window (0.75–1.35 %Ro). Moreover, oil was cracked into thermogenic gas during end of the late Pliocene until the present day (2-0 Ma), indicating the beginning of the gas generation window (>1.35% Ro) with a transformation ratio (TR) above 99%. The prediction of a significant charge of thermogenic gas generation from the Salif Formation in the studied Kathib-01 well is due to the presence of the volcanic intrusive rocks extruded during the late Pliocene to present day time. • Salif shales, overall, indicate organic matter richness capable of generating hydrocarbons. • Salif shales are currently dominated by low HI values of <200 mg HC/g TOC and entering the gas-window maturity. • Salif shales contribute to thermogenic gas potential as implied from geochemical and basin modeling results. • Thermogenic gas is generated from Salif shales during the late Pliocene to present day due to the volcanic intrusive rocks. [ABSTRACT FROM AUTHOR]

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

Tithonian–Berriasian Chia Gara organic-rich rocks, located in Kurdistan (northern Iraq), were analysed based on inorganic and organic geochemistry to define the origin, type of organic matter, and the influencing factors of organic matter (OM) enrichment, including the OM input and preservation, and their relationship to the paleoenvironment conditions. The δ 13 C org values of the Chia Gara rocks range from −29.99‰ to −26.93‰, with average values of approximately −28.8‰, indicating that the organic matter has a predominantly marine origin. Enhanced biological productivity within the photic zone of the water column during deposition of the Chia Gara Fm. is indicated by consistently high organic carbon content in most samples (average 3 wt.%), as well as by bulk geochemical and biomarker characteristics. Major contributions by aquatic algae and microorganisms with a minor terrigenous organic matter contribution are indicated by the n -alkane distribution patterns and the composition of the hopanoids, steroids, and tricyclic terpenoids. Strongly reducing bottom water is indicated by low pristane/phytane ratios, homohopane distribution patterns, and the redox-sensitive trace elements geochemistry. Salinity stratification with alkaline bottom waters is indicated by high Sr/Ba ratios and the presence of gammacerane in the analysed Chia Gara samples. These data indicate that OM enrichment in the Tithonian–Berriasian Chia Gara rocks results from the combination of enhanced biological productivity and salinity stratification with anoxic bottom water conditions, which favoured OM preservation. [ABSTRACT FROM AUTHOR]

This study is the first investigation which provides information regarding the organic geochemical and petrographic characteristics of Miocene Salif organic-rich shales from Tihama Basin in the Red Sea, Yemen. We evaluate organic matter content, type, maturity, and oil-generation potential as well as depositional environmental conditions. The total organic carbon (TOC) contents of the Miocene Salif shales vary between 0.59% and 5.40%, indicating fair to very good source rock potential. The Salif shales have hydrogen index values in the range of 64–576 mg HC/g TOC. The organic matter in the Salif shales are dominated by Type II kerogen and mixed II–III kerogens with a minor contribution of Type III kerogen, as supported by kerogen microscopy. This is also confirmed by their biomarker and carbon isotope results, which indicate that the Salif shales were deposited in highly reducing marine conditions and received high contributions of aquatic organic matter (e.g., algal and microbial) and terrigenous organic matter. Consequently, the Salif Formation is likely to be an oil-source rock. Maturity indicators such as vitrinite reflectance and pyrolysis data (i.e., T max and PI) indicate that most of the Salif shale samples are generally thermally mature, at the early-mature to peak oil window stage. The new data presented in this paper suggest that early-mature oil has been generated from Miocene Salif organic-rich shales, so exploration strategies should focus on the known location of Miocene Salif organic-rich shales for predicting the location of the source kitchen. [ABSTRACT FROM AUTHOR]

The petroleum generating potential of the Late Cretaceous coal within the Mukalla Formation is evaluated. Bulk and quantitative pyrolysis techniques and organic petrology were used to characterize the kerogen composition, generative potential and kinetic models to determine the variability of the organic matter and their effect on the timing of petroleum generation. These measurements identified one major organic facies containing an oil-prone Type II/III kerogen, with HI values >300 mg HC/g TOC that produces mainly paraffinic and paraffinic–naphthenic–aromatic (P–N–A) oils with high wax contents. Bulk kinetic analysis on Late Cretaceous coal samples reveal a relatively broad distribution of activation energies (42–69 kcal/mol). Using a generic heating rate of 3.3 °C/My, the onset temperature for oil generation (TR 10%) is ∼139 °C and the peak generation temperature (geologic T max ) range from 150 to 167 °C. A 1D model predicts that the Mukalla coals in the Jiza-Qamar Basin began oil generation at ∼40 My and reached peak generation ∼20–15 My ago. Therefore, the Mukalla coals could have be generated mature oils in the Jiza-Qamar Basin. [ABSTRACT FROM AUTHOR]

Barremian–Aptian organic-rich shales from Abu Gabra Formation in the Muglad Basin were analysed using geochemical and petrographic analyses. These analyses were used to define the origin, type of organic matters and the influencing factors of diagenesis, including organic matter input and preservation, and their relation to paleoenvironmental and paleoclimate conditions. The bulk geochemical characteristics indicated that the organic-rich shales were deposited in a lacustrine environment with seawater influence under suboxic conditions. Their pyrolysis hydrogen index (HI) data provide evidence for a major contribution by Type I/II kerogen with HI values of >400 mg HC/g TOC and a minor Type II/III contribution with HI values <400 mg HC/g TOC. This is confirmed by kerogen microscopy, whereby the kerogen is characterized by large amounts of structured algae ( Botryococcus ) and structureless (amorphous) with a minor terrigenous organic matter input. An enhanced biological productivity within the photic zone of the water columns is also detected. The increased biological productivity in the organic-rich shales may be related to enhanced semi-arid/humid to humid-warm climate conditions. Therefore, a high bio-productivity in combination with good organic matter preservation favoured by enhanced algae sizes are suggested as the OM enrichment mechanisms within the studied basin. [ABSTRACT FROM AUTHOR]

[Display omitted] • Madbi Formation is considered to be both conventional and unconventional petroleum plays. • The burial temperature with increasing depth is mainly controlled the conventional and unconventional petroleum potential. • Madbi source rock with high TOC of up to 12 wt% and low mature stage, entering unconventional petroleum. This study aims to carry out the detailed geochemical characterization of the Madbi organic-rich shale intervals from structural heights in the Sunah oilfield, Say'un–Masilah Basin. The geochemical and basin model results of the source rock reveal that the Madbi Formation in the Sunah oilfield have both conventional and unconventional oil resource potential, and can laterally and vertically change from one well site to another due to varying burial temperature distributions with increasing depth. The Madbi source rock from structural heights of the oilfield is characterized by high organic content, with total organic matter (TOC) values of up to 12 wt%, and reached the low mature stage of the oil generation window. These characteristics make them a potential yet unconventional oil resource candidate, resulting in the retention of more oil that could be released upon application of similarly unconventional techniques. The conventional petroleum system of the Madbi Formation in the deeper portions in the Sunah oilfield was identified based on the match between source, reservoir and seal rocks, and timing of generation, migration, trap formation, and preservation. This Madbi source rock set reached relatively high maturity in the peak-oil window, with ratios of approximately 10–50% of the kerogen converted to large amounts of oil since the late Eocene-early Oligocene. To date, the conversion ratios of kerogen have reached their highest values of more than 50%, generating significant amounts of oil and leading to high pressures and subsequent oil expulsion, which reached the trapping site via vertical migration paths through the faults. [ABSTRACT FROM AUTHOR]

The Jiza-Qamar Basin in eastern Yemen is still undergoing hydrocarbon exploration and hydrocarbon potential has not been assigned yet. In this study, subsurface samples from two onshore and offshore wells were collected to characterize the source rocks of Dabut Formation and to incorporate into basin modelling in order to know and determine the timing of petroleum generation and expulsion of the Dabut source rocks. Based on organic geochemical analysis, the Dabut sediments have variable TOC content in the range of 0.5–2.5 wt%, indicating fair to good source rock generative potential. The organic matter of Dabut source rock is dominated by Type III kerogen with minor mixed III–II kerogen contributions, and is thus considered to be mainly gas-prone and some oil-prone. This is supported by HI values in the range of 50–212 mg HC/g TOC. Vitrinite reflectance in the range of 0.63–0.88%Ro and pyrolysis T max in the range of 427–454 °C, generally indicate that the Dabut source rocks contain mature organic matter. One-dimensional basin modelling was performed to analyse the hydrocarbon generation and expulsion history of the Dabut source rocks in the Jiza-Qamar Basin based on the reconstruction of the burial and thermal maturity histories in order to improve our understanding of the hydrocarbon generation potential. Calibration of the model with measured vitrinite reflectance (%Ro) and borehole temperature (BHT) data indicates that the paleo-heat-flow was constant during the Late Cretaceous–Paleogene but increased during the Late Paleogene–Neogene and then decreased exponentially from Neogene to present-day. The modelled maturity history predicts that the oil generation (0.5% Ro) in the Dabut source rock began from about 56 Ma to 42 Ma and the peak hydrocarbon generation (0.86% Ro) occurred approximately from 14 Ma to 13 Ma. These models also indicate that the main phase of oil generation was at 56 Ma to 25 Ma, whereas the main phase of gas generation began from about 25 Ma to 14 Ma and still generated in the present-day. [ABSTRACT FROM AUTHOR]

Organic-rich shale layer is present within the syn-rift Madbi Formation of the Masila Basin, representing excellent oil source rock. Twenty-five representative immature to very early-mature source rock samples from the Upper Jurassic Madbi shale sequences were investigated using bulk and quantitative pyrolysis techniques. The analytical program included TOC, pyrolysis (SRA), pyrolysis GC, bulk kinetics, and kerogen microscopy. The results were used to characterize the kerogen composition and type of petroleum generated during thermal maturation from Madbi source rock and to clarify the variability of the organic matter and their effect on the timing of petroleum generation. Pyrolysis data identified two major organic facies with different petroleum generation characteristics; Type II kerogen with HI values of >400 mg HC/g TOC; Type II/III facies with HI values <400 mg HC/g TOC. This is supported by the abundant liptinitic materials (i.e., alginite, structureless (amorphous), and spores). Pyrolysis GC analysis on extracted rock samples show a dominance of a marine aliphatic-rich organic matter with variable contributions from transported terrestrial organic matter and proved to produce mainly paraffinic–naphthenic–aromatic oils with low wax contents. Bulk kinetic analysis on Madbi shale samples indicate that the Type II facies mostly derived from a homogenous organic matter, spans relatively narrow distribution of activation energy (50–54 kcal/mol) and predicted petroleum formation temperature is very different, with onset (TR 10%) temperatures of ∼125 °C (geological T max ∼138 °C). In contrast, the Type II/III facies reveals a relatively broad distribution of activation energies (40 kcal/mol to 62 kcal/mol) that are directly related to the heterogeneity in the organic matter, onset (TR 10%) temperatures of ∼106 °C (geological T max ∼139 °C). The bulk kinetic analysis also suggested that the peak generation temperatures (geological T max ) are variable and ranging from 135 °C to 142 °C, reaching a significant transformation ratio (∼50% TR). Therefore, the Madbi source rock potential could have be generated and expelled mature oils in the Masila Basin. [ABSTRACT FROM AUTHOR]

Widely exposed in the Marib-Shabowah Basin, the early Upper Jurassic Madbi Formation is divided into two units (Lam and Meem, youngest to oldest) believed to be major source rocks. The Madbi source rocks are characterized by relatively high total organic carbon contents (TOC) ranging from 0.5 to 10.0 wt%, meeting the standard as a fair to excellent source rock generative potential. They contain Type II kerogen grading to mixed Type II/III kerogens and Type III kerogen with HI values between 40 and 620 mg HC/g TOC. Vitrinite reflectance values range from 0.41 to 2.61% R o , indicating sufficient thermal maturity for both oil and gas generation. Burial/thermal history models indicate that the Upper Jurassic Madbi source rocks passed the peak of oil generation stage and convert the oil to dry gas in the Late Jurassic to Late Cretaceous time. Oil generation began immediately after deposition in the Late Jurassic time (150–145 Ma) and maximum rates of oil with significant gas have been generated during Late Cretaceous time (110–65 Ma). The peak gas generation occurred during the early Tertiary. The modelled hydrocarbon expulsion evolution suggests that the timing of hydrocarbon expulsion from the Madbi source rocks began in the early Cretaceous (140 Ma) persisted to present-day. The modelling results also indicate that the peak hydrocarbon generation and expulsion from Madbi source rocks in the studied area occurs well after deposition of the seal rock and formation of traps, ensuring entrapment and preservation of migrated hydrocarbons. [ABSTRACT FROM AUTHOR]

Abstract: Bituminous coals and carbonaceous shales, located in the Jiza–Qamar Basin, on the eastern Yemen, were analysed based on a combined investigation of organic geochemistry and petrology to define the palaeodepositional environment condition, organic matter inputs and their thermal maturity. Carbon isotope compositions and various biomarkers were performed on coals and carbonaceous shales within the Upper Cretaceous Mukalla Formation in the Jiza–Qamar Basin. The δ13C values range from −29.2‰ to −24.5‰ with average values around −26.7‰, whereas the organic carbon contents in most sediment samples are consistently high (>3%), indicating that the organic matter in the Mukalla coal and carbonaceous shale sediments has a predominantly terrigenous origin with slightly marine influence during burial. This has also been identified from kerogen microscopy, which is characterized by dominance of vitrinite and liptinite organic matter. The investigated biomarkers indicated that the Mukalla coals and carbonaceous shales contain high contribution of land plants with a minor aquatic organic matter input that was deposited in a fluvial to deltaic environments and preserved under relatively oxic conditions. This has been achieved from acyclic isoprenoids, terpane and sterane biomarkers of a saturated hydrocarbon and dibenzothiophene, alkylnaphthalene and methylphenanthrene biomarkers of an aromatic hydrocarbon. Based on the analysed biomarker thermal maturity indicators, it may be deduced that the Mukalla coals and carbonaceous shales in the Jiza–Qamar Basin have entered an early-mature to mature stages for hydrocarbon generation. This is also supported by vitrinite reflectance values of 0.63–0.83% Ro indicative that these sediments have reached oil window maturity. [Copyright &y& Elsevier]

[Display omitted] • Organic-rich chalky marls within the Mid Eocene Wadi Shallala Formation have TOC content up to 6.53 wt.%. • The Wadi Shallala organic-rich chalky marls contain mainly Types I and II kerogen with high organic S content. • The chalky marls can generate mainly sulfur-rich oil at the early stages of the kerogen cracking. This study deals with organic matter in chalky marls of the Wadi Shallala Formation in northern Jordan. We report geochemical analyses (Total organic carbon, programmed pyrolysis, bitumen extraction, and pyrolysis–gas chromatography) for the chalky marls from 17 samples to provide information on the quantity, quality, the thermal maturity of the organic matter, their potential as petroleum source rocks. The chalky marl samples contain a significant amount of total organic carbon (TOC, max = 6.53%) and hydrogen index (HI) ranging from 300 to 702 mg HC/g TOC. The organic facies are mainly Types-II and -I kerogen with a potential to generate high amounts of oil. The dominance of such kerogen is consistent with significant amounts of fluorescent alginite macerals, observed under ultraviolet light microscopy. These organic facies are also confirmed by the Py-GC investigation, showing sulfur-rich Type II-S kerogen. The presence of weak carbon–sulfur (C-S) bounds in the kerogen molecules, however, suggests the generation of sulfur-rich oil at the early stages during the oil-generation window as reported by earlier works. Both geochemical maturity indicators (i.e., Tmax and PI) and the fluorescence color of the liptinite macerals indicate that the studied chalky marls in the outcropped section of the study area are still thermally immature, and maturity did not alter the organic-rich intervals to generate suitable oil for commercial production. Therefore, these organic-rich sediments in the locations having relatively deeper stratigraphic sections are likely to be promising source rocks and recommend for petroleum exploration and production in northern Jordan. [ABSTRACT FROM AUTHOR]

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

Highlights: [•] The Upper Cretaceous coals are high volatile B–A bituminous coal rank. [•] The Upper Cretacous coals contain significant amount of oil-liptinite macerals. [•] The Coals have good potential for both liquid hydrocarbons of waxy oils and condensates. [•] The Upper Cretacous coals deposited in a swamp environment under relatively oxic conditions. [ABSTRACT FROM AUTHOR]