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The Jurassic–Cretaceous source rocks and their exploratory operations in the Mesopotamian Foredeep Basin are limited, and the origins of recovered hydrocarbons have not been comprehensively investigated. Comprehensive geochemical analyses and 1-D basin models were performed on the Middle Jurassic–Lower Cretaceous succession. Additionally, geochemical analyses of eight crude oils from Upper Cretaceous reservoirs were used to evaluate the conventional petroleum resource potential and petroleum exploration and development. The total organic carbon (TOC) and Rock–Eval results reveal the Middle Jurassic–Lower Cretaceous succession to be characterized by fair to excellent source rock potential and consists mainly of Types II/III and III kerogens. Consequently, the Middle Jurassic–Lower Cretaceous succession can generate both oil and gas, with high oil generation potential. The dominance of such kerogen is confirmed by the substantial lipids derived from phytoplanktonic, bacterial, and algal organic matter, as indicated by biomarker compositions. Furthermore, biomarker parameters and isotopic compositions of oil samples provide evidence of a genetic link between the Middle Jurassic–Lower Cretaceous source rocks and crude oils. The data suggest that the non-biodegraded oils were generated from mature marine source rocks deposited under reducing conditions. One-dimensional basin models show that the oil generation from the organic matter-rich intervals within the Sargelu, Najmah/Naokelekan, and Gotina formations started during the Upper Cretaceous and continued into the Miocene (83–21 Ma) at low maturity levels (EASY%Ro > 0.50%). Oil expulsion from the Sargelu, Najmah/Naokelekan, and Gotina formations has taken place since the Miocene until now (21–0 Ma) with higher conversion ratios (%TR > 50%) and migrating through vertical pathways provided by faults and being trapped within Upper Cretaceous reservoirs.Graphical abstract: The Jurassic–Cretaceous source rocks and their exploratory operations in the Mesopotamian Foredeep Basin are limited, and the origins of recovered hydrocarbons have not been comprehensively investigated. Comprehensive geochemical analyses and 1-D basin models were performed on the Middle Jurassic–Lower Cretaceous succession. Additionally, geochemical analyses of eight crude oils from Upper Cretaceous reservoirs were used to evaluate the conventional petroleum resource potential and petroleum exploration and development. The total organic carbon (TOC) and Rock–Eval results reveal the Middle Jurassic–Lower Cretaceous succession to be characterized by fair to excellent source rock potential and consists mainly of Types II/III and III kerogens. Consequently, the Middle Jurassic–Lower Cretaceous succession can generate both oil and gas, with high oil generation potential. The dominance of such kerogen is confirmed by the substantial lipids derived from phytoplanktonic, bacterial, and algal organic matter, as indicated by biomarker compositions. Furthermore, biomarker parameters and isotopic compositions of oil samples provide evidence of a genetic link between the Middle Jurassic–Lower Cretaceous source rocks and crude oils. The data suggest that the non-biodegraded oils were generated from mature marine source rocks deposited under reducing conditions. One-dimensional basin models show that the oil generation from the organic matter-rich intervals within the Sargelu, Najmah/Naokelekan, and Gotina formations started during the Upper Cretaceous and continued into the Miocene (83–21 Ma) at low maturity levels (EASY%Ro > 0.50%). Oil expulsion from the Sargelu, Najmah/Naokelekan, and Gotina formations has taken place since the Miocene until now (21–0 Ma) with higher conversion ratios (%TR > 50%) and migrating through vertical pathways provided by faults and being trapped within Upper Cretaceous reservoirs. [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]

[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]

The current study focuses on the organic geochemical and basin modeling of organic matter-rich limestones and oil samples from the Ajeel Oilfield. The objective was to characterize the organic matter and its hydrocarbon-generating potential, and its relevance to future hydrocarbon exploration in the northwestern Mesopotamian Basin. The organic biomarker results of the extracted bitumen samples indicated that the Sargelu, Naokelekan, and Chia Gara limestones received abundant planktonic-bacterial organic matter input, with a limited terrestrial contribution. Lipid-rich organic matter that originates from phytoplankton and bacteria with low amounts of terrestrial organic matter suggest a high abundance of Type-II or mixed-II/III kerogen as the original organic matter at time of sedimentation. Bulk property and geochemical analyses of the recovered oil samples, with mediumAPI gravities between 31 and 33°, and relatively high sulfur concentrations of up to 3.95 wt%, suggest that examined oil samples were derived mainly from Type II-S kerogen at moderate maturity stages. Biomarker ratios and parameters, as well as carbon isotopes, further indicated that these oils were derived from marine carbonate-rich source rocks deposited under reducing environmental conditions. These biomarker fingerprints and carbon isotopes show a genetic link between the oil examined samples and the extracted rocks of the Sargelu, Naokelekan, and Chia Gara source rocks and represent a mix of these carbonate-rich source rocks. Therefore, these source rocks contained kerogen Type II-S with high sulfur, and generated commercial oil at relatively low thermal maturity of early to moderate stages, as demonstrated from maturity parameters such as T max and PI as well as several biomarker ratios. Burial/maturity models with kerogen Type–II–S kinetic parameter revealed that the Sargelu, Naokelekan, and Chia Gara intervals began to generate oil at slightly lower thermal maturity (maturity levels = 0.55–0.79 EASY%Ro). As a result, about 10%–50% of the organic-matter was converted to oil during the Late Paleocene. The basin models also suggested that the organic-rich units including Sargelu and Naokelekan source rocks reached higher maturity levels, with TR of 71%–79% in the Early Miocene (20 Ma) and continued to the present. Trapping large quantities of oil lead to the high pressures and expulsion of these oils. The high conversion ratios further suggested large oil volumes accumulated in the northwestern Mesopotamian Basin were mainly originated from the Middle-Late Jurassic Sargelu and Naokelekan source rocks. • Middle Jurassic–Lowermost Cretaceous organic matter-rich limestones from were investigated. • Organic matter-rich limestones contain mainly Types II and II/III, with low Type III kerogen. • Genetic link between oils and the extracted rocks from Sargelu, Naokelekan and Chia Gara source rocks was obtained. • Oil was generated and expelled from theses source rocks since Late Paleocene and continued to present-day. [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 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]

[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]

• Datta shales contain mixed organic matter of planktonic/bacterial and land plant inputs. • The organic facies is predominantly of Types II and II/III, with Type III kerogens. • The Datta shales are both oil- and gas-prone source rocks. • There is a genetic link between extracted Datta shales and the oils from the Chanda Oilfield. This study deals with organic matter in the Early Jurassic Datta shale in the Upper Indus Basin, Pakistan. Organic geochemical and microscopic techniques were used to investigate organic matter input, environmental conditions of deposition as well as petroleum generation potential. The geochemical results suggest that the shales display mainly fair to good source rock generation potential, with poor petroleum generation potential in some samples. The HI varies between 32 and 519 mg HC/g TOC, with many of the samples appearing to be mainly Type II and mixed Type II-III kerogen, and thereby exhibiting the ability to generate both oil and gas. The dominance of such Type II kerogen in some samples is consistent with the high HI values (>300 mg HC/ g TOC) and high fluorescence alginite macerals. A section of the shale within the Datta Formation appears to be gas-prone, with HI values of less than 200 mg HC/g TOC. Biomarkers also indicate the presence of mixed organic matter of planktonic/bacterial and land plant input, which were deposited in a marine environment under relatively oxic conditions. The biomarker characteristics of the extracted shales correlate well with those of the oil from the Chanda Oilfield, indicating that the Datta shales are likely to be the effective source rock. This is supported by the thermal maturity, which ranges from moderate to peak-maturity, as indicated by vitrinite reflectance values of 0.69–0.82%, and the biomarker maturity indicators. [ABSTRACT FROM AUTHOR]