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The Upper Miocene Bongaya Formation coal, carbonaceous shale, and shale sediments were collected to investigate their origin, types, and maturity. The main objectives of this study were to verify and update previous claim of possible hydrocarbon showings and to gain new insights about the petroleum potential using different geochemical analysis approach. The primary methodology used in this study is the pyrolysis technique and coupled with petrographic analysis. The bulk geochemistry results revealed that the Bongaya sediments serve as favorable source rock, with the total organic carbon (TOC) content ranging from 0.90 to 63.10 wt% by weight, indicating fair to excellent organic richness. The coal samples exhibited the highest TOC values, followed by carbonaceous shale samples, while shale and coal laminated with sandstone samples displayed fair TOC amounts. Most of the Bongaya sediments analyzed in this study exhibited hydrogen index (HI) values of less than 200 mg HC/g TOC, indicating Type III organic matter, which signifies a significant influence of terrestrial organic matter. However, three coals displayed comparatively higher pyrolysis HI values, corroborated by Pyrolysis gas-chromatography (Py-GC) results and maceral types, indicating a mixture of Type II/III kerogen. This suggests that the Bongaya Formation sediment has the potential to generate gas with minor oil. Maceral analysis also revealed that most of the coal samples contained a high content of resinite maceral, which explains the waxy composition of the oil. The organic matter in the analyzed Bongaya sediments was found to be immature for petroleum generation, as evidenced by low huminite reflectance data (lower than 0.50% VR) and Tmax values between 372 and 432 °C. Consequently, the kerogen in the studied onshore Bongaya sediments has yet to enter the hydrocarbon cracking (catagenesis) phase before expelling petroleum. Therefore, it is essential to consider the offshore equivalent Bongaya sediments, which may be laterally extended offshore and buried at deeper depths to attain optimal maturity for hydrocarbon generation. [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]

Shale sediments were collected from four Cretaceous stratigraphic units across four explorations well locations in South Africa's Orange Basin and analysed to determine organic-matter characteristics, such as amount, quality, thermal maturity, and their viability as gas resources. The geochemical results show that the Cretaceous shales contain moderate organic quantities, as shown by TOC averagely up to 1.29%. The organic facies consist primarily of Type III kerogen, as proven alongside low hydrogen indexes between 40 and 133 mg HC/g TOC. As seen under a reflected light microscope, the dominance of such land plant-rich organic matter is in harmony with the significant amount of Vitrinite macerals. These organic sediments can produce primarily gas when they mature. The geological and geochemical properties of the organic sediments, chiefly Type III kerogen, generate both wet and dry gas, particularly when adequate thermal maturity is enhanced at deeper locations. Thus, the Orange Basin is considered promising for shale gas exploration and production. [ABSTRACT FROM AUTHOR]

This study examines the geochemical and petrographic characteristics of seven bituminite shales from the Kapurdi mine in the Rajasthan, NW India, in order to assess their organic matter inputs and evaluate the oil-prone potentials. These bituminite shale samples exhibit high total organic carbon (TOC) content (up to 45.11 wt.%). The high TOC contents were correlated with low total sulfur content of less than 1 wt.% and suggest that these bituminite shales were deposited in a fresh lacustrine environment. The dominance of such lacustrine environmental setting was confirmed by the presence of the Botryococcus algae. The analyzed bituminite shales are characterized by a bimodal distribution of normal alkanes and relatively low isoprenoid Pr/Ph, Pr/n-C17 and Ph/n-C18 ratios. These characteristics suggest that these bituminite shales contain a blend of organic matter that was derived primarily from algal lacustrine and other aquatic organic matter, with terrigenous land plants and deposited under suboxic to anoxic environmental conditions. Such findings of the organic matter (OM) input and environmental conditions are consistent with mainly Types I and II kerogen and small amounts of Type II/III kerogen, thus yielding both oil and gas prone to higher concentrations of oil generation potential. The dominance of hydrogen-rich kerogen and oil generation potential is in agreement with the findings of high hydrogen index (HI = 240–425 mg HC/g TOC) and H/C atomic ratio of more than 1.20. The abundance of n-alkene and n-alkane doublets in the pyrolysis–gas chromatography (Py–GC) also indicates that these bituminite shales have potential to generate high concentrations of paraffinic waxy oil. Most of the maturity indicators show that the bituminite shales from the Kapurdi mine have not yet entered the main stage of oil generation window, exhibiting a range of immature stages. Therefore, as highlighted in this study, these bituminite shales can be considered as a good candidate for oil shale reoterting processes to release commercial amounts of oil upon using artificial heating techniques such as hydrothermal conversion. [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]

Pliocene shales included in the post-rift Abbas Formation were recovered from an exploratory well (Kathib-01) in the Tihamah Basin and geochemically analyzed. A preliminary evaluation of the organic facies of the Abbas shales and their petroleum generation potential was conducted based on basic organic geochemical results. Most Abbas shale samples had total organic carbon (TOC) contents < 1% and a fair source potential, while the remaining samples, with TOC contents > 1%, had a relatively good potential. Overall, the Rock–Eval hydrogen index values of the shales analyzed were between 96 and 234 mg of hydrocarbon per gram of TOC (mg HC/g TOC), indicating two dominant organic facies: types III and II/III kerogen, which indicate the presence of mainly gas- and oil-prone source rocks. We conclude that the Pliocene Abbas shales in the Tihamah Basin are still in a very early-mature stage (with respect to the oil window) and, hence, have not generated petroleum yet. [ABSTRACT FROM AUTHOR]

The Say'un–Masila rift, one of the most important basins of Yemen, contains unconventional resources of organic-rich rocks. In the present work, geochemical and palynofacies analyses were performed on the organic-rich source rock (argillaceous limestone) of the late Jurassic–early Cretaceous Naifa Formation in the Say'un–Masila Rift Basin to investigate its hydrocarbon generation potential. The geochemical analysis of the organic matter reveals that the argillaceous limestone unit has total organic carbon contents of 0.5–2.6%, which indicate fair to good hydrocarbon source potential. The organic matter in the analyzed samples is dominated by Type II/III and Type III kerogens, with minor Type II kerogen, referring to both oil- and gas-prone source rocks. The dominant kerogen Types II/III and Type III are indicated further from quantitative results based on an open pyrolysis–gas chromatography analysis. Biological markers and palynofacies analysis suggest that the kerogen was formed through a combination of mixed marine and high land plant organic matter and was preserved under sub-oxic sedimentary conditions. The different geochemical and optical maturity parameters indicate that the analyzed argillaceous limestone of the Naifa Formation is thermally mature, equivalent to early mature of oil-generation window. This implies that the burial depth of the analyzed samples is not deep enough; therefore, only the deeper parts of the Naifa source rocks at the basin have reached a satisfactory maturity level to be considered as potentially effective petroleum source rock. The biomarker source and depositional environment indicators presented and discussed in this study are useful for future exploration in the Say'un–Masila Basin for oil-to-oil and oil-to-source geochemical correlations and offer guidance for potential prospecting targets that may occur within the 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]

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]

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]

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]

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]

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]

[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]

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

Abstract: The hydrocarbon source rock potential of shales from the Jurassic Madbi Formation was evaluated using organic geochemistry (Rock-Eval pyrolysis, TOC and bitumen extraction) and organic petrology. Very good source rock potential is suggested by high values of total organic carbon content (TOC,>2.0wt%) and high extractable organic matter content and hydrocarbon yields (>11,000 and 6000ppm, respectively). The Madbi Formation samples have high hydrogen index (HI) and low oxygen index (OI) values. Most of the samples in the study area are thermally mature and contain oil prone Type I and Type II kerogen. Vitrinite reflectance (Ro) values for the Madbi shale samples were measured from 0.74% to 0.89%. T max values range from 430 to 438°C, which are in reasonably good agreement with vitrinite reflectance data, reveal that the Madbi shales are at the early to peak mature stage. On the basis of biomarker maturity parameters, these shales are thermally mature. Shales of the Madbi Formation contain abundant hydrogen rich kerogen (liptinite up to 55%) and therefore good oil generating potential is anticipated. This is supported by high hydrogen indices (HI) of up to 400mgHC/gTOC and early to peak mature oil window range. [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]

Bulk property and geochemical analyses were performed on 15 crude oil samples collected from the Early Cretaceous clastic reservoirs in the oilfields of the southern Mesopotamian Basin, South Iraq. Specific gravities ranging between 25.4 and 31.6 API and relatively high sulfur concentrations of up to 1.97 wt % suggest that the samples were generated from kerogen Type II-S at relatively low maturity level. Biomarker ratios and parameters as well as carbon isotope ratios, indicate that the oils were derived from marine carbonate-rich source rocks deposited under reducing environmental conditions during the Jurassic to Early Cretaceous. Furthermore, biomarker maturity suggests two maturity subgroups for the samples based on their sulfur concentrations and specific gravity values. Sub-group (A) is characterized by oils generated from low-mature source rocks from the Late Jurassic-Early Cretaceous Sulaiy Formation; while the relatively high mature oils of sub-group (B) were generated from organic-rich intervals in the Jurassic Sargelu and Najmah formations. Basin model results revealed that these formations reached a peak oil-generation window at different times, expelling various quantities of oil. The basin model results further suggest that the organic-rich interval in the Sulaiy Formation began to expel little amounts of oil, corresponding to transformation ratio (TR) between 50 and 63% since the Late Miocene to present-day, while the organic-rich intervals in the Sargelu and Najmah formations were the earliest to expel significant amounts of oil, with relatively high TR values of 50–90% during the end of the Late Cretaceous to Early Eocene and continued to the present-day. These generated oils subsequently migrated to the shallow stratigraphic reservoir intervals through the vertical pathway of faults, and are currently extracted for use in the oil industry. • The oils sourced from a marine carbonate-rich rocks containing Type II-S kerogen. • The oils were derived predominantly from algal and microorganisms source input. • The oils were classified into two subgroups based on maturity. • The basin models suggest that the most oils were generated from Sargelu and Najmah source rocks. [ABSTRACT FROM AUTHOR]

The investigation of the Nyalau Formation and its offshore equivalents (Cycles I and I) using 1D-basin modeling was carried to evaluate the timing and maturity aspects of their petroleum system. The Nyalau Formation and its offshore equivalents show a very remarkable source rock sequence for oil and gas in the Sarawak Basin. About twenty typical samples of the Nyalau Formation, with its maturity range beginning at immature to early-mature were evaluated, adopting bulk and quantitative pyrolysis procedures to reveal the kerogen characteristics and define the inherent optical properties of the organic matter and the effect it has on petroleum generation. Pyrolysis data identified two organic facies that indicate petroleum generation tendencies; Kerogen Type II/III having fairly high values of hydrogen index (HI) above 200 mg HC/g TOC whilst the kerogen Type III is comparatively with low HI values below 200 mg HC/g TOC. The aforementioned is reinforced with respect to distribution appertaining to energy activation a derivative of the bulk kinetic analysis. This study in a wide distribution of energy activation of kcal/mole to 69 kcal/mol which is unswervingly correlated heterogeneously to the organic matter. Also, the bulk kinetic analysis shows substantial variation in petroleum formation tract with regards to onset as well as the Nyalau's source rocks samples peak generation temperatures. At the temperatures between 121 and 131 °C petroleum generation for kerogen Type II/III commenced while at the temperatures of 134–145 °C for kerogen Type III. There is a variation of the peak generation temperatures (geological temperature maximum) in the range of 135–142 °C for Type II/III kerogens, whilst 153–167 °C for kerogen Type III. A notable transformation ratio of about 33% is reached as a result of these peak generation temperatures. The results were then integrated into the basin modelling, thereby predicting the timing, generation, and expulsion of hydrocarbons from the Nyalau equivalent source rocks in the offshore basin. This models suggests the onset of petroleum generation from Nyalau source rocks began in the Early Miocene (23-16 Ma), and the generation peaked at the Middle Miocene (18-12 Ma). The evolution and the expulsion of hydrocarbon as modeled indicate the timing of the expelled petroleum commenced in Pliocene and continued to present-day (5–0.0Ma). One dimensional basin models and bulk kinetics provide a quantitative way of predicting the timing, generation, and expulsion of hydrocarbon from Nyalau Formation within the Sarawak Basin. • Τhe Nyalau Formation represents an important source rock sequence for oil and gas in Sarawak Basin. • Bulk and quantitative pyrolysis are used to characterize the kerogen composition and its impact on petroleum systems. • Τhe onset of petroleum generation from Nyalau source rocks began in the early Miocene. • Tow type of organofacies, namely type II/III and type III are established. • The reservoirs are present in zones in the pinnacle reefs that have secondary moldic and vuggy porosity. [ABSTRACT FROM AUTHOR]

The purpose of this study is to present the source rock characteristics of Late Cretaceous Harshiyat Formation source rock in the onshore and offshore basins of Yemen (i.e. Mukalla-Sayhut, Sayun–Masilah , and Jiza-Qamar). Source rock geochemical characterizations were completed and integrated to perform 1-D basin modeling to back-predict source rock thermal maturation, oil generation and expulsion. The geochemical findings revealed that mudstone intervals within the Harshiyat Formation comprised favorable source rocks, with total organic carbon (TOC) content between 0.50 and 35.10 wt %. The organic matter intervals in the Harshiyat mudstones are mainly Types II/III and III kerogens, with certain amount of Type II and I kerogens based on Rock-Eval HI values, ranging from 40 to 923 mg HC/g TOC. Mixed kerogen types were consistent with vitrinite and sapropelic organic matters, as observed by visual kerogen examination and the distribution of biomarker fingerprints. The existence of mixed types I, II, and III organic matter suggests that the Harshiyat mudstones could contribute to oil and gas at sufficient thermal maturity levels. The biomarker data of the organic matter in the Harshiyat mudstones show that the source rock contains a mix marine phytoplanktonic-bacteria/terrestrial land plant enthronement and were deposited in suboxic-anoxic conditions. Results of chemical and optical maturity indicators led to the conclusion of varying maturity stages from immature to late oil window levels for the mudstones of the Harshiyat Formation. Thermal maturation distributions inferred from the analyzed samples indicate that mudstone intervals in the offshore Mukalla-Sayhut Basin are extremely mature, compatible with the late-mature oil window and may have generated significant amounts of oil. This interpretation was supported by strong geochemical similarity between the organic matter in the mudstones and those of the oils found in the offshore Mukalla-Sayhut Basin and demonstrated by the concentrations of n -alkanes and isoprenoids as well as carbon isotopes. In the offshore Ras-Ghashwah-1X well, burial and thermal models were constructed and used to address the effect of tectonic events in triggering oil generation and expulsion from mature Harshiyat source rock in the offshore area. Kinetic database models for Type II and III kerogen mixtures indicate that the initial conversion of kerogen to oil occurred since the Late Oligocene with transformation ratios (TR) that span between 10% and 50%. Furthermore, the oil was expelled from organic matter intervals in the Harshiyat source rock starting from Late Oligocene and continuing until Late Miocene, with TRs of 50%–72%. From that period up to the present, the retained oil was cracked into wet gas in the gas window with an Easy %Ro greater than 1.30, and with peak TR ratios greater than 72%. • Late Cretaceous Harshiyat Formation source rock in the onshore and offshore basins of Yemen was investigated. • Generation and expulsion of oil started from Late Oligocene and ended in Late Miocene. • Gas window evolution started from Late Miocene and continued to present day. • Oil exploration targets should concentrate on the Harshiyat Formation along the deeper parts of the basins. [ABSTRACT FROM AUTHOR]

The current study aimed to explore the gas-generating potential and oil-to-gas conversion in the Madbi oil-source rock system based on data from deep well within the Say'un-Masila Basin using both geochemical and petrological methods as well as basin models. Biomarker results for the bitumen from analyzed shale samples indicate mixed organic matter, with mainly phytoplankton, bacteria, and some terrigenous land plants, deposited under relatively anoxic marine environmental conditions. The terrigenous organic matter, and rich in lipids from phytoplankton and bacteria, suggests Types II and II/III as the original organic matter during deposition. Such findings are not consistent with the significant amounts of vitrinite and inertinite that found under microscope and the low current hydrogen index (HI) values of 43–282 (Types III/IV and III/II kerogen) of the analyzed shale samples. The chemical and optical maturity indicators show that the Madbi shales throughout the studied well section are at different thermal maturity stages, consistent with late-mature stage of the oil window to gas-generation window. Therefore, this high thermal maturation is the critical factor that significantly modifies the original organic matter. Based on the basin models of the single well studied (Ghayl Bin Yumain-01), the initial conversion of kerogen to oil, occurring between the Late Cretaceous and Late Eocene (75–38 Ma), corresponding to peak-oil window (0.70–1.00 Easy %R o). Furthermore, the oil was expelled during the Late Eocene to Early Oligocene; hence, the late-mature stage of the oil window (1.00–1.30 Easy %R o) commenced during this time, with transformation ratios (TR) of 50–70%. Subsequently, the cracking of the retained oil into gas has occurred from the Early Oligocene through the present and is attributed to the high thermal maturation of the gas window (>1.30 Easy %R o), with maximum TRs of 70–97%. • Late Jurassic Madbi shales in the South-East Say'un-Masila Basin were investigated. • The Madbi shales are currently in the late-mature of the oil-generation to gas window. • Thermogenic gas was produced at above 1.3 %VR during the early Oligocene until today. • The petroleum source rocks system is still active up to present-day. [ABSTRACT FROM AUTHOR]

Late Cretaceous Fika Formation shale was collected and analyzed from six wells in northeastern Nigeria's Chad (Bornu) Basin. The characteristics and the oil and gas-generating potential of the source are discussed based on combined geochemistry investigations and basin models. The abundance of marine phytoplanktonic-bacteria and land-plant suggested by biological markers indicate that the kerogen in the Fika shale Formation is a mixture of Types II and III, which is not compatible with the current low Rock-Eval HI findings of less than 200 mg HC/g TOC. The chemical and optical maturity parameters suggest that the Fika shales throughout the studied wells are in the early maturity stage of the oil window near the gas window point. Therefore, thermal maturation is the critical factor that significantly reduces the original HI values and modifies Types II and III to produce oil and gas. Based on the kinetic database models for Types II and III kerogen mixtures, the initial conversion of kerogen to oil has been occurring since the Late Cretaceous in the Kanadi-1 and Tuma-1 wells and since the Eocene in the Kinasar-1, Kuchalli-1, and Faltu-1 wells with transformation ratios (TR) between 10–31% and 10–50%, respectively. Furthermore, the oil was expelled from the Fika shale source rock in the Kanadi-1 and Tuma-1 wells at the end of Late Cretaceous, with TRs of 65–70%. From that period up to the present, the retained oil was cracked into wet gas in the gas window of 1.10–1.30 Easy %R o with peak TR ratios greater than 65%. The distributions of thermal maturation, conversion ratio, and thickness suggest that the Fika source rock could generate substantial amounts of oil and gas in the southwest part of the basin. Therefore, the southwest part of the Chad (Bornu) Basin is considered a frontier exploration target. • Late Cretaceous Fika shales from six wells in the Chad (Bornu) Basin, were collected and analyzed. • Fika shales contain phytoplanktonic-bacteria and land-plant, consistent with a mixture of Types II and III. • The Fika shales are currently in the early maturity stage of the oil window to near the gas window point. • The southwest part of the Chad (Bornu) Basin is considered a frontier oil and gas exploration targets. [ABSTRACT FROM AUTHOR]

Trace element contents in isolated kerogen from Upper Cretaceous sediments within Gongila and Fika formations in the Chad (Bornu) Basin, northeastern Nigeria were determined using Inductively-coupled plasma mass spectrometer (ICP-MS), in order to infer the origin of the organic matter and the paleo-redox conditions during their sedimentation. The concentrations of the elements in the kerogen samples varied from 1.01 to 24,740 ppm. The distribution of elements shows that Fe is the most abundant element in Chad (Bornu) Basin kerogen, followed by Ce. Among the biophile elements, V is the most abundant, followed by Ni and Co in that order. Statistical evaluation of the elemental composition data shows that As, Ce, Pb, V, Cr, Fe, Co, Ni and U exhibit good positive correlations with each other. Molybdenum, on the other hand displays no obvious correlation with most of the trace elements determined including TOC, but has good positive correlation with TS and negative correlation with Tmax, Ce and Th, which suggests that the concentration of Mo decreases with increasing maturity and vice versa. Some trace element concentrations and their ratios suggest mixed marine and terrigenous source input for the organic matter (kerogen) in Chad (Bornu) Basin. More so, the concentrations of redox-sensitive elements, such as V, Ni, Cu, Cr Mo and Mn, in the kerogen samples suggest dysoxic bottom water conditions within the Gongila and Fika sediments. Cross-plots of V and Ni and V/(V + Ni) ratio also indicate that the organic matter of these samples was deposited in slightly reducing environments. [ABSTRACT FROM AUTHOR]