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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]

The advent of low-field nuclear magnetic resonance (LF-NMR) has revolutionized the petroleum industry by providing a swift and straightforward method for the spectroscopic characterization of crude oil. This review paper delves into the significant strides made in LF-NMR technology since its inception by Felix Bloch and Edward Purcell in 1946, particularly its application in determining the composition, viscosity, and water content of crude oil, alongside SARA (Saturates, Aromatics, Resins, and Asphaltenes) analysis. LF-NMR's ability to noninvasively quantify the total water and oil content, differentiate between bound and mobile phases, and measure the SARA fractions underscores its superiority over traditional analysis methods, which often suffer from interference and lack of precision. This manuscript not only highlights LF-NMR's pivotal role in enhancing crude-oil characterization but also reviews recent developments that solidify its position as an indispensable tool in the petroleum industry. The convergence of empirical studies and technological advancements points toward a pressing need for further research to fully exploit LF-NMR's potential and refine its application, ensuring its continued contribution to the efficient and accurate analysis of petroleum products. [ABSTRACT FROM AUTHOR]

Forty Tertiary coals from Mukah-Balingian and Merit-Pila coalfields of the Sarawak Basin, Malaysia were investigated using bulk and molecular geochemical techniques such as proximate analysis, gas chromatography-mass spectrometry, elemental analyser, isotope ratio mass spectrometry, and inductively coupled plasma mass spectrometry to reconstruct their paleovegetation, paleoclimate, and environments of deposition. In addition, principal component analysis (PCA) of selected geochemical parameters was carried out to determine the controlling influences on the petroleum potential of the humic coals. δ13C values and the abundance of terpenoids imply the predominant contribution of angiosperms to the paleoflora. Bimetal proxies (Sr/Ba, Sr/Cu, and C-value), and δD values are generally suggestive of a warm and humid climate during the accumulation of the paleopeats. However, n-alkane proxies (Pwax, Paq, n-C23/n-C29, etc.) and polycyclic aromatic hydrocarbons (PAHs) distribution suggest that Balingian coals accumulated under relatively drier and strongly seasonal paleoclimate in the Late Pliocene. When compared with published global average abundances, the investigated coals are mostly depleted in major oxides and trace elements, suggesting peat accumulation in freshwater-influenced environments. Nonetheless, higher (> 0.5 wt%) total sulfur content in some Mukah-Balingian coals suggests some degree of epigenetic marine influence. Furthermore, the low to moderately-high ash contents of the Sarawak Basin coals indicate the presence of ombrotrophic and rheotrophic peat deposits. PCA result of selected geochemical proxies suggests that source input, paleoflora, and marine incursions are not major controlling influences on the petroleum potential. However, climatic, and depositional conditions appear to slightly influence the petroleum potential of the studied humic coals. [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]

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]

The distribution of aromatic hydrocarbon in sediments and oils is known to be affected by thermal maturity, source input and depositional conditions. Hence, the aromatic hydrocarbon fraction of four oil samples from different wells of the West Siberian Basin (central Russia) was investigated to determine the source of organic matter (OM), depositional environment and maturity of their source rocks. Biomarker ratios and parameters of aromatic compounds indicate that the studied oils were generated from clay-rich source rocks containing a mixed organic matter of marine and terrestrial origin, which were deposited in freshwater/deltaic to marine environmental settings under suboxic to relatively oxic conditions. Furthermore, the maturity-sensitive aromatic hydrocarbon parameters indicate that the source rocks are thermally mature, and in the peak to late maturity stage of the oil generation window. Oil–oil correlation results of various established aromatic biomarker proxies for organic matter origin, depositional environment and lithology suggests that the analyzed west Siberian Basin's oils were generated from a variety of geological sources and can be grouped into two distinct oil families. The first oil family (group I) was generated from clay-rich source rock containing mixed organic matter with relatively high amounts of terrestrial plant input and deposited in a non-marine (freshwater/deltaic) environment under relatively oxic conditions, while the second oil family (group II) was derived from mixed organic matter with high marine OM input that was deposited in marine environment under suboxic conditions. The findings of the heterocyclic and polycyclic aromatics highlighted in this study can help for better understanding of the genetic ties between oils and their sources and have an impact on traditional hydrocarbon development in the Basin. [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]

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]

An apparent increase in average global temperature is evident globally, and India is no exception. With the recent decade (2011–2020) arguably being the warmest, significant challenges due to rapid climate change have gained attention. However, notable spatial-temporal changes, especially with regard to land surface temperature (LST), were observed during the COVID-19 pandemic lockdown period, when a comparatively cooler climate was experienced in many urban centers. Assessment of LST, crucial in many heat-balance, land use, and climate change models research studies, depicts the near-surface hotness of the Earth's temperature at a given location. Thus, this study utilizes satellite remote-sensing data to investigate the spatial-temporal variations of LST pre and post-lockdown imposed during the COVID-19 outbreak. Unlike many existing research studies on the metropolitans of India, the study considers developing Indian cities, Ranchi and Dhanbad, as its study area. Accurate LST computation was performed using existing LANDSAT-8 OLI/TIRS images and judged using other parameters (NDVI, LSE) obtained directly from the thermal infrared bands. The LST assessment successfully estimated temperature variations in Ranchi and Dhanbad, depicting a significant drop in temperature coinciding with the lockdown period and subsequent increase in urban temperature post-pandemic, indicating a meaningful relationship between human activities and urban surface temperature. [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]

Within the last three decades, twelve major earthquakes (Mw > 6.0) have jolted Pakistan and contributed to a heavy death toll and an economic loss of billions of dollars, which is immense for any underdeveloped country. Despite the generalized description of seismic hazards in various regions of Pakistan, densely populated cities still require a detailed and integrated vulnerability analysis to overcome the impact of a significant earthquake. This study aims to integrate seismic hazard assessment schemes to understand the vulnerability of Attock city against an earthquake. It initially evaluates the threat from an earthquake due to tectonic activity in the region, splits the region (about 200 km radius) into six seismic zones and uses area source parameters. The ground motion prediction equations compatible with the study area's seismotectonic environment are also used in this study. Peak horizontal ground acceleration (PGA) and 5% damped spectral acceleration are critical features of ground motions. The site classification is carried within Attock city, indicating the presence of SB (foundation condition with Vs30 = 760 m/s), SC (foundation condition with Vs30 = 400 m/s) and SD (foundation condition with Vs30 = 300 m/s). The peak ground accelerations for a return period of 475 years at the SB, SC and SD sites are estimated as 0.23 g, 0.28 g and 0.30 g, respectively. Uniform hazard spectra are obtained for each site classification at three return periods (475, 975 and 2475 years). Another possible threat can be the local site conditions of the study area, as Attock city exists on the unlithified sediments of upper Pleistocene to Recent alluvial deposits. That is why microtremor recordings are conducted at 20 sites within Attock city to understand the fundamental frequency (f0), horizontal to vertical spectral amplitude (A0) and Kg parameter, a seismic vulnerability index. The values of f0 are found between 0.6 and 9 Hz and A0 is observed between 2.1 and 5 Hz, whereas the Kg is estimated between 0.24 and 20 Hz. Despite evidence of the seismic vulnerability of Attock city, the current building designs and infrastructure development are not synchronized with the uniform hazard response spectra and the soil amplification, thus enhancing the exposure of the study area to disaster during a major earthquake. This study will be instrumental in pre-disaster mitigation strategies for urban planners and policymakers. [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]

Heavy oil resources are attracting considerable interest in terms of sustaining energy demand. However, the exploitation of such resources requires deeper understanding of the processes occurring during their development. Promising methods currently used for enhancing heavy oil recovery are steam injection methods, which are based on aquathermolysis of heavy oil at higher temperatures. Regardless of its efficiency in the field of in situ upgrading of heavy oil, this technique still suffers from energy consumption and inefficient heat transfer for deeper reservoirs. During this study, we have developed a molybdenum-based catalyst for improving the process of heavy oil upgrading at higher temperature in the presence of water. The obtained catalyst has been characterized by a set of physico-chemical methods and was then applied for heavy oil hydrothermal processing in a high-pressure reactor at 200, 250 and 300 °C. The comparative study between heavy oil hydrothermal upgrading in the presence and absence of the obtained molybdenum-based oil soluble catalysts has pointed toward its potential application for heavy oil in situ upgrading techniques. In other words, the used catalyst was able to reduce heavy oil viscosity by more than 63% at 300 °C. Moreover, our results have demonstrated the efficiency of a molybdenum-based catalyst in improving saturates and light hydrocarbon content in the upgraded oil compared to the same quantity of these fractions in the initial oil and in the non-catalytically upgraded oil at similar temperatures. This has been explained by the significant role played by the used catalyst in destructing asphaltenes and resins as shown by XRD, elemental analysis, and gas chromatography, which confirmed the presence of molybdenum sulfur particles in the reaction medium at higher temperatures, especially at 300 °C. These particles contributed to stimulating hydrodesulphurization, cracking and hydrogenation reactions by breaking down the C-heteroatom bonds and consequently by destructing sphaltenes and resins into smaller fractions, leading to higher mobility and quality of the upgraded oil. Our results add to the growing body of literature on the catalytic upgrading of heavy oil in the presence of transition metal particles. [ABSTRACT FROM AUTHOR]

The shale samples of the Timah Tasoh Formation that deposited during the Early Devonian in Perlis, northern Peninsular Malaysia, have been investigated by utilising organic geochemical and petrological methods as well as elemental compositions. The shale samples were examined to assess the origin, type, and conditions of the paleodepositional environment during the sediment deposition and explore the gas-generating potential from the conversion of bitumen to gas from the more profound and older Paleozoic strata. Biomarker study indicates a mixed terrestrial-derived organic matter input with significant influences from lacustrine and marine-derived (marine phytoplanktonic-bacteria) land-plants organic matter deposited in a transitional environment (terrestrial to marine) under a suboxic condition. The ratio of trace elements concentration (e.g. Sr, Ba, V, Ni, Cr) established that the organic material was preserved under suboxic to oxic conditions. The analysis from the Rock–Eval pyrolysis indicates poor to very good hydrocarbon source potentials. However, evaluation based on bulk pyrolysis shows that the Timah Tasoh Formation contains a low hydrogen index (HI), suggesting that the organic matter is dominated by type IV kerogen, corroborated by the high vitrinite reflectance values. It indicates that the analysed samples are already in the stage of late mature to overmature and thus within a gas generation window. The solid bitumen within samples suggests that the Timah Tasoh Formation had prominent organic matter content for liquid hydrocarbon generation before a thick overburden rock and high thermal temperature occurred at the beginning of the deposition. During Late Cretaceous time transformed the primary organic matter kerogens of types II and III (that initially generated liquid hydrocarbons) into type IV kerogen, generating thermogenic gas potential by the process of secondary cracking source rocks. [ABSTRACT FROM AUTHOR]

The Marib Concession in the northwestern Sab'atayn Basin is the most conventional petroleum exploration activities. Although the Marib Concession is an established hydrocarbon province due to the accumulation of Mesozoic sediments some of which act as good source and reservoir rocks, still there is a gap in developing a better understanding the petroleum system of the region. This study identifies the characterization and effectiveness of the Late Jurassic Madbi-Sab'atayn petroleum system for the Marib Concession and reveals Kimmeridgian-Tithonian Madbi Shales and Tithonian Alif sandstones as the source and reservoir rocks, respectively. To analyze its source rock and reservoir characteristics, model the generation and migration histories, and outline the entrapment style and effective seals of the petroleum system, integrated geochemical and geological modeling techniques were used. The shale intervals within the Lam and Meem Members of the Late Jurassic Madbi Formation are considered to be the main source rocks in the Marib Concession and characterized by fairly high total organic content (TOC%) of up to 9.0%, whereas the hydrogen index (HI) ranges from 50 to 595 mg HC/g TOC, indicating that the kerogen types contained within these shales are mainly Type II and mixed Type II/III, with a significant amount of Type III. A wide range of vitrinite reflectance values (0.50–2.61 R0%) is indicative of the Madbi shales maturity and illustrates that the Madbi source rock is currently within the peak oil to gas window. Geochemical oil-source rock correlation analyses propose that the hydrocarbon's regional distribution in the Marib Concession was mainly derived from the Kimmeridgian age Madbi shales. The reservoir units are discovered in various stratigraphic sequences of Late Jurassic period, including Alif and Seen Members of the Sab'atayn Formation as well as Lam Member of the Madbi Formation. Still, the sandstones of the Alif Member of the Sab'atayn Formation acting as the primary productive reservoir within the studied Marib Concession. The best reservoir quality of the Alif sandstones is characterized by high porosity and permeability values up to 33% and 10,000 mD, respectively. The Tithonian salt and shales within the Safir Member of the Sab'atayn Formation represent good seal rocks that underlie the hydrocarbon reservoir rocks in Marib Concession. The main tectonic development within the Marib Concession in the northwestern Sab'atayn Basin is occurred as Late Jurassic to Early Cretaceous rifting during the Gondwana supercontinent and separation of Africa–Arabia and Madagascar–India and played a vital role in designing the petroleum play. Structural features such as horst, tilted fault blocks, and few stratigraphic traps are the main trapping mechanisms resulting from the Late Jurassic to Early Cretaceous rifting episodes. Both burial and thermal basin models reveal that the hydrocarbon generation within the Madbi active pod was initiated during the Late Jurassic period. The highest rate of hydrocarbon expulsion was attained in the Late Cretaceous time. In contrast, the migration of hydrocarbons continued since the Early Cretaceous period, most likely during the Hauterivian-Barremian ages. The hydrocarbon from the Madbi source rock, reached the trapping site via vertical migration paths through the faults due to an episode of rift during the Early Cretaceous period. This study provides important petroleum system elements for evaluating hydrocarbon resources in the Marib Concession of the northwestern Sab'atayn Basin, which is beneficial for further and exploration and better resources exploitation. [ABSTRACT FROM AUTHOR]

A study using high-resolution macroscopy and microscopy was conducted on the Neogene Mukah coal in Sarawak, Malaysia, to describe the changes in the coal facies, peat development and its precursors, and depositional conditions of the peat/coal. Eight coal seams from three boreholes (MC05, MC12, MC01) were analyzed. Bright, banded bright, banded dull, and dull coal lithotypes, with a predominance of the brighter lithotypes, were identified and primarily attributed to increases in huminite content and decreases in liptinite and mineral matter contents. Coals were characterized by high huminite (70.3%–91.9%), moderate liptinite (4.0%–26.3% mmf), minor inertinite (1.4%–5.9% mmf), and argillaceous mineral matter (0.0%–50.6%). Clarite (3.5%–88.7%) was observed to be the most predominant microlithotypes with carbominerite content ranging from 0.0% to 67.9%. The complete succession from topogenous to ombrogrenous peat evolution was identical between the eight coal seams, and temporary development of rheotrophic–ombrotrophic mires was suggested. The basal section of coal bench was dominated by humodetrinite/liptinite-rich coal or humocollinite/mineral matter-rich coal, whereas the middle section was characterized by humotelinite- and humocollinite/liptinite-rich coal and overlain by humotelinite-rich coal. The Mukah coal was suggested to have been deposited in a coastal floodplain within a (mainly) upper–lower delta plain setting more prone to telmatic coal facies. [ABSTRACT FROM AUTHOR]

Four oil samples were collected from oilfields in the western Siberian Basin, and analyzed using conventional geochemical and physical methods. The results of this study were used to evaluate the oil samples, focusing on the characteristics of their source rocks, including the origin of organic matter input; redox depositional conditions and degree of thermal maturity of their probable source rock were studied. The obtained SARA results show that the examined oils are paraffinic oils owing to their high saturated hydrocarbon fraction values of greater than 70% volume. The observed API gravity values (23.55° to 32.57°) and low sulfur content of less than 0.25% wt indicate that the examined oils are sweet oils and were generated from source rock containing Type-II, with low sulfur content. The low sulfur content combined with the vanadium (V) and nickel (Ni) ratios indicates that the examined oils were scoured from a mixture of aquatic and terrestrial organic matter, depositing under generally suboxic environmental conditions. The n-alkane and isoprenoid distributions, with their ratios and parameters further suggest that the examined oil samples were generated from source rock containing a mixed organic matter input and deposited under suboxic to relatively oxic environmental conditions. Bulk compositions and distributions of n-alkane and isoprenoid indicate that the oil samples were generated from mature source rock. [ABSTRACT FROM AUTHOR]

Organic-rich shale samples from the Miocene Miadol Formation were collected from seven exploration wells in the Melut Rift Basin, South Sudan and analyzed using organic geochemical analyses coupled with microscopic examination. We report the geochemical and petrological characteristics of 23 cuttings shale samples to provide information on the quantity, quality, and thermal maturity, thereby contributing to organic matter characteristics and their potential for oil and gas generation. The geochemical results indicate that the analyzed shale samples have moderate-to-high organic matter content with total organic carbon (TOC) content between 0.57 and 2.88 wt. %. The organic matter in the Miadol shale samples is primarily of type III kerogen, with a small amount of type II kerogen, as implied by the broad range of hydrogen index (HI) values (56 and 548 mg HC/g TOC), thereby exhibiting the ability to generate gas with some oil. The kerogen is consistent with the distributions of normal alkanes and isoprenoids in the aliphatic hydrocarbon. The n-alkane and isoprenoid distributions, with their ratios and parameters, suggest that the examined Miadol shale samples contain a mixture of organic matter and were deposited under suboxic to relatively anoxic environmental conditions. The analyzed Miadol shale samples at relatively shallow burial depths (470–820 m) are still immature as implied from their VR values of less than 0.50% VRo (0.28–0.39% VRo). Therefore, these Miocene organic-rich shales in the deeper burial depths may be promising source rocks for primarily gas and limited oil production in the Melut Rift Basin where they may reach high thermal maturity levels of oil- and gas-generation windows. [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]

Four crude oil samples representing the Jurassic sandstone sequence were collected from several wells in the Shabwah depression and analyzed using conventional geochemical and physical methods. The results were used to evaluate the oil samples, focusing on the characteristics of their source rocks, including the origin of organic matter input, redox depositional conditions, and degree of thermal maturity. The observed physical results show that the examined oils are light crude oils owing to their high American Petroleum Institute (API) gravity of 35.0–40.1°. The high API gravity and aliphatic hydrocarbon fraction indicate that the examined oils were generated from mature source rocks. The biomarkers of n-alkane, isoprenoid, hopanoid, and steroid with the δ13C isotopic compositions suggest that the oil samples were sourced from clay-rich rocks containing mixed organic matter with high contributions of marine organic matter and deposited under suboxic to relatively anoxic environmental conditions. The biomarker maturity indicators also suggest that the oil samples were generated from mature source rocks. According to the biomarker environmental indicators and δ13C isotopic compositions, the oil samples are from the Late Jurassic Madbi shale source rock. [ABSTRACT FROM AUTHOR]

The shale intervals in the Late Jurassic (Tithonian) Lam Member were collected from four exploration wells in the Al-Jawf region, northwestern Yemen, for combination of organic geochemical and microscopic investigations. This study mainly attempts to provide information on source rock characterization, including quantity, quality, and thermal maturity, and evaluate their suitability as petroleum generation potential, thereby contributing for future petroleum exploration along the Al-Jawf region. The geochemical findings reveal that the shale intervals in the Lam Member have favorable hydrocarbon source rocks with total organic carbon (TOC) contents between 0.50 and 6.43 wt. %, and they have laterally changed from one well site to another. The shale samples also have hydrogen index (HI) values between 50 and 433 mg HC/g TOC, resulting in two dominant organic facies of types II–III and III kerogen, with little type II, and thereby contributing to generate both oil and gas. The high contributions of mixed types of II–III and III kerogen were also demonstrated from the presence of the marine sapropelic organic matter and vitrinite derived from terrigenous plant input as observed by visual kerogen examination. According to both maturity indicators of geochemical Tmax (417–451 °C) and vitrinite reflectance (VRo) values (0.36–0.86%), the Lam shale intervals from the examined wells in the Al-Jawf region are currently in immature to peak mature of oil window. These thermal maturity levels of the organic matter intervals in the analyzed Lam shales are affected by the burial temperature distributions with the depth. In this regard, the source rock characteristics of the analyzed Lam shale samples in the studied wells are further distributed on the maps, and show that the Lam shales in the southwestern part of the Al-Jawf exploration region in the area around Kamaran-01 well are considered to be effective source rocks for generating amounts of oil. [ABSTRACT FROM AUTHOR]

This study analyzed the bulk properties and geochemical characteristics of four crude oils from the Central Gulf of Suez province (NE Egypt). Such oils were derived from high sulfur Type II kerogen, as demonstrated by their API gravity and sulfur content (S) of more than 2.45 wt. %. The result agrees with their asphaltene structures, derived using open pyrolysis-gas chromatography (Py–GC), which further suggests that the analyzed oils were primarily paraffinic and produced from Type II kerogen. The high S content combined with the vanadium (V) and nickel (Ni) metals ratios also indicates that the examined oils were scoured from carbonate-rich rocks that were deposited in a highly reducing marine environment. The occurrence of reduced oxygen with enhanced stratified conditions during deposition is further supported by the existence of gammacerane, low Pr/Ph ratio, Pr/C17, and Ph/C18 ratios, and high homohopane ratios of C3122R/ C30 and C35/C34. The tricyclic terpane distribution and homologous sequence of normal steranes C27-C29 suggest that the oils were derived from mainly phytoplankton algae and microbial mats. The existence of low quantities of 18α (H)-oleanane also indicates a source age that is not older than Late Cretaceous. In addition, the biomarker maturity ratios show that the investigated oils were obtained from low maturity source rocks. The geochemical results also suggest that the oils under study are genetically consistent with the organic-rich intervals in the Upper Cretaceous Brown Limestone Formation. [ABSTRACT FROM AUTHOR]

Organic-rich shale samples from the Late Cretaceous Galhak Formation were collected from one well location in the northern Melut Basin, Sudan, and analyzed by integrated organic geochemical and microscopic techniques. The study investigates the nature and preservation conditions of the organic facies and their relevance to petroleum resource potential. Judging from the high total organic contents (total organic carbon (TOC) > 2%), the analyzed Galhak shales are organically rich and include favorable source rocks. The organic richness in these shale sediments may be attributed to enhance the preservation of organic matter under suboxic conditions as implied from the n-alkanes and isoprenoid biomarkers. Biological markers, including of n-alkanes, isoprenoids, terpanes, and steranes, further suggest that the Galhak shale sediments were deposited in a relatively fresh lacustrine environment and received largely aquatic organic matter of plankton and bacteria with little terrestrial plant input. An abundance of aquatic-derived organic matter is consistent with types I and II kerogen as indicated by high Rock-Eval HI values of more than 400 mg HC/g TOC. The hydrogen-rich kerogen types I and II in the analyzed samples suggests an oil-prone source. According to the optical and geochemical maturity indicators, the organic matter in the Galhak oil shale is thermally immature; thus, they have not reached sufficient oil-window maturity for commercial oil generation. Therefore, the deeper parts of the Melut Basin, where the Galhak Formation reached high mature of peak-oil generation window, are recommended for further petroleum exploration and production. [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]

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]

Shale samples from the Early Cretaceous Sembar Formation were selected from a well in the southern Indus Basin, Pakistan, and were analyzed for geochemical parameters. The study investigates the source-rock characteristics and hydrocarbon-generation potential indicated by organic richness, organic-matter type, and thermal maturity. The high values of total organic carbon (TOC) content of the Sembar shales indicate favorable source-rock characteristics. The shale samples analyzed in this study have hydrogen index (HI) values in the range 43–238 mg HC/g TOC and oxygen index (OI) values in the range 14–151 mg CO2/g TOC. Accordingly, the organic matter is mainly type III, which is consistent with high amounts of terrestrial organic matter. The dominant presence of type III kerogen suggests mainly gas generation. According to geochemical-maturity indicators, the organic matter in the analyzed Sembar shale is thermally mature, having reached an early peak-window, but commercial amounts of oil and/or gas have not yet been generated. Therefore, further petroleum exploration at depth in the southern Indus Basin, mainly for gas production, is recommended. [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]

The Madbi Shale Formation is the main oil-source rock for conventional petroleum extraction in the east-central Say'un-Masilah Basin. This study explores the generation and expulsion potential of oil from the Madbi source rock system in a deep well location (Al-Qarn-01) in the north-western Say'un-Masilah Basin using geological and geochemical modelling. One-dimensional (1D) basin models were constructed to the estimate thermal regime in the basin and the evolution of oil cracking and expulsion from the organic-rich intervals in the Madbi Formation over the geological time. In the studied Al-Qarn-01 well, the organic-rich intervals in the Madbi Formation are thermally mature, ranging from peak- to late-mature oil window stages; thus, half or more of the kerogen was converted to oil at these maturity stages. The basin modelling results of the studied well (Al-Qarn-01) show that oil was generated and expelled from Madbi source rock intervals in two main phases according to the conversion ratio (TR %) of kerogen. The main conversion of kerogen to oil (TR = 10–50%) occurred between Late Cretaceous and Early Oligocene (80–33 Ma) periods, corresponding to the peak-oil window (0.70–1.00 Easy %Ro). Furthermore, significant amounts of oil were expelled from the source rock, which subsequently migrated into the overlying reservoir rocks in the Early Oligocene time during the initial Tertiary rifting. The late-mature oil window (1.00–1.10 Easy %Ro) commenced during this time, with TRs of 50–77%. [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]

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]

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]

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The Late Cretaceous Mukalla Formation is preserved in the Mukalla-Sayhut Basin of Southern Yemen. Using a combination of organic geochemical and petrological methods, we investigated shale intervals in the Mukalla Formation using the Masilah-1 well. We focused on identifying the organic facies and their hydrocarbon generating potential, which has relevance in terms of attracting future hydrocarbon exploration in this basin. The geochemical analysis was conducted on bulk cutting shale samples and indicated fair–good source rock potential, with moderate–high total organic carbon (TOC) contents of 0.51–3.49 wt%. Rock-Eval hydrogen index (HI) pyrolysis results suggested that the organic matter in the analyzed Mukalla shales was mainly type III kerogen; thus, it is likely to have shale-gas generation potential. The high proportions of type III kerogen are consistent with the distributions of lipid biomarkers and visual kerogen typing. Visual kerogen results showed that the analyzed Mukalla shales mainly contained vitrinite organic matter derived from land plants. The biomarker fingerprints of normal alkane, isoprenoid, sterane, and terpane in the saturated hydrocarbon fraction further suggested high contributions of terrestrial organic matter that deposited in fluvial to fluvial-deltaic environments under oxic conditions. The thermal maturation level was inferred from both chemical and optical maturity indicators and indicated that the shale samples, which were buried at relatively shallow depths in the Masilah-1 well, were of low maturity, i.e., within early-mature oil window. [ABSTRACT FROM AUTHOR]

The article presents the geochemical and petrographical characteristics of Paleocene lignite deposits of the Nagaur Basin to appraise the regional rank variation, organic matter maturity, and liquid hydrocarbon generative potential. The petrographical investigation indicated that the analyzed lignites contain abundant huminite group macerals with a significant amount of the liptinite group macerals while the concentration of inertinite group is less in comparison to huminite and liptinite group. The huminite reflectance (%R0) indicates that lignite samples of Nagaur Basin are thermally immature in nature and lignite to sub-bituminous B in rank. Immaturity of samples has a significant influence on the proximate results of the samples, especially on moisture and volatile matter concentration and low fixed carbon percentage. The analyzed lignites have TOC and S2 values that range from 30.4 to 43.0 and 58.0 to 130.7 mg HC/g rock, respectively, which shows that these lignites have excellent hydrocarbon generation potential and make them industrially important, considering the huge lignite reserve in the study area region. The Rock-Eval pyrolysis and ultimate analysis also reveal that these lignite samples mainly contained mixed type II-III kerogens with significant potential for both liquid hydrocarbon and gas generation. These kerogens are dependable on the maceral composition that was derived from the microscopic study. The presence of the high huminite with significant amount of liptinite (more than 15%) macerals also suggests that these lignites can act as a good source rock for hydrocarbon generation. [ABSTRACT FROM AUTHOR]