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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]

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

Lower to Middle Eocene organic-rich deep-water limestones of the ∼335-m-thick (1100 ft) Radwany (Thebes-equivalent) Formation represent a source rock and a potential reservoir unit at the October Oil Field in the Gulf of Suez. However, in spite of recent exploration advances, the pore system and diagenetic history of the formation are still poorly understood. This study aims to discriminate porosity types and their vertical distribution, assess the diagenetic processes controlling porosity evolution, and evaluate the unit's overall reservoir potential. To achieve these goals, we utilized an integrated petrographic, mineralogical, geochemical and petrophysical dataset from four offshore wells. At October Oil Field, the Radwany Formation is informally divided into three intervals (from the base up: C, B and A) which are composed of planktonic foraminiferal wackestone, wackestone-packstone and packstone microfacies. Pores include both fabric selective (interparticle, intraparticle and moldic) and non-fabric selective (fracture) types. Visible porosity reaches up to 11.6%, and the highest porosity values are associated with interparticle pores in foraminiferal packstone in interval C. The two overlying intervals have lower porosities but have TOC values of up to 6 wt %. The Nuclear Magnetic Resonance (NMR) analysis yields low amplitudes of short T2 components (max. 52 ms), which suggests the presence of small pores (intraparticle, moldic, fracture, and fissure). Based on the electrical quality index (EQI) rock classification, nine groups were identified, suggesting a high heterogeneity of the formation. The highest EQI values positively correlate with high porosity (visible and estimated) in the lower part of Interval C which is dominated by interparticle/intraparticle porosity, thus reflecting the low tortuosity values of this microfacies. Dominantly low EQI values in Intervals A and B indicate low porosity efficiency and higher tortuosity. Carbonate sediments of the Radwany Formation are interpreted to have undergone a complex series of diagenetic processes. These processes modified the primary pore system either by enhancing the reservoir properties (dissolution and fracturing), or by reducing or destroying porosity (cementation, mechanical and chemical compaction, and minor pyritization, chertification, and asphaltene precipitation). The study highlights the unconventional reservoir potential of the middle and upper parts of the Radwany Formation (intervals B and A) at October Oil Field, and the conventional reservoir potential of interval C. It emphasizes the complexity of diagenetic controls on the porosity evolution in deep-water limestones of the Gulf of Suez, and may provide valuable insight into similar deep-water carbonate systems in rift basin reservoirs elsewhere. • Eocene deep-water limestones of October Field, Egypt underwent complex diagenesis. • Dissolution of carbonate grains and/or matrix and fracturing increased porosity. • Porosity reduced by cementation, pressure solution, and authigenic mineralization. • Radwany (Thebes) Formation shows combined conventional and unconventional potential. [ABSTRACT FROM AUTHOR]

The Early Cretaceous clay-rich facies of the Sembar Formation represent the most significantly occurring organic-rich sediments in the Southern Indus Basin of Pakistan. In this study, detailed geochemical research of total organic carbon, biomarker, mineralogy and trace elemental compositions, together with kerogen microscopic analysis, were carried out and used to understand the organic matter input and the dispositional environmental setting of the organic-rich Sembar shale. The Sembar shales have high organic matter, as indicated by the total organic carbon (TOC) content of up to 2.31 wt %. These shales contain a high abundance of liptinites (i.e., alginite and bituminite), with significant reactive vitrinite maceral, reflecting a mixed-organic matter with a high contribution of marine-derived input. The biomarker distributions evidence the finding of mainly marine organic matter. The biomarker characteristics such as Pr/Ph, Pr/n-C 17 , Ph/n-C 18 , and tricyclic terpane ratios together with C 27 -C 29 regular sterane distributions show that the source of organic matter was primarily marine-derived from mainly phytoplankton algae, along with amounts of land plant input, and accumulated under a low oxygenated environment. The Sembar shale facies are characterized by high Mo trace element content and high V/Ni and Mo/TOC ratios, suggesting anoxic and nonsulfidic environmental conditions during time deposition. The geochemical proxies such as the Sr/Ba ratio and gammacerane/C 30 hopane (G/C 30 ) index suggest that the Sembar shale facies were deposited in a relatively low moderate stratified water column. The higher gallium (Ga) than rubidium (Rb), with high Ga/Rb ratios, indicates a high abundance of the kaolinite mineral, thereby deducing the subaerial weathering during the warm and humid climatic conditions. In this case, these warm and humid climatic conditions cause an influx of masses of nutrients, which could be attributed to increasing marine primary bioproductivity. These large masses of nutrients into the photic zone are also attributed to the presence of the upwelling system during the deposition time. Therefore, such conditions of bioproductivity and preservation of organic matter (OM) resulted in the accumulation of organic carbon in the shale facies of the Early Cretaceous Sembar Formation., Competing Interests: The authors declare no competing financial interest., (© 2024 The Authors. Published by American Chemical Society.)

Organic rich sedimentary rocks of the Late Cretaceous Muwaqqar Formation from the Lajjun outcrop in the Lajjun Sub-basin, Western Central Jordan were geochemically analyzed. This study integrates kerogen microscopy of the isolated kerogen from 10 oil shale samples with a new finding from unconventional geochemical methods [i.e., ultimate elemental (CHNS), fourier transform infrared spectroscopy and pyrolysis-gas chromatography (Py-GC)] to decipher the molecular structure of the analyzed isolated kerogen fraction and evaluate the kerogen composition and characteristics. The optical kerogen microscopy shows that the isolated kerogen from the studied oil shales is originated from marine assemblages [i.e., algae, bituminite and fluorescence amorphous organic matter] with minor amounts of plant origin organic matter (i.e., spores). This finding suggests that the studied kerogen is hydrogen-rich kerogen, and has the potential to generate high paraffinic oil with low wax content. The dominance of such hydrogen-rich kerogen (mainly Type II) was confirmed from the multi-geochemical ratios, including high hydrogen/carbon atomic of more than 1.30 and high A-factor of more than 0.60. This claim agrees with the molecular structure of the kerogen derived from Py-GC results, which suggest that the studied kerogen is mainly Type II-S kerogen exhibiting the possibility of producing high sulphur oils during earlier stages of diagenesis, according to bulk kinetic modeling. The kinetic models of the isolated kerogen fraction suggest that the kerogen conversion, in coincidence with a vitrinite reflectance range of 0.55-0.60%, commenced at considerably lower temperature value ranges between 100 and 106 °C, which have produced oils during the early stage of oil generation. The kinetic models also suggest that the commercial amounts of oil can generate by kerogen conversion of up to 50% during the peak stage of oil window (0.71-0.83%) at relatively low geological temperature values in the range of 122-138 °C. Therefore, further development of the Muwaqqar oil shale successions is highly approved in the shallowly buried stratigraphic succession in the Lajjun Sub-basin, Western Central Jordan., (© 2024. The Author(s).)

Bituminous carbonate rocks of the Upper Cretaceous Shu'ayb Formation from the Ajloun outcrop in Northern Jordan were geochemically and petrologically analyzed in this study. This study integrates kerogen microscopy results with geochemical results (i.e., biomarker, stable carbon isotope, and major elemental compositions) to understand the organic matter (OM) inputs and to reveal the dispositional setting and its effect on the occurrence of OM. The Shu'ayb bituminous carbonate rocks have high total organic carbon (TOC) and sulfur (S) contents, with average values of 12.3 and 4.59 wt %, respectively, indicating redox conditions during their precipitation. The high abundance of alginite (i.e., lamalginite ) in the Shu'ayb bituminous carbonate sediments is a further evidence for redox conditions. The finding of mainly marine-derived OM was also demonstrated by the biomarker distribution and carbon isotope composition. The biomarkers are represented by a narrow Pr/Ph ratio of up to 0.97, abundance of tricyclic terpanes, and high C 27 regular sterane, indicating that the OM was primarily derived from phytoplankton algae, along with small amounts of land plant-derived materials, and were accumulated under reducing conditions. The studied Shu'ayb bituminous carbonate facies is composed of mainly calcium (CaO; average, 45.10 wt %), with significant amounts of silicon (Si 2 O 3 ; avg., 9.35 wt %), aluminum (Al 2 O 3 ; avg., 6.91 wt %), and phosphorus (P 2 O 3 ; avg., 1.47 wt %) and low amounts of iron (Fe 2 O 3 ) and titanium (TiO 2 ) of less than 1 wt %, indicating that the detrital influx was low in an open water depth system with higher primary bioproductivity. The geochemical proxy suggests that the Shu'ayb bituminous carbonate facies was established in a saline water environment, with Ca/Ca + Fe and S/TOC values of more than 0.9 and 0.50, respectively, which could be attributed to the increase in reducing conditions of the water column. The chemical index of alteration values of more than 0.8 also indicate that the Shu'ayb bituminous carbonate facies formed during warm and humid climatic conditions, thereby resulting in intense subaerial weathering., Competing Interests: The authors declare no competing financial interest., (© 2024 The Authors. Published by American Chemical Society.)

Oil-bearing sandstone samples were collected from the Lower Cretaceous sequence in the Kharir-2 exploration well, Kharir oilfields (Eastern Yemen). The current study integrates biomarker of the aliphatic hydrocarbon fraction of the extracted oil with a new finding from the molecular structure of the oil-asphaltene, in order to learn more about their properties, including organic matter (OM) input, depositional environment, and thermal maturity. The overall oil composition results show that the extracted oils have a high saturated hydrocarbon of up to 50% and significant levels of aromatic hydrocarbon and polar components, indicating generally paraffinic to naphthenic oil. This claim agrees with the molecular structure of the kerogen derived from the pyrolysis-gas chromatography result of the oil-asphaltene, which suggests that the extracted oils from the Lower Cretaceous sandstone reservoirs are mainly paraffinic-naphthenic-aromatic oils, exhibiting low wax content and originated from marine type II kerogen. The type II kerogen of the marine-source rock is also demonstrated by the bulk kinetic model of the oil-asphaltene for the extracted oils, with a broad range of E a between 38 and 62 kcal/mol and a frequency factor ( A ) of 1.52-1.47 × 10 13 /1 s. The biomarker characteristics of the aliphatic fraction show that the extracted oils from the Lower Cretaceous sandstone reservoirs were generated from clay-rich source rock, containing OM origin of mainly marine and terrestrial OM input and deposited under suboxic environmental conditions. Furthermore, the maturity-sensitive aliphatic biomarker parameters indicate that the extracted oils were generated from mature source rock in the range of the peak-mature stage of the oil generation window. Oil-source rock correlation of various established biomarker proxies for OM origin, depositional environment, and lithology suggests that these extracted oils were possibly generated from a single source rock, and the Madbi clay-rich formation contributed to most of the extracted oil from the Lower Cretaceous sandstone reservoir rocks., Competing Interests: The authors declare no competing financial interest., (© 2024 The Authors. Published by American Chemical Society.)

The current study aims to integrate the geochemical characteristics of the Oligocene shale source rock system, oil, condensate, and natural gas samples in the Oligocene sandstone reservoirs from three exploration wells located in the offshore Nile Delta, East Mediterranean Sea, using organic geochemistry and a 1D basin modeling scheme. The Tineh shales exhibit total organic carbon values ranging between 0.90 and 1.89 wt %, along with hydrogen index values in the range of 54-240 mg hydrocarbon/g rock. The geochemical characterization suggests that the shale intervals of the Oligocene Tineh Formation contain type II-III and type III kerogens and, thereby, could be regarded as promising oil- and gas-prone source rocks with high contributions of gas generation potential. The study also reconstructs the 1D thermal and burial history models, showing that the Oligocene Tineh source rock system is in the main oil and wet gas generation phases from the late Miocene to the present time. The simulated basin models reveal the transformation (TR) of 10-50% kerogen to oil during the late Miocene-early Pliocene period and that the Oligocene Tineh source rock system has larger oil generation and expulsion competency, with a TR value of up to 65% during the early Pliocene-Pleistocene time period. The thermogenic gas was also formed during this time and continued to the present day. This study also investigated the presence of oil and condensate in the Oligocene sandstone reservoir samples and revealed that they were generated from mature source rock, ranging from moderately to highly mature stages. This source rock unit was deposited in fluvial to fluvial-deltaic environments under oxic mixed organic conditions and accumulated during the Tertiary time, as evidenced by the presence of the oleanane biomarker dating indicator. The molecular and isotope compositions of natural gases revealed that most of the natural gases in the Oligocene sandstone reservoir are mainly thermogenic methane gases that were generated from mainly mixed organic matter. The thermogenic methane gases were formed mainly from secondary cracking of oil and gas, with small contributions of primary kerogen cracking. The properties of natural gases together with oil and condensate in the Oligocene reservoir rocks suggest that most of the thermogenic methane gases and associated liquid hydrocarbons are derived primarily from the Oligocene shale source rock system and formed by primary kerogen cracking and secondary oil and oil/gas cracking in different thermal maturity stages. Therefore, the Oligocene Tineh Formation can be regarded as self-source generation and self-reservoir rock; hence, an intensive oil exploration and production program can be recommended whenever the Tineh source rock system is is well developed and deeply buried., Competing Interests: The authors declare no competing financial interest., (© 2024 The Authors. Published by American Chemical Society.)

This investigation looks at the Late Triassic Baluti Formation's organic geochemical, mineralogical, and petrographical characteristics from a single exploration well (TT-22) near the Taq Taq oilfield in northern Iraq. The Baluti Formation shale samples that were studied in the studied well have high total organic carbon (TOC %) values up to 4.92 wt % and mostly hydrogen-rich types I and II kerogen with a minor gradient to types II/III and III kerogen, indicating a good oil-source rock. The hydrogen-rich kerogen was also confirmed by various organic matter (OM) origins and depositional environment-related biomarkers. The biomarker indicators demonstrate that the Baluti shale was deposited under anoxic conditions and contains a variety of OM generated mostly from algae marine and other aqueous organic materials, along with some terrigenous land plants. The geochemical and optical maturity indicators show that most of the examined Baluti shale samples, with a deep burial depth of more than 4000 m, are thermally mature, thus defining peak-mature to late-mature stages of the oil generation window. According to the basin models, from the late Miocene to the present, between 10 and 59% of the kerogen in the Baluti shale source rock has been transformed into oil, which is consistent with the VR values between 0.77 and 1.08%. The presence of the oil crossover in these shale rocks with an oil saturation index of more than 100 mg HC/g rock supports the maximal oil generation from the Baluti source rock system. Additionally, there was little oil expulsion from the Baluti source rock system at the end of the late Miocene, with transformation ratio values below 60% (59%). Considering the more significant oil generation and little expulsion, a high pressure was generated and forced the brittle minerals of the Baluti shales (mainly quartz), creating a natural fracture system as recognized and observed in the thin section. This natural fracture system enhances the porosity system of tight shale rocks of the Baluti Formation, giving rise to a high probability of oil production using hydraulic fracturing stimulation., Competing Interests: The authors declare no competing financial interest., (© 2024 The Authors. Published by American Chemical Society.)

The Western Delta Deep Marine Concession (WDDM) in the Eastern Mediterranean Sea is one of northern Africa's most recent petroleum-potential regions for gas and condensate exploration. The present study aims to determine the characteristics of the 15 natural gases and 5 associated condensate samples, using molecular compositions and isotopes from the Miocene reservoir rocks in the various wells located in the WDDM. The results of this study are also used to determine the gas-condensate correlation for their probable source rocks as well as the methane-generating mechanisms (i.e., thermogenic or microbiological). Results highlighted in this research reveal that most of the natural gases in WDDM are mainly thermogenic methane gases, with small contributions of biogenic methane gases that were generated from mainly mixed sources, with a high sapropelic organic matter input for biogenic gases. The thermogenic methane gases were formed from secondary oil and oil/gas cracking at the high maturity stage of the gas window. The biogenic gases are also contributed to the Miocene reservoirs, which are formed from the primary cracking of kerogen at low maturity stage by the action of CO 2 bacterial reduction. In addition, the saturated and aromatic biomarker results show that the condensate samples were generated from clay-rich source rocks. This source unit of the Miocene condensates were deposited in a fluvial deltaic environmental setting, containing mixed kerogen type II/III and accumulated during the Jurassic-Cretaceous, as evidenced by the age dating indicators. The properties of the natural gases and associated condensates in the Miocene reservoir rocks suggest that most of the thermogenic methane gases, together with the condensate, are derived primarily from mature Jurassic-Cretaceous source rocks and formed by secondary oil and oil/gas cracking at the gas generation window, as demonstrated by the 1-D basin modelling results highlighted in the prior works. Therefore, most of the natural gases in WDDM are non-indigenous and migrated from more mature Jurassic-Cretaceous source rocks in the nearby Northern Sinai provinces or the deeper sequences in the offshore Nile Delta provinces., (© 2023. The Author(s).)

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-C 17 , and Ph/n-C 18 ratios. It is classified as Type II oil-prone kerogen, consistent with high hydrogen index value. Considering the maturity indicators of geochemical T max (< 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.