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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.

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.

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.

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 Botryococcusalgae. The analyzed bituminite shales are characterized by a bimodal distribution of normal alkanes and relatively low isoprenoid Pr/Ph, Pr/n-C17and Ph/n-C18ratios. 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.

The knowledge on CO2sequestration and CO2enhanced oil recovery (CO2-EOR) in mature mixed and interbedded hydrocarbon reservoirs are limited. In this vein, the feasibility of CO2-water alternating gas (CO2-WAG) for coupling CO2sequestration and CO2-EOR in a mature mixed sandstone-carbonate reservoir was investigated using the S1A reservoir. First, core sample analysis and scanning electron microscopy (SEM) were conducted to evaluate the reservoir characterization. Next, a geological model with dual porosity and permeability was developed and transferred to a reservoir simulation model, and 21-year field production data were utilized for history matching and constraining of the reservoir model. Then, continuous CO2and CO2-WAG injection methods were simulated using newly developed and history-matched geo-models and compared to assess their CO2-EOR and CO2storage mechanisms and determine their potential in a mixed sandstone-carbonate reservoir. The effect of the anisotropic permeability ratio and hysteresis on CO2storage mechanisms was addressed in this work. The results indicate that the CO2-WAG scheme can yield a +3% oil recovery factor than the continuous CO2injection method, and CO2-WAG injection can utilize up to 14 and 12% of the total CO2injected for residual and solubility trappings, respectively, while a minimal 2.9 and 0.03% was utilized from continuous CO2injection for residual and solubility trappings, respectively. The WAG ratio of 2:1 could yield a higher recovery factor and greater CO2utilization for solubility and residual trappings in a mixed reservoir. In mixed and interbedded reservoirs, geological anisotropy can also strongly influence reservoir performance during the CO2-EOR process, in which higher values of the anisotropy ratio (Kv/Kh) in CO2-WAG can yield greater oil recovery and more CO2storage; also, hysteresis has great impact on residual trapping. This study provides valuable insights into the potential of CO2-WAG for CO2sequestration and CO2-EOR in mature mixed and interbedded reservoirs.

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.

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%, 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.

This is the first study that focuses on the evaluation of a newly discovered oil shale deposit in the eastern Chenor area in the state of Pahang, Malaysia. Previously, this deposit was reported as carbonaceous/coaly mudstone. However, in this study, organic-rich immature carbonaceous mudstone containing above 15 wt % total organic carbon (TOC) is evaluated as oil shale, and that below 3.5 wt % TOC is termed mudstone. Oil shale and mudstone, which are significant sedimentary facies for oil and gas exploration, were investigated using organic geochemical and petrological methods, as well as computed tomography (Micro-CT), pyrolysis, and bulk kinetic techniques, to evaluate their hydrocarbon generation potential. The vitrinite reflectance values are less than 0.5% Roin all of the analyzed samples, indicating low maturity stage. This is corroborated by Tmaxvalues ranging from 383 to 429 °C. However, based on the kinetic simulation model, the average predicted geological temperature for the onset of hydrocarbon generation is 109 °C, while the peak of hydrocarbon generation is 153 °C. The extractable organic matter and hydrocarbon contents results show that the oil shale samples possess excellent petroleum potential compared to very good values for the studied mudstone. This is consistent with the plots of TOC content versus extractable organic matter, and hydrocarbon yields versus TOC content, commonly used in estimating the hydrocarbon generative potential of source rocks. The TOC of these oil shales is consistent with that of the Tertiary oil shale deposits in China. The analyzed oil shale samples are characterized by a high hydrogen index (HI) of up to 700 mg HC/g TOC (average 517.4 mg HC/g TOC), suggesting oil-prone type I and type II kerogens. However, the open pyrolysis-gas chromatography (Py-GC) result of these samples displays a predominance of n-alkene/n-alkane doublets extending to the long-range homologous series (C7–C33) with considerably high aromatic compounds, which indicates type II/III kerogens’ (mixed oil and gas) generative potential. Similarly, bulk kinetic analysis of the analyzed samples suggests typical petroleum source rock facies derived from heterogeneous (type II/III kerogens) organic matter assemblages. Thus, based on the pyrolysis and bulk kinetic result, the studied oil shale can be classified as “‘cannel coal”’ derived from terrestrial plants materials. This is supported by organic petrological and Micro-CT studies which revealed that the samples are composed mainly of liptinite (sporinite, cutinite, amorphous organic matter, and resinite) and vitrinite, with varied trace amounts of inertinite.

•Chia Gara Formation is an important oil-source rock in the Kurdistan region, North Iraq.•Chia Gara source rock is presently in peak oil-window maturity.•Chia Gara source rock is considered to be generated and expelled mainly oil.•The oil expulsion began since end of Late Eocene to present-day.

•The oils were generated from two source rocks.•The oils were derived from mixed marine organic matter input.•The oils were generated from mature source rocks.

Thirteen crude oil samples from fractured basement reservoir rocks in the Bayoot oilfield, Masila Basin were studied to describe oil characteristics and to provide information on the source of organic matter input and the genetic link between oils and their potential source rock in the basin. The bulk geochemical results of whole oil and gasoline hydrocarbons indicate that the Bayoot oils are normal crude oil, with high hydrocarbons of more than 60%. The hydrocarbons are dominated by normal, branched and cyclic alkanes a substantial of the light aromatic compounds, suggesting aliphatic oil-prone kerogen. The high abundant of normal, branched and cyclic alkanes also indicate that the Bayoot oils are not biodegradation oils.

•The oils were generated from a marine carbonate source rock bearing Type II-S kerogen.•The oils were derived predominantly from higher plankton/algal and microorganisms source input.•The oils were generated from early mature source rocks.

The subsurface of Qishn clastic rocks, which are exposed in the Sharyoof oilfield, has been studied. The petrophysical properties, i.e., porosity and permeability of Qishn clastic reservoir rocks were investigated using well logging coupled with core data. The results were used to evaluate the reservoir quality and hydrocarbon occurrence potential. The lithology of the Qishn clastic was computed from well logs, which indicate that the lithofacies of the Qishn clastic at Sharyoof oilfield is mainly composed of sandstone and carbonates with a low amount of shale intercalations.

This study was investigated eleven crude oil samples from representing Jurassic reservoir sandstones from the Al–Uqlah Oilfield in the Shabwah depression, using physical and geochemical aspects for saturated, aromatic, and asphaltene fractions to gain information about their source rock characteristics, particularly the conditions of depositional environment, thermal maturity and organic matter (OM) character. The overall results show that the examined oils have API gravity values between 38° and 43°, indicating that most crude oils are light and not biodegradable; nevertheless, oil samples, sweet oils with a low sulfur content, with S of <1 wt%. The molecular structure of the asphaltene in these oils derived from Py–GC suggests mainly paraffinic oil exhibiting high to low wax content derived from Types I and II kerogens. This claim agrees with the high saturated HC of more than 38% and significant levels of aromatic HC and polar components. The studied oil were generated from clay-rich source rocks, containing a mixed OM origin of marine and terrestrial organic matter and deposited under sub-oxic depositional environmental conditions as indicated by their biomarker of the saturated and aromatic fractions. The Py–GC structure of the asphaltene together with the environment-related biomarker indicators reveals the existence of two oil families. The first oil family represented in the majority of the studied oils and characterised as waxy paraffinic oil and generated from a mixture of organic matter, with significant terrestrial land plant input and deposited in sub-oxic environmental conditions. Other oil samples belonged the second oil family; these samples are predominantly P–N-A oils with low wax content and were derived from marine-source rock, containing significant contributions from aquatic OM and little input from terrestrial OM and deposited under more reducing environmental conditions. The biomarker and non-biomarker maturity ratios indicate that thermally mature source rocks generated the investigated crude oils of both oil families, corresponding to the peak oil window.

Paleogene Umm Er Radhuma and Ghaydah and Neogene Sarar source rocks from Sayhut subbasin in the Gulf of Aden Basin were studied to provide information such as organic-matter types, paleoenvironmental conditions, and petroleum-generation potential. This study is based on whole-rock organic-geochemical analyses and organic petrology. The total organic carbon (TOC) contents of the Paleogene to Neogene source rocks range from 0.43% to 6.11%, with an average TOC value of 1.00%, indicating fair to very good source-rock potential. The Paleogene Ghaydah and Umm Er Radhuma source rocks are relatively higher in genetic petroleum potential than Neogene Sarar source rocks. Mainly oil and gas are anticipated from the Ghaydah and Umm Er Radhuma source rocks with hydrogen index (HI) values ranging from 95 to 715 mg hydrocarbon (HC)/g TOC. This is supported by the presence of significant amounts of liptinite macerals in the Ghaydah and Umm Er Radhuma source rocks. The Sarar source rocks are dominated by vitrinitic type III kerogen (HI < 200 mg HC/g TOC) and are thus considered to be gas source rocks. The Paleogene to Neogene source rocks have vitrinite reflectance (R0) values in the range between 0.30% and 0.77% Ro, and pyrolysis maximum temperature values range from 412°C to 444°C (774°F to 831°F), consistent with the immature to early mature oil window. Therefore, the present-day kerogen type in the Paleogene to Neogene source rocks is original and should not have been altered by thermal maturity. The biomarker of organic matter suggests that the Paleogene to Neogene source rocks were deposited in a marine environment under suboxic to anoxic conditions. The biomarkers also indicate that the Paleogene to Neogene source rocks contain a mixture of aquatic organic matter (planktonic and bacterial) and terrigenous organic matter, with increasing terrigenous influence to Sarar source-rock samples. Highly hypersaline reducing conditions are also evidenced in Ghaydah and Umm Er Radhuma source rocks, as indicated by the presence of the gammacerane biomarker, low pristane to phytane ratios, and homohopane distribution patterns. [ABSTRACT FROM AUTHOR]

The Middle Jurassic Khatatba Formation in the northern Western Desert of Egypt was evaluated in terms of organic matter abundance, type and thermal maturity, as well as for some organic petrographic characteristics. Depositional environments were interpreted based on organic geochemical (Rock-Eval pyrolysis, extract analysis, and biomarker distributions) and organic petrological methods. Organic carbon contents range between 1.0 and 32.5 wt. %. The Khatatba shale and coaly shale samples have hydrogen index values in the range of 63 to 261 mg hydrocarbon (HC)/g total organic carbon, with mixed types 2-3 and 3 kerogens. Mean vitrinite reflectance (Ro) between 0.77 and 1.07% is in reasonably good agreement with pyrolysis Tmax (temperature at maximum of S2 peak) data (438-459°C). Organic-rich sediments of the Middle Jurassic Khatatba Formation have very good source rock generative potential and have obtained thermal maturity levels equivalent to the oil window. The main generation products are gas with very limited liquid HCs (oil or condensate). Seven shale and coaly shale samples from Khatatba Formation were characterized using gas chromatography (GC) and GC-mass spectrometry techniques. The Khatatba samples are characterized by the predominance of C14- C24 alkanes, a pristane/phytane ratio of less than 2, abundant C27 regular steranes, and the presence oftricyclic terpanes. These are consistent with the suboxic marine-environment conditions for the Khatatba source rock. Biomarker parameters for these samples generally indicate a mixture of land- as well as marine-derived organic-matter input. The maturity indicators based on C32 22S/ (22S + 22R) homohopane and C29 20S/(20S + 20R) and ββ/(ββ + αα) sterane ratios reveal that the Khatatba samples are thermally mature and have reached the peak oil-window maturity supporting the Ro data. [ABSTRACT FROM AUTHOR]