Jordanian Oil Shale Research Articles

Hydrogen adsorption kinetics in organic-Rich shale reservoir rocks for seasonal geological storage

The geo-storage of hydrogen (H2) is essential for advancing a robust and industrial-scale H2-based economy. The efficient H2 storage in a geological formation depends on the presence of a secure and impermeable caprock, such as a shale formation. However, the existing literature lacks information on the kinetics of H2 adsorption in actual shale formations with diverse organic contents and mineral compositions. Therefore, the kinetics of H2 adsorption in organic-rich shale samples from a Jordanian oil (JO) source rock formation are experimentally investigated herein at various temperatures (193, 273, 303, and 333 K) and two equilibrium pressures (15 and 45 bar) by using a volumetric method. The impact of mineral compositions and total organic content (TOC) on H2 adsorption is studied using two samples with distinct mineralogy and TOC values. Thermodynamic calculations are performed, and common adsorption models are used to analyze the experimental data. The results indicate that the H2 adsorption rate increases with pressure and decreases with temperature, being characterized by an initial rapid adsorption phase followed by a slower adsorption period as the uptake of H2 approaches equilibrium. More interestingly, the rate of H2 adsorption is higher in the sample with a high TOC and a richer composition of carbonate minerals. Both the applied adsorption isotherm models and adsorption kinetics models fit the experimental data remarkably well, thereby indicating their suitability for analyzing the kinetics of H2 adsorption in the JO shale. The unipore model matches the H2 kinetics data well, with R2 > 0.91. The H2 diffusion coefficient increases with pressure and temperature, where the H2 diffusion in shale accelerates with thermal motion intensity. This study provides fundamental insights into the adsorption kinetics of H2 and is expected to assist in implementing an industrial H2-based economy.

Impact of Thermal Maturation of the Upper Cretaceous Bituminous Limestone of Attarat Um Ghudran Central Jordan on Calcareous Nannofossil Preservation.

Oil shale deposits of the Late Cretaceous from three boreholes in central Jordan were examined to assess the impact of thermal maturation on the content of nannofossils. Thermal activity has been shown to have a strong effect on organic matter content and composition but its effect on calcareous nannofossil assemblages remains inconclusive. This study aims to determine the impact of thermal maturation on nannofossil assemblages and to compare this to an estimated maturity level based on bulk geochemical analysis. Micropaleontological and geochemical analyses were conducted on 31 samples from three oil shale wells drilled in Attarat Um Ghudran central Jordan. Several types of nannofossil preservation have been recorded, including dissolution, overgrowth, and breakage. In the Jordan oil shale sections, nannofossils exhibit a variety of preservation types, with intense dissolution in the middle part of the study sections. The vast majority of the samples had high TOC enrichment, with 29 samples exceeding values of >10%. Kerogen recovery and quality from the oil shale are very good, with a predominance of fluorescent amorphous organic matter (AOM) and minor algal components. The low fluorescence preservation index (FPI), which is 1 in most of the samples, indicates that alteration occurred due to intense thermal activities in the study interval. The palynomorph and AOM fluorescence, ranging from a spore coloration index (SCI) of 3 to 5, suggest that the studied samples were approaching the oil window. A correlation between the nannofossil preservation and geochemical parameters shows a predominance of poorly preserved nannofossils along with high total organic carbon contents and an elevated hydrogen index (HI). We show that low FPI values and a higher level of maturity are associated with poor nannofossil preservation, suggesting that nannofossils, in conjunction with petrographic analysis of kerogen, could be used as a rapid screening technique for estimating levels of oil-shale maturity. The nature of the tectonism in the study area, including faulting and a metamorphosed zone, enhanced the maturity, which might explain why the nannofossils were so significantly affected.

Influence of organics and gas mixing on hydrogen/brine and methane/brine wettability using Jordanian oil shale rocks: Implications for hydrogen geological storage

Influence of organics and gas mixing on hydrogen/brine and methane/brine wettability using Jordanian oil shale rocks: Implications for hydrogen geological storage

Organic-rich source rock/H2/brine interactions: Implications for underground hydrogen storage and methane production

There is increasing global interest in the attainment of a carbon dioxide-free global economy by replacement of carbon-based fossil fuels with clean hydrogen. But huge volume of hydrogen needs to be stored to address the imbalance between energy demand and supply due to low volumetric energy content of H2. Underground Hydrogen Storage (UHS) is an integral part of the hydrogen economy value chain and an appealing technology for the attainment of global decarbonization. The Jordan oil shale (Upper Cretaceous, organic-rich source rock sequence) has been proposed as a promising geological storage medium for hydrogen due to its exceptionally high organic content because methane can be produced from the reaction of trapped hydrogen with the kerogen. However, the extraction of methane from kerogen during hydrogen storage in organic-rich shale has not yet been reported. In this study, pressurized hydrogen was injected into high TOC shale samples for 80 days at 1500 psi and 75 °C to assess the extent of hydrogen-rock reaction and possible methane production. We also measured H2/brine and CH4/brine interfacial tensions (IFT), as well as the contact angles of H2/brine/shale and CH4/brine/shale systems at 75 °C and varying pressure (500–1500 psi) to understand the shale-fluid interaction at subsurface conditions. Results indicate some reaction of H2 with the shale after 80 days. No hydrogen sulfide was detected from gas chromatography analysis at the end of the experiment, but traces of methane (0.018 %) were detected. The reaction between hydrogen and organic matter of the shale yielded only a little methane under the conditions investigated in this research, possibly because the experimental temperature and reaction time was insufficient for copious methane generation. Furthermore, contact angle values of CH4/brine were found to be higher than of H2/brine. This means that under geo-storage conditions, the surface becomes fully CH4-wet condition (131o-149o) but remains only intermediate-wet in the presence of the H2/brine system (94o -106o) with increasing pressure, confirming that the interaction of methane with the shale surface is higher than hydrogen-shale surface interaction at similar conditions. The opposite trend was observed for IFT values. The hydrogen/brine IFT was 69.4 mN/m at 500 psi but decreased to 67.9 mN/m at 1500 psi. Likewise, the methane/brine IFT decreased from 69.7 mN/m to 58.3 mN/m with increasing pressure from 500 to 1500 psi. The findings of this study contribute to a better understanding of the adsorption trapping potential of organic-rich source rocks.

Life Cycle Assessment of Asphalt Mix Containing Jordanian Oil Shale Ash

Life Cycle Assessment of Asphalt Mix Containing Jordanian Oil Shale Ash

The deposition of type II-S Jordan oil shale in the context of Late Cretaceous source rock formation in the Eastern Mediterranean realm. Insights from organic and inorganic geochemistry and petrography

This study provides a detailed geochemical and petrographic investigation of 22 Upper Cretaceous Jordan Oil Shale (JOS) samples obtained from various wells distributed across Jordan. The JOS is generally characterized by high amounts of organic matter with total organic carbon (TOC) contents of 10–29 wt%, high carbonate contents of 15–75 wt%, and variable biogenic SiO2 contents of 1–50 wt%. The organic matter is oil-prone, reflected by a clear predominance of liptinite macerals and Rock-Eval Hydrogen Index (HI) values of 608–1078 mg HC/g TOC. In terms of elemental composition, bulk and molecular organic geochemistry and petrology, the JOS is similar to other age-equivalent organic-rich rocks from the Eastern Mediterranean. Primary bioproductivity was probably controlled by a Late Cretaceous upwelling event that affected the whole region. Low Pr/Ph ratios <0.5 indicate that organic matter preservation was not only controlled by the formation of an upwelling-related oxygen minimum zone but also by further oxygen depletion in isolated sub-basins. This setting led to vulcanization of kerogen; proven by a positive correlation between calculated organic sulfur contents and the amount of thiophenes generated during Curie-point pyrolysis. Although the thermal maturity is low (Tmax values < 430°C), significant amounts of hydrocarbons (up to 30 kg HC per ton of rock) are present within these rocks. The present bitumen fraction shows high concentrations of asphaltenes (10–65%) and NSO compounds (30–85%) with higher contributions in samples with the lowest thermal maturities. The relative contributions of aliphatic and aromatic compounds are correspondingly low, but increase with higher thermal maturities. Kinetic parameters suggest that isothermal pyrolysis at 350°C might be already enough to artificially convert 80% of the reactive kerogen within about one day, making the JOS a potential target for oil shale retorting.

The Behavior of Jordanian Oil Shale during Combustion Process from the El-Lajjun Deposit

The Behavior of Jordanian Oil Shale during Combustion Process from the El-Lajjun Deposit

Beneficiation and upgrading of Jordanian oil shale

Beneficiation and upgrading of Jordanian oil shale

Silica diagenesis promotes early primary hydrocarbon migration

AbstractWe present evidence that hydrocarbon source rocks can be preconditioned for primary hydrocarbon migration at an early stage of catagenesis by pore-scale processes linked to silica diagenesis. The evidence comes from a detailed petrographic and geochemical study of the Jordan Oil Shale (JOS), an immature to early mature, Upper Cretaceous to Paleogene source rock developed on the platform regions of central and southern Jordan. Diagenesis of biogenic silica led to silicification of the source rock interval and the growth of chert nodules. Localization of bitumen veins in reaction rims around these nodules is interpreted to indicate that silica diagenesis promotes the early mobilization of hydrocarbons from the geochemically identical, disseminated bitumen within the host mudstones. We propose a model in which early-formed bitumen migrated into neoforming mode I fractures that formed as a result of the crystallization pressure imposed from the growing chert nodule. Hydraulic fracturing occurred under elevated bitumen fluid pressures that approached lithostatic stress values under burial depths of the order of 1000 m. The recognition that silica diagenesis can promote the early migration of neoforming bitumen raises the possibility that primary hydrocarbon migration may occur earlier and at shallower depths than predicted by kinetic modeling approaches wherever silica diagenetic reactions are coeval with catagenesis.

Genesis and role of bitumen in fracture development during early catagenesis

Bitumen-bearing fractures and vugs were investigated in the highly organic-rich Jordan oil shale (JOS) of Late Cretaceous–Eocene age, which has potential as a highly fractured, unconventional hydrocarbon play. Bitumen is present as macroscopically visible deposits, and as inclusions in the cement of abundant natural fractures and adjacent vugs. The frequency of bitumen occurrence in fractures closely correlates with total organic carbon (TOC) and burial depth. Petrographical and organic-geochemical analyses on bitumen samples extracted from fractures and their host-rock matrix show that the fracture-filling bitumen comprises indigenous low maturity hydrocarbons derived from the surrounding organic-rich oil shale and has not migrated from a deeper source. Maturity indicators imply that the oil shale is in the pre-oil generation stage of early catagenesis throughout the investigated area, but with a regional increase in thermal maturity from west to east as the result of greater maximum burial depth. Bitumen mobilization in the host rock was mainly controlled by vertical loading stress acting on the non-Newtonian bitumen phase in load-bearing configurations in the organic-rich matrix. Bitumen fractures were developed by hydraulic fracturing as the result of fluid overpressure in the organic matter. Overpressured bitumen has acted as a fracture driver, generating bitumen veins in both the organic-rich mudstones and the adjacent chert and silicified intervals. Supplementary material : A summary of core data and photographs of the fracture bitumen and matrix bitumen are available at https://doi.org/10.6084/m9.figshare.c.4602290 Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs

High Throughput Screening and Characterization Methods of Jordanian Oil Shale as a Case Study

Oil shale is an important possible solution to the problem of energy in Jordan. To explore the technical and the economic feasibility of oil shale deposits, numerous samples are analyzed using the standard Fischer Assay (FA) method. However, it would be useful to develop faster, cheaper, and reliable methods for determining the oil content of oil shale. Therefore, the aim of this work was to propose and investigate rapid analytical techniques for the screening of oil shale deposits and to correlate them with the FA method. The Omari deposit located east of Jordan was selected as a case study for analysis using thermogravimetric analysis (TGA) coupled with Fourier-transform infrared (FTIR), differential scanning calorimetry (DSC), elemental analysis, X-ray fluorescence (XRF), X-ray diffraction (XRD), scanning electron microscopy (SEM), and energy-dispersive X-ray (EDX) analysis. Results obtained from the TGA method were linearly correlated with FA with high regression factor (R2 = 0.99); a quadratic correlation (R2 = 0.98) was maintained between the FA and the elemental hydrogen mass content, and a quadratic correlation (R2 = 0.97) was found between the FA and the aliphatic hydrocarbons (FTIR peak at 2927 cm−1) produced in the pyrolysis zone. Although other techniques were less correlated, further investigation might lead to better results. Subsequently, these correlated techniques can be a practical alternative to the conventional FA method when, in particular, specific correlation is made for each deposit.

Groundwater risk assessment investigations for oil shale exploitation in El-Lajjun area of central Jordan

Oil shales are sedimentary rocks that contain organic material in its inorganic matrix. The oil shale deposits of Jordan have been investigated since the 1960s. An extensive investigation studies have been commenced to evaluate the quality and quantity of these resources. In 2006, the government of Jordan invited pioneer companies in oil shale field to submit their proposal to utilize and develop the oil shale of Jordan using different extraction technologies. Jordan is considered one of the driest countries in the world, which poses an additional challenge for oil shale development, because a vast quantity of water is needed for this process. El-Lajjun study area is located in central Jordan; the oil shale in the study area was deposited in marine environment; it comprises massive beds of brown-black, kerogen-rich, bituminous chalky marl. Ten representative oil shale rock samples were collected for risk assessment investigations from different localities of oil shale exposures. A standardized laboratory Fischer assay test delivered oil shale characteristics. Sequential extraction was used to evaluate mobility and distribution of the trace elements Ti, V, Cr, Co, Zn, As, Zr, Cd, Pb, and U. Column leaching experiments were performed to simulate the leaching behavior of the above elements from oil shale and spent shale to evaluate the possible negative impact on groundwater in the study area. Results of sequential extraction indicate that concentration of trace elements and trace elements are richer in oil shale and in the spent shale compared to most rocks and soils. The concentrations in the leachate were below the maximum contaminant levels of the Environmental Protection Agency (EPA) and the Jordanian standards for drinking water. The significance of this study lies in that its utilizes for the first time the sequential extraction and column leaching techniques to investigate the Jordanian oil shale rocks.

Low temperature retorting of Jordanian oil shales using semi-continuous apparatus

Two oil shales from Jordan, El-Lajjun (EL) in the centre of the country and Isfir Al-Mahata (IA) in the south, have been analysed by elemental analysis, XRF, XRD, FTIR, TGA and 13C NMR. Both oil shales have high S contents and atomic H/C ratios. The calorific value of EL (1630 ± 10 kcal/kg) was similar to that of IA (1571 ± 13 kcal/kg). IA has higher moisture content (7.1 ± 0.3 wt% db) than EL shale (0.7 ± 0.2 wt% db); higher CaCO3 content (XRF, XRD) and lower P content (XRF, XRD). FTIR and 13C NMR indicated a high content of aliphatics for both oil shales, especially for IA shale. These oil shales have been pyrolysed at 300 °C and 320 °C for 7, 14 and 21 days under a constant flow rate of N2. The lower-temperature, long-time reaction yields and analyses of the products were compared with those obtained from the standard Fischer Assay method (520 °C for 90 min). EL oil shale was less reactive than IA oil shale, particularly at lower reaction time. For both oil shales, as the reaction time increased from 7 to 21 days, the oil yield increased to 83–90 wt% of the Fischer Assay oil yield.Fischer assay and lower-temperature, long-time reaction products were analysed using gas chromatography-mass spectrometry (GC–MS) and 1H NMR. The GC–MS results for both shales showed that all the reaction products were similar and of high aliphatic content. Higher diesel fraction was obtained for 21 day reactions at 320 °C. Homologous series of sulfur-containing organic compounds (thiophenes and benzothiophenes) were present in considerable amounts in both EL and IA reaction products. The 1H NMR measurements suggested that the Fischer assay and long-time, lower-temperature reaction products all had high aliphatic content, matching the results obtained from GC–MS measurements.

Characterization of Jordanian oil shale and variation in oil properties with pyrolysis temperature

Marine oil shale from the Sultani mine was characterized (ultimate and proximate analysis, 13C NMR, differential thermogravimetry (DTG)). The 13C NMR indicated that the shale is highly aliphatic, and the concentration of carbonyl carbon is small. DTG indicated a total weight loss of 21 wt% to 550 °C. The shale was pyrolysed to different final temperatures in the range 360–540 °C under N2 and the shale oils produced characterized by utilization parameters (API, heating value, boiling point distribution) and by chemical properties (1H-NMR and gas chromatography-mass spectrometry GC–MS) as a function of final pyrolysis temperature. Previous studies have only investigated the utilization properties of marine-shale oil at one temperature. The average oil yield increased with pyrolysis temperature to a maximum at 520 °C, and then fell. The oil density was higher at 440–520 °C than at 360–400 °C (0.99–1.00, 0.96−0.97 g/cm3 respectively). Unexpectedly, oil heating value (39.7–40.0 MJ/kg in 360–540 °C) and sulfur content (11.25 wt% in 360–520 °C) were independent of pyrolysis temperature. Oil distillation indicated that up to 90 vol% was in the diesel fraction.1H-NMR implied that the oil produced at all temperatures was highly aliphatic. GC/MS for the oil indicated the presence of long chain hydrocarbons (C11-C32), both normal and branched, some substituted benzenes, and high concentrations of sulfur compounds, mainly substituted thiophenes with same benzothiophenes. The average molecular weight of the sulfur compounds and proportion of heavier oil were higher at 520 °C than at 460 °C, so that the increased yield of oil at higher temperatures would have to be balanced against the lower quality of the crude shale oil produced. The results emphasized the importance of studying oil properties as a function of pyrolysis temperature, as differences which could be important in practice were noted.

Maastrichtian to early Paleocene sea level changes and climatic evolution on the southeastern Tethys margin

Abstract An integrative multi proxy approach based on lithology, microfacies, bulk rock composition, total organic carbon (TOC), and δ13Ccarb was used to estimate southeastern Tethys sea level fluctuations during the deposition of the Maastrichtian-Danian oil shales in Jordan. Clay mineral assemblages were used as proxies to determine climatic variation induced sediment supply during the Cretaceous/Paleogene boundary (K/Pg) interval. The results from two cores (OS-02, Jafr Basin, southeast Jordan; OS-28 Azraq-Hamza Basin, central-east Jordan) reveal four major intervals of distinctive bulk rock composition reflecting sea level changes. Interval I (earliest Maastrichtian) with a low sea level and the formation of dolomites and a high detrital quartz input predates the oil shales. Intervals II and III in core OS-02 and interval II in core OS-28 represent the highest relative sea level following the Early Maastrichtian sea level rise on the Arabian Platform. Intervals III (core OS-02) and II (core OS-28) coincide with the highest organic matter deposition. Interval IV (core OS-02) and intervals III and IV (core OS-28) relate to the sea level regression-transgression cycle in the latest Maastrichtian through Danian and are marked by a large drop in the TOC content. Increased terrestrial influx during sea level lows is evident from two peaks/intervals of major negative δ13Ccarb values in core OS-28. Based on clay mineralogy it can be differentiated between warm/humid, warm/cool seasonally alternating, and cool/arid climates. When bulk rock composition is used as a sea level proxy, clay mineral assemblages from both cores reveal the dominance of warm and humid climate or, alternatively, warm/cool seasonal alternations during high sea levels (II and III core OS-02; II and IV core OS-28), while periods of arid and cool climate correspond to lower sea levels. The sea level changes and climatic variations deduced from the Jordanian oil shale successions are in agreement with the long term variations from the Egyptian Western Desert sections (southeastern Tethys), and the Tunisian El-Kef section (southweastern Tethys). Moreover, the sea level changes identified relate to the regional changes on the Arabian platform during the Maastrichtian-Danian.

Producing geopolymer composites using oil shale ash

The potential of producing geopolymer (GP) composites using Jordanian oil shale ash (OSA) was investigated. Twelve GP mortar mixtures were prepared using OSA and different proportions of commercially available alkaline activator, composed of sodium silicate and sodium hydroxide. Prismatic specimens (40 × 40 × 160 mm), attained satisfactory workability, were left at laboratory air for 24 hr, then demolded and dry cured at different practical temperatures (60–100 °C) for 24 and 48 hr before left in laboratory air and finally tested for strength and capillary porosity. Furthermore, SEM analysis was carried out on matured GP mortar samples to determine the extent of OSA polymerization and status of pore system. The results indicated the potential of producing GP mortar using OSA with strength grades of as high as 20 MPa. Dry curing at 60 °C for 24 hr imparted the best mechanical and durability properties of OSA‐based GP mortar. The internal pore structure showed excellent correlation with mechanical and durability properties of produced GP composites.

Thermogravimetric and composition analysis of Jordanian oil shale

ABSTRACTJordan occupies the eighth place in oil shale reserve in the world. Prospective efforts are directed toward the production of fuel from shale. Analysis of oil shale samples will help in planning for energy strategies. Oil shale samples were collected from Wadi Ash Shallala at Yarmouk Basin. X-ray fluorescence spectrometer and X-ray diffraction showed that calcite is the dominant mineral. Other minerals such as; Kaolinite, quartz, and Fluorapatite, were detected. Thermogravimetric analysis revealed that mass loss is due to organic matter decomposition at 350–550°C and carbonate and silicate decomposition at 650–850°C. Fourier transform infrared analysis revealed the main organic groups.

Oxyfuel technology: Oil shale desulfurization behavior during staged combustion

A high sulfur content in Jordanian oil shale is considered one of the biggest challenges preventing its full utilization. To resolve this issue, direct limestone injection during staged combustion has been investigated for the simultaneous control of NO and SO2 emissions. Staged El-Lajjun oil shale combustion under oxyfuel conditions and conventional air-firing conditions was performed at 1200°C in a 20-kW vertical reactor. Limestone was mixed with oil shale before combustion. Three different molar ratios of Ca/S, three different burner oxygen ratios (0.75, 0.85 and 0.95) and different positions of the burnout oxidant probe were tested in both firing conditions to determine the optimum conditions for the lowest SO2 and NO emissions. The SO2 emissions were significantly lowered by adding limestone during staged air-firing and OF27 (27% O2/73% CO2 environment) combustion. The desulfurization efficiencies ranged from 32 to 61% and from 25 to 60% during the staged air-firing and staged OF27 combustion, respectively. The staging level, the Ca/S molar ratio and the position of the secondary oxidant are important parameters that affect the desulfurization efficiency. Higher desulfurization efficiencies were obtained during OF27 combustion compared with air-firing at burner oxygen ratios of 0.85 and 0.95. At a burner oxygen ratio of 0.75, the opposite trend was observed. The SO2 emissions during staged combustion were significantly higher than those during unstaged combustion in air and during OF27 combustion. This was due to high competition among many reactions, which minimized the desulfurization efficiency. The maximum desulfurization efficiency during staged OF27 combustion was 60% with λ=0.85 and Ca/S=2 at 1m from the burner. During air-firing combustion, the maximum desulfurization efficiency was 61% with λ=0.85 and Ca/S=3 at 1.5m from the burner. Based on the current and previous studies, the authors recommend that oxyfuel technology be used for oil shale combustion so that CO2, SO2 and NOx emissions can be simultaneously controlled.

Two-dimensional numerical modeling of combustion of Jordanian oil shale

ABSTRACTA two-dimensional (2-D) modeling of the burning process of Jordanian oil shale in a circulating fluidized bed (CFB) burner was done in this study. The governing equations of continuity, momentum, energy, mass diffusion, and chemical combustion reactions kinetics were solved numerically using the finite volume method. The numerical solution was carried out using a high-resolution 2-D mesh to account for the solid and gaseous phases, k-ε turbulence, non-premixed combustion, and reacting CFD model with the same dimensions and materials of the experimental combustion burner used in this work. The temperature distribution and evolution of species were also computed.Proximate and ultimate analyses were also performed to evaluate the air–fuel ratio and ash content. The required thermophysical properties, such as heating value, density, and porosity were obtained experimentally, while the activation energy was obtained from published literature.It was found that the temperature contours of the combustion process showed that the adiabatic flame temperature was 1080 K in a vertical burner, while the obtained experimental results of maximum temperature at various locations of the burner in actual, non-adiabatic, non-stoichiometric combustion reached 950 K, showing good agreement with the model.

Organic geochemical and petrographic characteristics of the oil shales in the Lajjun area, Central Jordan: Origin of organic matter input and preservation conditions

Oil shales, located in Lajjun area (Central Jordan), were analyzed based on organic geochemistry, coupled with microscopical study to define the origin, type of organic matter input, and the influencing factors that govern organic matter (OM) enrichment, including the OM preservation conditions. Oil shales are thermally immature petroleum-source rocks for oil that require artificial heating to generate oil of commercial value. The analyzed oil shales have high total sulfur content values in the range of 2.08–4.06wt%, and the organic carbon contents are also consistently high (>10%). The high total sulfur content and its relation with organic carbon values indicate that the Jordanian oil shales were deposited in a marine environment under reducing conditions. The organic matter input and paleoenvironmental conditions have also been evidenced from their biomarker distributions and microscopic study. The microscopical investigation indicated that the oil shales contain an abundant liptinitic organic matter (i.e., alginite, structureless (amorphous) and planktonic foraminifera). The presence of these liptinitic materials and planktonic foraminifera assemblages in the oil shale samples, further suggests a marine origin. Their biomarkers also provide evidence for a high contribution of marine plankton/algal and microorganisms and persevered under highly hypersalinity reducing conditions. The good preservation under reducing conditions contributes to the high amounts of organic matter enrichment during deposition of these oil shale sediments. Consequently, the Jordanian oil shales have very good oil generative potential, owing to high content of hydrogen rich Type I/II oil-prone kerogen.