Oil Shale Samples Research Articles

Kinetic modeling of Kukersite oil shale pyrolysis with thermal bitumen as an intermediate

In this work, the kinetics of oil shale pyrolysis was studied in a fixed bed retort with thermal bitumen as an intermediate. Kukersite oil shale samples were tested at temperatures ranging from 300 to 480 °C at the constant heating rate of 1 °C·min−1. Weights of kerogen, thermal bitumen, shale oil and gases were measured as functions of the final pyrolysis temperature, which were simulated using a first-order reactions in series model under non-isothermal conditions. The obtained kinetic parameters were also proven to accurately describe the experimental results. The proportional factors for products (fB = 0.658, fO1 = 0.183, fO2 = 0.890, fG1 = 0.157, fG2 = 0.106) indicate that kerogen decomposition mainly generates thermal bitumen accounting for 65.8% of total composed kerogen, and that thermal bitumen further degrades and mostly produces shale oil occupying 89.0% of total degraded thermal bitumen. Activation energies and pre-exponential parameters for the two steps are: 126.12 and 192.77 kJ·mol−1, 1.66 × 107 and 1.08 × 1012 s−1, respectively.

Biodegradation Effect on the Campanian Oil Shale of Egypt

In the present article, ten bacterial strains were isolated from two Campanian bulk shale samples from Abu-Tartur mine of the Western Desert and the Quseir area at the El-Nakheil area of Red Sea, Egypt. The characterization of these two samples was analyzed. Two of the bacterial isolated strains showed a higher growth rate on oil shale and these were selected for the biodegradation process. These bacterial isolates (B1 and B2) were identified using molecular identification performed by 16S rRNA gene sequences. The results indicated that two isolated bacteria belong to Bacillus flexus and Enterobacter cloacae. Gas Chromatographic analysis of the remaining oil shale in different culture medium after one week at 30 oC yielded optimum percentage biodegradation at 35.15% for the Abu-Tartur oil shale sample, while for the El- Nakheil oil shale sample was detected at 32.13%. The bacterial strain (B1) consumed more of the iso-paraffins than n-paraffins of saturates fraction in the Abu-Tartur oil shale sample. The complete utilization of some different polyaromatics membered rings and the highest percentage biodegradation of other polyaromatics were determined with two bacterial strains and different oil shale samples separately. From the results seems to be worthy biodegradation of oil shale samples trend.

The application of Nuclear Magnetic Resonance T1-T2 maps in the research of sedimentary organic matter: A case study of early mature shale with type Ⅰ kerogen

The Nuclear Magnetic Resonance (NMR) 2D T1-T2 map was widely used in shale resources for separation of the different proton contributions, and the obtained data provided lots of information for shale resources evaluation. However, the further work of its application in organic matter quantification and hydrocarbon generation research was quite limited. In this article, we used a low field NMR instrument working at a high frequency (15 MHz) to test isolated organic matter, raw oil shales and shale samples processed by pyrolysis respectively. The results indicated that the kerogen and bitumen could be distinguished by positions located in NMR 2D T1-T2 maps. The standard equations (the relationship between the signal intensity and the mass of isolated organic matter) with excellent linear relationship were established for firstly calculating the content of organic matter in oil shales. The results of NMR were almost identical with that tested by traditional methods. In addition, the NMR relaxometry measurements correlated well with geochemical properties of pyrolyzed oil shales obtained from Rock-Eval pyrolysis (S1 and S2).

Experimental investigation of the effect of temperature on thermal conductivity of organic-rich shales

Experimental data on thermal conductivity of hydrocarbon reservoirs and surrounding formations at elevated temperatures are important for a variety of purposes: determining heat flow density; designing and optimizing thermal methods of enhanced oil recovery (EOR); basin and petroleum system modeling; exploitation of geothermal reservoirs; and design of radioactive waste disposal. However, there is an acute shortage of such data at present, particularly for unconventional reservoir rocks. We helped to fill this data gap by using a new, sophisticated technique to carry out thermal conductivity measurements on 28 oil shale samples from various unconventional formations in a temperature range of 30–300°С. The formations studied were Bazhenov and Abalak (West Siberia, Russia), Mendym, Domanic, Sargaev and Timan (Volga-Ural, Russia). Divided-bar and optical scanning methods were combined in the thermal conductivity measurements in order to account for thermal anisotropy and heterogeneity of the rocks and improve quality of the experimental data. Application of the optical scanning technique enabled us to select representative full-diameter or split-core samples from the continuous thermal core logging data and to choose an optimal location for drilling of core plugs from the core samples for measurement of thermal conductivity at elevated temperatures, with due account for anisotropy and heterogeneity inherent to oil shales. This approach enabled us to reveal and overcome systematic errors in previous measurements of oil shale samples using the divided-bar method and to develop an approach for the correction of measurement results. The measurements of thermal conductivity of our samples at elevated temperatures found a 5–27% decrease of rock thermal conductivity with temperature increase from 30 to 300°С. New methodology of the rock thermal conductivity determining at elevated temperatures is reported that includes a combination of two instruments: Thermal Conductivity and Thermal Diffusivity Scanner and DTC-300. It allowed to account for the contact resistance, non-ideal form of rock samples prepared for study (nonparallelism of rock samples surfaces), and changes in rock samples structure after heating.

Thermal maturity evaluation using Raman spectroscopy for oil shale samples of USA: comparisons with vitrinite reflectance and pyrolysis methods

Thermal maturity is commonly assessed by various geochemical screening methods (e.g., pyrolysis and organic petrology). In this contribution, we attempt to establish an alternative approach to estimating thermal maturity with Raman spectroscopy, using 24 North American oil shale samples with thermal maturity data generated by vitrinite reflectance (VRo%) and pyrolysis (Tmax)-based maturity calculation (VRe%). The representative shale samples are from the Haynesville (East Texas), Woodford (West Texas), Eagle Ford and Pearsall (South Texas) Formations, as well as Gothic, Mancos, and Niobrara Formation shales (all from Colorado). The Raman spectra of disordered carbonaceous matter (D1 and G bands separation) of these samples were directly obtained from the rock chips without prior sample preparation. Using the Gaussian and Lorentzian distribution approach, thermal maturities from VR were correlated with carbon G and D1. We found that the Raman band separation (RBS) displayed a better correlation for equivalent VRe% than vitrinite reflectance VRo%. The RBS (D1–G) distance versus total organic carbon, free hydrocarbons from thermal extraction (S1), and the remaining hydrocarbon generating potential (S2) indicate that the RBS (D1–G) distance is also related to kerogen type. Data presented here from three methods of maturity determination of shale demonstrate that Raman spectroscopy is a quick and valid approach to thermal maturity assessment.

Utilization of Oil Shale as an Electromagnetic Wave Absorbing Material in the Terahertz Range

This study demonstrates that oil shale subjected to pyrolysis at 1000 °C strongly absorbs electromagnetic radiation in the terahertz (THz) range. Analyses reveal obvious differences between oil shale samples with and without pyrolysis, as well as between low-middle mature shale and oil shale samples. The electromagnetic absorption effect of oil shale subjected to pyrolysis conditions is demonstrated to be strongly related to its relatively small concentration of pyrite, which progressively yields pyrrhotite and elemental Fe during pyrolysis that facilitates the absorption of THz radiation. Accordingly, oil shale can be used not only as a resource for generating oil, natural gas, and petrochemical products, but the material obtained after processing can also be employed for the absorption of THz radiation as a means of converting incident electromagnetic radiation into heat or other forms of energy, which offers substantial prospects in many engineering and technology applications.

Energy consumption and product release characteristics evaluation of oil shale non-isothermal pyrolysis based on TG-DSC

Thermogravimetric-Differential Scanning Calorimetry Analysis (TG-DSC) was applied to study non-isothermal pyrolysis characteristics of oil shales, such as the starting point, stability, pyrolysis interval and product release using Fuyu and Huadian oil shale samples. Results show that with the increase of heating rate, oil shale pyrolysis moves to higher temperature zone. This trend is more noticeable at higher oil content. The pyrolysis stability of the oil shale is related to oil content and pyrolysis atmosphere. The higher the oil content, the more stable the pyrolysis of the oil shale. Under nitrogen atmosphere, the pyrolysis interval of oil shale is more concentrated, air prolongs the pyrolysis interval, and the pyrolysis stability index decreases. In addition, the increase of heating rate favours the release characteristic index of the product, which is not practically affected by oil content. The release characteristic indices of pyrolysis products from oil shale under nitrogen atmosphere are higher than those under air atmosphere. The optimum heating rate that produces the highest oil product yield for pyrolysis progress of Huadian oil shale is 20 °C/min, and Fuyu oil shale is 40 °C/min.

Investigation of Organic Matter Content of Hungarian Oil Shale and Its Influence on Sorption of 2,4-Dichlorophenol

It is not only Total Organic Carbon content (TOC) but also the type of Organic Matter (OM) that the sorption of organic pollutants by soils or other natural absorbents is correlated with. Therefore, the characterization of organic components in the adsorbents is very important to elucidate sorption mechanisms.Oil shale samples were collected in Pula, Hungary. The TOC content of the investigated samples was approximately 6.8-40.1 m/m %. The characterization of the organic matter in samples was carried out by using Scanning Electron Microscopy (SEM), elemental analysis, thermal analysis, and GC-MS technics. The results predominantly indicated the presence of a low degree of the branching of aliphatic chain components in the samples. The Humic Substances (HS) content of the samples was only 1-6 m/m %, which could be determined after the treatment of oil shale with hydrogen peroxide.The influence of the amount and type of organic material in oil shale samples was studied on the adsorption of 2,4-dichlorophenol (2,4-DCP) as a model contaminant. For this aim a series of batch equilibration experiments was carried out. The results show that the total organic carbon content of samples is a strong indicator of 2,4-DCP adsorption, while the HS content is an important feature controlling sorption capacity. The study suggests that the special organic matter (kerogen) content of the oil shale plays a major role in its high adsorption capacity and in the nonlinearity of the isotherms. The HS covering the surface could decrease the sorption capacities despite the fact that though the amount of this organic material is quite low.

A pilot investigation of pyrolysis from oil and gas extraction from oil shale by in-situ superheated steam injection

Oil shale is a critical strategic energy with huge reserve. The research and development of an economically feasible in-situ retorting technology for oil and gas extraction from oil shale is of great significance. Thus, this paper experimentally studied the large oil-shale samples pyrolysis by in-situ superheated steam injection (MTI) implemented from 2014 to 2016. The structure of the large-scale in-situ pyrolysis test system, the experimental procedure, and the results are presented here. The steam fracturing-connection was used during the initial stage, and the pressure of the superheated steam for fracturing was ~2 times higher than the strata stress. The variation of temperature and pressure during pyrolysis was controlled by the variation in steam seepage. The operating steam pressure during pyrolysis was lower than 1/4 of the strata stress. The energy utilization of the superheated steam for the pyrolysis reaction was 42.7%. The average temperature of the fluid that was discharged from the production wells was around 170 °C, which can be recycled to achieve a heat-utilization coefficient of 13.19% in commercial operations. The oil-recovery rate in the pyrolysis area exceeded 95%, and the overall oil-recovery rate reached up to 70.7% of the tested large oil-shale samples. The gas production rate and the effective energy rate of the injected steam are correlated with an exponential function. Our pilot tests indicate that the in-situ retorting technology of oil shale by MTI shows great potential for commercial operation in oil-shale formation.

Rhenium and selenium in the Upper Jurassic shale of the “Gorodishchi” section, Central part of the Volga shale basin

Research subject. This article presents new data on the content of rhenium (Re), selenium (Se) and a number of other rare elements in the rocks of the Gorodishi section located in the Central part of the Volga basin shale (upper Jurassic) in the South-East of the Russian plate. In this section, rocks are rich in organic matter (15–37 % wt in oil shale) and contain layers of oil shale with a thickness of up to0.7 m.Materials and methods. The description and layer-by-layer testing of the Gorodishchi section was performed. Sulphides were isolated from two samples of carbonaceous shale for subsequent analysis. In the selected samples and isolated sulphides, the contents of Re, Se and a number of rare elements were determined at the VSEGEI central analytical laboratory. For the first time, the chemical composition of the samples was determined by ISP-MS using an Agilent 7700h device.Results. Oil shale samples demonstrated the highest concentration of Re and Se, with the concentration of Re and Se being on average 0.13 g/t (ranging from 0.09 to 0.19) and 10.39 g/t (from 6.54 to 12.4), respectively. A statistical analysis of the data obtained (using principal component factor analysis) revealed a close relationship of Re and Se both with the rock organic matter and with Cu, Cd, U, Ag.Conclusions. Anomalously high concentrations of Se and high concentrations of Re revealed in the oil shale of the section under study testifies to the need for specialized mineralogical and geochemical studies of the upper Jurassic carbon shale of the Central part of the Volga basin shale in terms of Re and Se content.

An investigation on the feasibility of using mixed Reversible ionic liquids for extraction of Kerogen from oil shale

Numerous of the separation issue usually accompanying with traditional ionic liquids can solve with Reversible ionic liquids. It can be forth and reversed back between ionic and molecular forms empowering superficial separations by means of considerable changes in situ property. This leads to actually sustainable processes. A comprehension of the systems phase behavior gives frameworks into the ability of separation.To our knowledge, the experimental information available in the literature for mixtures containing the pair Kerogen-Reversible Ionic Liquids (RevIL) is limited. Thus the objective of the current investigation is to produce data for Kerogen with different Reversible Ionic Liquids RevIL solvents to aid the extraction efficiency.The samples of Oil Shale collected from real Iraqi sedimentary rock deposits. Four Reversible Ionic Liquids solvents 3-(triethoxysilyl)-propylammonium 3-(triethoxysilyl)-propyl carbamate (TESAC), (3-(tripropylsilyl)-propylammonium 3-(tripropylsilyl)-propyl carbamate (TPSAC), 3-(trimethoxysilyl)-propylammonium 3-(trimethoxysilyl)-propyl carbamate (TMSAC), 3-(triethylsilyl)-propylammonium 3-(triethylsilyl)-propyl carbamate (TEtSAC)) are derived from carbon dioxide which reacts reversibly with silylated amine molecular liquids to produce ionic liquids.The efficiency of four Reversible Ionic Liquids (TEtSAC, TMSAC, TPSAC, and TESAC) and for mixed Reversible ionic liquid (Binary mixtures) as a selective solvent in the kerogen extraction from oil shale was investigated.The extraction efficiency was found to be more dependent on the basicity strength of hydrogen bond of the RevIL. It was found that higher extraction efficiencies are accompanied with higher hydrogen bond basicity.Four single RevILs and three binary mixtures (RevIL) to extract the Kerogen from oil shale is used. The study shows that the highest Kerogen extraction efficiency of 90.2% and 97.9% respectively, can be achieved by TESAC and (TESAC + TMSAC) respectively. One mixed binary solvent (TESAC + TMSAC) has the highest distribution coefficient, extraction efficiency and selectivity and greatest variation between its density and boiling point and those of Kerogen is selected. Therefore it can be considered as an excellent extracting solvent for Kerogen from oil shale.

Geochemical characterization and artificial thermal maturation of kerogen density fractions from the Eocene Huadian oil shale, NE China

Oil shales are an important alternative energy resource, through retorting, for the production of liquid hydrocarbons. A key factor in determining the value of an oil shale resource is its hydrocarbon generation potential; particularly its maceral distribution. To examine this, single maceral concentrates were obtained from a 1 kg Eocene Huadian oil shale sample using float-sink separation of chemically demineralized kerogen. Nine different density fractions were separated: the Botryococcus fraction occurred in the lightest (<1.06 g/mL) material, lamalginite in the 1.06–1.23 g/mL fraction, while detrovitrinite dominated in a higher density fraction (1.26–1.36 g/mL), which also contained some lamalginite.Rock-Eval S2 and hydrogen index (HI) parameters, as well as the aliphatic compound peaks in Fourier transform infrared (FTIR) spectra, all decreased with increasing kerogen density, whereas the Rock-Eval oxygen index and the aromatic compound peaks in FTIR spectra, increased. The δ13C values showed slight variations within the different density fractions. The δ13C value of parent shale kerogen was very close to that of the density fraction dominated by lamalginite (−25.1‰), because the sample is dominated by lamalginite macerals (>70%). The Botryococcus sp. fraction is isotopically enriched because Botryococcus sp. is typically significantly enriched in 13C (δ13C = −24.6‰).Artificial thermal maturation hydrocarbon generation results show that absolute hydrocarbon gas yields were similar among the different density fractions. The 1.06–1.12 g/mL fraction, dominated by lamalginite, generated nearly twice as much liquid hydrocarbons as the 1.26–1.30 g/mL fraction dominated by detrovitrinite. The maximum hydrocarbon yields corresponded well with the Rock-Eval HI values. Calculated by the relationships among HI, detrovitrinite and alginite compositions, the HI is 909 and 177 mg HC/g TOC for the purified alginite and detrovitrinite fractions, respectively. Kinetics analysis shows that Ea (activation energy) is higher for the low-density fraction (1.06–1.12 g/mL) than that for the heavy fraction (1.26–1.30 g/mL), indicating that lamalginite not only has a much better hydrocarbon generation potential, but also higher thermal stability. Therefore, this lamalginite-rich oil shale is well suited for exploitation by retorting, even though the retorting temperature would be higher than for detrovitrinite-rich fractions.

Mechanical properties of oil shale-coal composite samples

In this study, uniaxial compression tests were conducted on the composite samples of coal and oil shale characterised by high strength and low elastic modulus. Their fracturing and failure propagation processes were monitored by an acoustic emission (AE) device and a digital video camera. The strength, macro-failure initiation (MFI) and failure characteristics of composite samples are analysed. Differences in mechanical properties between the coal and oil shale influence the stress states near the interface area, resulting in strength increasing in the coal and strength decreasing in the oil shale. Strength characteristics of composite samples mainly depend on the strength σC of the coal far away from the interface, which is influenced by the coal's original defects and interactions with the oil shale. The large deformation of oil shale reduces the damage accumulation in the coal and the strengths of relatively intact composite samples are greater than σC; in contrast, the strengths of composite samples with more coal's original defects are low and less than σC. MFI occurs within the coal, causing a step-wise stress change accompanying the peak signal of the energy index and representing the beginning of macro-failure in composite samples. MFI models include the tensile fractures of coal near the interface, initiation and propagation of coal's original cracks, and surface spalling between coal's original cracks. The local ejection or surface spalling failure in the coal induces the chain destruction of its peripheral parts to form a large ejection or surface spalling failure zone. Finally, the coal displays the splitting ejection failure or shear failure along the original crack surface. The oil shale is destroyed through the tensile failure or mixed failure by crack propagation in the coal.

Fractal characteristics and significances of the nanopores in oil shales during hydrous pyrolysis

In order to explore the pore characterizations in shales during organic matter evolution, a series of simulation experiments were conducted. The artificial hydrous pyrolysis was conducted on the same seven columned oil-shale samples at 250 °C, 300 °C, 350 °C, 375 °C, 400 °C, 450 °C and 500 °C, respectively. To obtain the characteristics of pore structures in shales, the unheated and the residual solid samples were analyzed by low-pressure nitrogen adsorption method. Based on the nitrogen adsorption isotherms, fractal dimensions were calculated by the model of Frenkel–Halsey–Hill, which also contained the fractal dimension of D1 and D2 before and after the relative pressure P/Po = 0.5, respectively. And then the relationships of simulation temperatures (thermal maturity), total-, macro-, meso- and micro-pores volumes, specific surface areas and diameters to fractal dimensions were investigated. The results showed that the average value of D2 (2.6110) was higher than D1 (2.4147) and there was a positive relationship between them (R2 = 0.9237), which indicated that though D2 and D1 were more related to pore structures and surfaces, the better linear relationships suggested that both of them could be used in the representation of pore structures and surfaces in shales. With the thermal maturity increasing, the obvious fractal characteristics were, the complexity of pore structures were, which may be associated with the following cause-and-effect relationships. During the pyrolysis, the generation of hydrocarbons increased, as well as the consumption of TOC may increase the volume and surface area of total-, macro-, meso- and micro-pores but decrease the corresponding average diameter and then the quantities of smaller pores occurred and led to the strengthening of pore heterogeneity in shales. Based on the fractal characteristics, we also found the higher thermal maturity would result in the better connections among pores but worse permeability in shale, which further increased the gas adsorption quantity. Therefore, analyzing the fractal characteristics in shales could provide help for clarifying the characteristics of reservoirs as well as the comprehensive exploration and development of shale gas.

Coupled Numerical Simulation of Thermal-Reactive Flow and Geomechanics with Solid Mass Conversion

Summary An extension of the novel fully coupled thermal-hydromechanical (THM) open-system geomechanics (OSG) model is developed for the analysis of coupled flow and oil-shale geomechanics. The model is cast within the framework of Biot's elasticity and classical thermoelasticity. A new term in the equations accounting for the effects of pyrolysis is included in the present model to capture the removal of mass from the reactive solid phase because of the kerogen-conversion process modeled through a simplified chemical-reaction model. The proposed novel formulation approach and its numerical implementation differ from traditional methods and offer a step improvement in the geomechanical modeling of thermally reactive porous media, such as oil shales. The numerical implementation of the OSG model, a first in the literature, is developed within the framework of a proprietary coupled thermal-reactive flow and geomechanics simulator, which was extensively validated in a previous publication. In this paper, we compare the thermal-reactive OSG model against experimental measurements. Numerical results from the validation test show that the model captures the fundamental physical behavior of oil-shale geomechanics realistically and correctly. Parametric analyses of the OSG model indicate that the chemical conversion term is the critical term that dictates the magnitude of compaction in the solid equation, and a further investigation illustrates the importance of the mobility term in the pore-pressure buildup. It is also noticed that the initiation and the rate of compaction of the oil-shale sample are governed by the chemical activation energy and the reaction-rate constant.

Petrology and geochemistry of migrated hydrocarbons associated with the Albert Formation oil shale in New Brunswick, Canada

Samples of the Carboniferous oil shale of the Albert Formation in New Brunswick, Canada, were examined using reflected white and fluorescence light microscopy, Rock-Eval pyrolysis, and ICP-MS (for elements). The presence of fractured filled solid bitumen in contact with and within the Albert Formation oil shale indicated that migrated oil had enough force to overcome the tensile strength of oil shale matrix and penetrate the oil shale. Migrating fluid caused thermal alteration of the matrix as evident by the presence primary bitumen and oil droplets. The evidence of oil migration included the presence of solid bitumen and crystalline carbonates in contact with the oil shale. The low permeability oil shale acted as a seal/aquitard and created a diagenetic ‘front’ by slowing the advance of migrating oil, resulting in the formation of a reaction zone. Migrated solid bitumen consisted of both soluble solid bitumen types such as gilsonite and glance-pitch, and insoluble solid bitumen such as wurtzilite and albertite. The variation of Th/K ratio and TOC (wt%) indicates that most of oil shales from the Albert Mine area and within the vicinity of oil migration have higher content of TOC (17–25 wt%) compared to the other Albert oil shales (TOC = <10%). The oil shales examined were immature to marginally mature and had a wide range of hydrocarbon yield (2–213 L/Tonne). The highest hydrocarbon yield range (66–199 L/Tonne) was associated with outcrop samples collected in the Albert Mine itself, where the oil shale was heavily impregnated by migrated solid bitumen.

Experimental investigation on the physical and mechanical properties deterioration of oil shale subjected to freeze-thaw cycles

The exploration and utilization of oil shale have drawn much attention during the past decades around the world. To better understand the mechanical behavior of oil shale in the Junggar Basin, northwestern China, laboratory tests were conducted on five series of oil shale samples collected from different sites to investigate the effect of water on deteriorated rocks due to freeze-thaw weathering. The petrographic analysis and geochemical analysis were carried out, followed by the freezing-thaw (F-T) cycle test ranged from 10 times to 40 times with the increase of 15 times. All samples were frozen in a temperature-controlled freeze cabinet at − 20 °C and then thawed in distilled water at 20 °C. The deterioration of the samples was explored by the observation of the loss of weight and decrease of uniaxial compressive strength through some typical technical methods including scanning electron microscopy (SEM) and X-ray diffraction (XRD) analysis on the selected samples. Experimental results show that the uniaxial compressive strength is significantly affected by the increase of F-T cycles. The test results also indicate that the microstructure, in particular the minor cracks, is one of the main factors controlling the deterioration procedure of oil shale subjected to F-T cycles.

Geochemical characteristics of Early Cretaceous marine oil shale from the Changshe Mountain area in the northern Qiangtang Basin, Tibet: Implications for palaeoweathering, provenance, tectonic setting, and organic matter accumulation

The Early Cretaceous Shengli River–Changshe Mountain marine oil shale belt, located in the northern Qiangtang Basin, Tibet, is estimated to be the largest marine oil shale resource in China. However, its palaeoweathering, provenance, and tectonic setting during the depositional history have received little interest. In this paper, 19 outcrop marine oil shale samples from the ChangsheMountain (CSM) area were studied to investigate the provenance, palaeoclimate, palaeoweathering, and tectonic setting during the marine oil shale deposition. The total organic carbon and organic sulphur contents of the CSM oil shales range from 2.2% to 13.44% and 0.19% to 1.08%, respectively. The CSM oil shale samples contain abundant carbonate (e.g., calcite and dolomite), quartz, and clay minerals. The clay minerals of the CSM oil shale samples is dominated by illite and then by smectite. Other minerals, including haematite, apatite, pyrite, baryte, and celestite, were also identified by scanning electron microscope–energy‐dispersive X‐ray spectrometer. The total rare earth element (∑REE) contents of the oil shales range from 9.01 to 105.96 ppm (average 57.56 ppm), close to the average REE contents of U.S. coals. The REE contents in oil shale samples are mainly controlled by terrigenous input. The CSM oil shales show LREE‐enriched, HREE‐depleted, with the LREE/HREE ratios ranging from 5.12 to 10.18, negative Eu anomalies (0.56–0.84) and slightly negative Ce anomalies (0.87–1.05). The chemical index of alteration values of the CSM oil shales range from 67 to 76 (average 73), indicating a moderate chemical weathering condition. Sr/Cu and Rb/Sr ratios suggest the CSM oil shales were mainly deposited under a warm and humid climate regime. Sr/Ba ratios, ranging from 0.54 to 7.84, suggest a palaeoenvironment with fluctuant salinity. Major element, trace element, and REE relationships indicate that the CSM oil shales are mainly from the felsic and intermediate igneous rocks. The REE distribution patterns of the CSM oil shales are similar to the Late Triassic Nadi Kangri felsic volcanic rocks in the Qiangtang Basin, indicating that the CSM oil shale may be derived from the Late Triassic volcanic rocks and the oil shales were mainly formed in rift tectonic setting. Favourable preservation condition (e.g., warmer palaeoclimate, higher palaeosalinity, and dysoxic to anoxic water column environment) could be the main controlling factor for organic matter accumulation.

Statistical analysis of Egyptian oil shale column flotation

ABSTRACT Evaluation possibility of a low-quality Egyptian oil shale from Wadii El-Nakhil, Red sea region as an alternative clean fuel by advanced flotation technique via column flotation was investigated. XRD analysis showed that the non-clay minerals associated with the oil shale sample include; quartz, siderite, apatite, anhydrite, and calcite. Column flotation experiments were carried out and results were analyzed according to screening designs which are used when numerous parameters would affect a particular process. Reduced three-factor interactions (3 FI) two-level factorial experimental design were employed to evaluate the effects of the seven independent parameters. Besides, the contour plots were used to summarize the optimum reaction factors leading to a predicted maximum kerogen grade of 52.35% and kerogen recovery of 78.41%. The calculated optimum parameters were 15% solid concentration, 0 cm/s superficial wash water velocity, 0.49 cm/s feed superficial velocity, 40 ppm frother concentration, 40 cm froth depth, 0.67 cm/s superficial air velocity and 0.5 kg/ton kerosene collector dosage. The confirmation tests, at optimum conditions as predicted from the contour plots, gave approximately the same grade and recovery of about 54% and 80%, respectively.

Investigation of different chemical modifiers based on the Pd/Mg mixture for the determination of sulfur in shale oil by high-resolution continuum source graphite furnace molecular absorption spectrometry

This study investigated different combinations of Pd/Mg, as chemical modifier, for sulfur determination, via CS molecule, in shale oil samples by high-resolution continuum source graphite furnace molecular absorption spectrometry (HR-CS GF MAS). It was evaluated the mixture Pd/Mg in aqueous solution, Pd/Mg in propan-1-ol and the Pd/Mg in propan-1-ol plus Ru as a permanent modifier. The best sensitivity was achieved with Pd/Mg mixture in propan-1-ol. The high solubility of the samples in propan-1-ol promotes a better interaction with the modifier and, consequently, a more efficient thermal stability of the CS molecules. Due to the high sulfur content in the samples, the analytical line at 258.288 nm was used. Only a minimum sample preparation was required, i.e., a dilution in propan-1-ol by a factor of 1:10 (w/w). Temperatures of 800 °C and 2200 °C were the optimized conditions for pyrolysis and vaporization, respectively. The calibration curve was constructed with l-cysteine aqueous standard solutions. The characteristic mass was 27 ng; detection and quantification limits were 0.012% (w/w) and 0.039% (w/w), respectively. The accuracy of the proposed method was confirmed by the statistical agreement (Student's and Welch's t-test at 95% confidence level) using the certified reference material CRM NIST 1084a and an OTE oil sample whose sulfur content was previously determined by the standard method ASTM D4294. The method was successfully applied in three shale oil samples. The sulfur content in the investigated samples ranged from 1.0% (w/w) to 1.3% (w/w).