Sub-critical water extraction of Huadian oil shale at 300 Â°C

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Sub-critical water extraction of Huadian oil shale at 300°C Youhong Sun, Shijie Kang, Siyuan Wang, Li He, Wei Guo, Qiang Li, and Sunhua Deng Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b04431 • Publication Date (Web): 25 Feb 2019 Downloaded from http://pubs.acs.org on March 5, 2019

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Sub-critical water extraction of Huadian oil shale at 300°C Youhong Sun a, b, Shijie Kang a, b, Siyuan Wangc, d, Li He a, b, Wei Guo a, b, Qiang Li a, b, Sunhua Deng a, b, * a b

College of Construction Engineering, Jilin University, Changchun 130021, China Key Laboratory of Ministry of Land and Resources on Complicated Conditions Drilling Technology, Jilin University, Changchun 130021, China

c Interuniversity

d

Institute for Marine Science – Eilat, POB 469, Eilat 88103, Israel

The Freddy and Nadine Herman Institute of Earth Sciences, Edmond J Safra Campus, Givat Ram, Hebrew

University of Jerusalem, Jerusalem, Israel * Corresponding author. E-mail addresses: [email protected] (S. Deng); Tel.: +86-159-4802-2086.

ABSTRACT In this work, Huadian oil shale was extracted by sub-critical water at 300°C over different time periods to better characterize the underground mining of oil shale in-situ. The results revealed that the kerogen in the oil shale mostly transformed into bitumen through extraction over a long time period by sub-critical water at 300°C; however, a portion of the bitumen remained in the shale matrix. The yields of both bitumen 1 (the bitumen extracted out by sub-critical water) and bitumen 2 (the bitumen remained in the shale matrix) reached maximums at approximately 250 h. It should take a long time for bitumen 2 to be released because the ability of the transporting substrates of subcritical water was insufficient, the solubility of bitumen 2 was poor, and tiny fractures were generated in the oil shale matrix at such a lower temperature. The GC–

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MS analysis showed that the major components of bitumen 1 and bitumen 2 were similar and consisted of n-alkanes, n-alkanoic acids, n-alk-2-ones and isoprenoid alkane. Initially, kerogen decomposition produced a large number of n-alkanes with low molecular weights; however, as the reaction continued, comparatively higher molecular weight n-alkanes were obtained more. In addition, the bitumen underwent a secondary cracking in the sub-critical water, resulting in its decreased yield over time, while the contents of gaseous C2-C6 hydrocarbons increased. The organic matter dissolved in the spent aqueous solution consisted of mainly paraffins, isoparaffins, cyclohexanone derivatives and phenolic derivatives. The analysis of the oil shale residue showed that minerals were less reactive in the sub-critical water except for feldspar and calcite and that mesopores developed in the oil shale with prolongated extraction time, as more bitumen diffused out and into the sub-critical water at 300°C. KEYWORDS: oil shale; sub-critical water; low-temperature; composition analysis; GC–MS.

1. INTRODUCTION

Oil shale, a sedimentary rock with a high content of organic matter, can hopefully replace conventional fossil fuels in the near future due to its large reservoirs [1]. The conventional technologies, whether retorting for shale oil or combustion for power generation, have always been criticized for their high exploitation costs, their low utilization efficiency of oil shale particles and their environmental pollution problems [2,3].

Given these significant disadvantages, research agencies worldwide have proposed


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methods for heating the oil shale layer and producing hydrocarbons in-situ, and some methods including Shell’s In-situ Conversion Process[4] (ICP) and AMSO’s Conduction, Convection, Reflux[5] (CCRTM) have been processed as field experiments. The extraction of oil shale in-situ gives access to oil shale located at un-mineable depths and minimizes the effects of produced pollutants on ground water. Sub-critical water is obtained in contained systems by injecting heat and maintaining the temperature below the critical point (374°C) of water. Since it has a comparatively high temperature and pressure, functions as an acid/alkali-catalyst and possesses a unique extracting capacity for organic solvents, sub-critical water has been widely applied to biomass extraction[6,7], food chemistry

[8]

and environmental

remediation[9,10]. Therefore, some people used sub-critical water to extract shale oil from oil shale. Lewan et al. [11] first used sub-critical water at 300°C, 330°C and 350°C to extract and obtain shale oil. It was revealed that the yield of expelled oil increased, but the yields of bitumen extracts and gas decreased with increasing temperatures. Additionally, our previous works [12,13] proved that sub-critical water was capable of extracting hydrocarbons from large-sized oil shale lumps at 310°C, 335°C, 350°C, 365°C, and 375°C. Therefore, a pilot project being built by Jilin University in Jilin Province will attempt the in-situ extraction of oil shale by using sub-critical water as the mass medium and extraction agent. As is known, the temperature of sub-critical water, the extraction time and the size of oil shale particles affect the extracting yield of hydrocarbons and their compositions. Sinag et al.[14] researched the extraction of hydrocarbons from Göynük oil shale with


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sub-critical water and found that the extracting rate increased markedly with the temperature. Yanik et al.[15] used sub-critical and supercritical water to extract Göynük oil shale and found that the oil yield obtained from sub-critical water was slightly higher than that from supercritical water and that the recovered oil contained more aromatic and polar compounds at the same time. Alan L Chaffee et al.

[16,17]

researched the

pyrolytic reactions of oil shale under long-time and low-temperature conditions. The results showed that a high conversion to products of good characteristics could be obtained for reactions at sufficiently long times and low temperatures. In general, high temperatures will promote the extracting efficiency. The abovementioned results showed that a high conversion of kerogen could be obtained by sub-critical water at a relatively low temperature through a sufficiently long extraction time, but people rarely researched the extraction of oil shale using sub-critical water at lower temperatures. On the other hand, for the in-situ extraction process of oil shale, a large range of oil shales can hardly be heated to such a high temperature due to the low thermal conductivity and low connectivity of oil shale layers. In contrast, a low temperature and long extraction time are substantially easier to achieve. Therefore, systematically researching the extraction of oil shale by lower temperature sub-critical water is very meaningful for pilot experiments. In this study, Huadian oil shale was extracted by sub-critical water at 300°C with series of extraction time. The yields and the composition of bitumen were carefully investigated, and the composition changes of the gas product, water-dissolved organics and minerals in shale residue during sub-critical water extraction were studied. We hope


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the results may be helpful when applying the sub-critical water techniques to extract oil shale layer in-situ. It is hoped that the results are helpful to the pilot project for the insitu extraction process of oil shale by sub-critical water.

2. MATERIALS AND METHODS

2.1 Materials

The oil shale used in this experiment was collected from the fourth layer of the Dachengzi mine located in Huadian city, Jilin Province of China. The shale samples were crushed and sieved into small particles with a diameter of 0.45-0.90 mm. Before the experiments, all the particle samples were uniformly mixed and separated to reduce experimental errors caused by sample heterogeneity. The results for the proximate analysis, ultimate analysis and Fischer assay analysis of the oil shale samples are shown in Table 1. Table 1. Proximate analysis, ultimate analysis and Fischer assay analysis of Huadian oil shale. Proximate analysis (wt, %, ad) Volatile matter Fixed carbon Ash Moisture

34.36 2.01 59.85 3.78

Ultimate analysis (wt, %, ad) C H N S

23.61 3.63 0.47 0.32

Fischer assay analysis (wt%) Shale oil Gas Water Residue

15.15 2.71 8.76 73.38

2.2 Methods

First, 0.5 L stainless-steel autoclaves manufactured by Hai’an Oil Research Co., Ltd. of Jiangsu, China were loaded with 150 g oil shale particles and 300 ml distilled water.


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High-pressure nitrogen was used thrice for removing the air in the top space of the reactors and was then released to keep the system at the ordinary pressure. The autoclaves were heated to 300°C and kept for 50, 70, 100, 150, 250 and 350 h. The temperatures were monitored by using thermocouples with a standard deviation of ±0.1°C. During the sub-critical water extraction, the pressures monitored by piezometers were approximately 8.5-9 Mpa, which were almost provided by the vapor pressure of water at 300°C. After each extraction process, when the reactor had been cooled down to room temperature, the gas products, bitumen extracts, oil shale residues and spent aqueous solution were subsequently collected for further analyses. The bitumen extracts aggregated on the water surface were called bitumen 1, and the remaining soluble bitumen in the shale residue, which could be extracted by dichloromethane in a Soxhlet extraction apparatus, was called bitumen 2. In addition, 0.40 g of bitumen 1 was mixed with 20 ml hexane at 69°C for 6 h to obtain n-hexanesoluble bitumen for the composition analysis. Bitumen 2 was obtained by extracting 3.000 g residue with 50 ml dichloromethane at 55°C for 6 h in the Soxhlet extraction apparatus. Then, the residue was dried, cooled and weighed. The yields of bitumen 1 and bitumen 2 were calculated by using the equations below: bitumen 1 yield =

weight of bitumen 1 × 100 weight of oil shale

bitumen 2 yield =

weight of bitumen 2 × 100 weight of oil shale

The extracted experiments over 70, 150, 250 and 350h were repeated three times under the same extraction conditions. The standard deviation of the bitumen 1 yield and


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bitumen 2 yield due to errors in experiment and measurement were less than 1 % and 0.7 %, respectively. The experimental data were the mean values of three experiments to ensure the accuracy of the conclusions. The components of bitumen 1 and bitumen 2 were analyzed by gas chromatography-mass spectrometry (GC-MS). The gas compositions were analyzed by gas chromatography (GC). The total carbon (TC), inorganic carbon (IC) and total organic carbon (TOC) in the aqueous solution were determined using a TOC analyzer. The changes to the mineral composition and porosity of spent shale were examined using X-ray diffraction (XRD) and nitrogen isothermal adsorption/desorption analyses. The schematic diagram is shown in Fig 1.

Fig 1. Schematic of extraction experiments and testing methods for products.

2.3 GC analysis

The gaseous products were analyzed by an Agilent 7890B gas chromatograph equipped with two thermal conductivity detectors (TCD) and a flame ionization detector (FID). The FID was used to detect the hydrocarbons (C1-C6) using HP-AL/S


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columns (25 m×0.32 mm×8 μm) with helium as the carrier gas. CO2, O2, N2 and CO from the gas samples were determined using HayeSep A 80-100 mesh columns with helium as the carrier gas and a thermal conductivity detector (TCD1). H2 was also determined using Molsieve 5A 60/80 Mesh columns and a thermal conductivity detector (TCD2). The content of each component was quantified with an external standard method using a calibration gas sample (item number: A0908685) manufactured by the Scott company and the software of Agilent OpenLab.

2.4 GC-MS analysis

The GC-MS analysis was performed with an Agilent 7890A gas chromatograph coupled to an Agilent 5975N mass spectrometer to analyze the compounds in the bitumen samples. The inlet was operated in split mode, and the temperature was maintained at 300°C. The split ratio was set at 20:1 and 10:1 for analyzing bitumen 1 and bitumen 2 samples, respectively. The oven equipped with an HP-5MS column (0.32 mm ID, 0.25 μm film thickness) was programmed as follows: the initial temperature was 50°C and held for 5 min; then, heated at a 10 °C/min temperature ramp until a final temperature of 280°C and held for 12 min. The MS detector was equipped with an electron ionization (EI) detector set at 70 ev and 230°C. The mass spectra were collected by the Agilent MSD ChemStation software and were analyzed using the National Institute of Standards and Technology (NIST) mass spectrum library (Version 2.0). The relative content of each compound was directly calculated based on the peak area percentage in the chromatograms.


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2.5 XRD analysis

The mineral compositions of the spent shale were determined using an XRD-2700 diffractometer (China, Haoyuan Co. Ltd) with Cu-Kɑ radiation at 40.0 kV and 30.0 mA. The 2θ scan range was from 5° to 85°.

2.6 Nitrogen isothermal adsorption/desorption analysis

The low-temperature N2 isotherm adsorption/desorption analysis was conducted using an SSA-7000 specific surface area and aperture analyzer (BIAODE Electronic Technology, Ltd., China). Prior to the measurement of nitrogen adsorption, the samples underwent vacuum degassing at 180°C for 3 h. The distribution in pore size was calculated according to the adsorption branch of the isotherm using the Barrett–Joyner– Halenda method.

3. RESULTS AND DISCUSSION

3.1 The bitumen extraction capability of sub-critical water at 300°C

Fig 2. Extract yields of bitumen 1 and bitumen 2.


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Fig 2 shows the extract yields of bitumen 1 and bitumen 2 extracted from Huadian oil shale by sub-critical water at 300°C. It is evident that the bitumen 2 yield is initially significantly higher than the bitumen 1 yield and that they both increase and approach each other with extraction time. This result suggests that a high portion of bitumen extract remains in the oil shale during the sub-critical water extraction, especially at the early extraction stage because the decomposition of kerogen is incomplete at such a lower temperature; thus, the initial bitumen products are not readily released from the shale matrix due to their complex chemical structures, low flowability and dissolvability in subcritical water. Therefore, high contents of bitumen 2 are found in the shale residue. However, with extraction time, this bitumen will gradually be transferred out of the matrix due to the further decomposition of kerogen and the evolution of the fractures and pores inside of oil shale. Furthermore, at approximately 250 h, the yields of both bitumen 1 and bitumen 2 nearly reach maximum; after which, the bitumen 1 yield remains stable for an extended extraction time, but the bitumen 2 yield decreases significantly. It can be deduced that, at this time, the secondary cracking reaction rate of bitumen 1 is the same as the release rate of bitumen 2 out of the shale matrix. Meanwhile, most of the kerogen in the oil shale is supposed to have completely decomposed owing to the reduced generation of new bitumen 2 after extraction over a long-time scale by sub-critical water. In summary, the kerogen could almost transform into bitumen via lower temperature sub-critical water with a sufficiently long extraction time, and the remaining bitumen in the shale matrix could also be gradually released.


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3.2 The compositions of the products 3.2.1 The composition of bitumen 1


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Fig 3. Gas chromatograms of bitumen 1 with extraction time.

Changes in the composition of bitumen 1 during the extraction process could also reflect the characteristics and effectiveness of the extraction by sub-critical water at 300°C. Four bitumen 1 samples were chosen based on the approximate inflection points (70 h, 150 h and 250 h) and the end point (350 h) of the bitumen 1 yield curve in Fig 2. The n-hexane-dissolved portion of the bitumen 1 samples, which could present bitumen 1 in a certain way, was then measured and identified by a GC-MS analyzer and the gas chromatograms are shown in Fig 3. Each type of major component in the figure is marked, and the carbon atom number of individual n-alkanes is given to indicate the carbon chain length. n-Alkanes are the predominant component of bitumen 1, and the other major components are n-alkanoic acids, n-alkane-2-ones and isoprenoid alkane, while numerous weak peaks representing aromatic hydrocarbons, n-alkenes and some other heteroatom compounds are found in each gas chromatogram at short retention times.

Fig 4. Composition changes of bitumen 1 with extraction time.


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Fig 4 shows the content change of each kind of major component in bitumen 1, according to the method of GC-MS peak area normalization. The content of n-alkanes is significantly higher than that of the others, and it is separated out as a figure insert. As shown in Fig 4, the total contents of n-alkanes and n-alkanoic acids present clear changes with the sub-critical water extraction time. A visible decrease in the content of n-alkanes appears when going from an extraction time of 70 h to 150 h, and then the content elevates from 250 h to 350 h, while the content of n-alkanoic acids shows the opposite trend. Compared to n-alkanes, n-alkanoic acids are substantially more difficult to be extract by sub-critical water at such a relatively low temperature and over a relatively short time. Therefore, more n-alkanoic acids are released after a longer time extraction by sub-critical water. Furthermore, the decarboxylation of n-alkanoic acids into n-alkanes might be a very slow reaction in sub-critical water [18] at 300°C, but it eventually leads to a striking decrease in n-alkanoic acids’ content and an increase in n-alkanes’ contents with sufficient extraction time. Additionally, the n-alkane-2-one content changes similar to that of n-alkanoic acids.

Fig 5. Content change of n-alkanes in bitumen 1 with extraction time.


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As shown in the gas chromatograms, n-alkanes are the predominant components in bitumen 1, and the relative intensities of their peaks vary with the extraction time. To better analyze this phenomenon, the n-alkanes are divided into three parts according to their molecular weights (Mw), which are low Mw n-alkanes (C12-C19), medium Mw nalkanes (C20-C27) and high Mw n-alkanes (C28-C36), and Fig 5 presents their relative contents. In general, as shown in Fig 5, the column for low Mw n-alkanes grows and that of medium Mw n-alkanes falls with the sub-critical water extraction time. This result can be mostly attributed to the secondary decomposition of the long-chain alkanes in sub-critical water[19]. On the other hand, the content of the high Mw nalkanes continually increases with the raise of extraction time and finally decreases. As we know, large molecules are more difficult to extract out of oil shale matrix owing to their high density and viscosity and low flowability and dissolvability; however, because of the large amount of kerogen that decomposed during the extraction, more big molecules would be extracted by sub-critical water. Until most of kerogen decomposes, maybe after 250 h or longer, little new bitumen is generated inside of the oil shale, as mentioned in Section 2.1. Then, the content of the high-Mw n-alkanes decreases.


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3.2.2 The composition of bitumen 2

Fig 6. Gas chromatograms of bitumen 2 with extraction time.


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The gas chromatograms of the bitumen 2 samples are shown in Fig 6, and the primary components are marked in the graphs. It is noted that in accordance with bitumen 1, the predominant components of bitumen 2 are n-alkanes, n-alkanoic acids, n-alkane-2-ones and isoprenoid alkanes, while numerous weak peaks representing nalkanals, aromatic hydrocarbons, n-alkenes and some other heteroatomic compounds are also found at short retention times. It is evident that with increasing extraction, the content of n-alkanes with low Mw increase. Because the aldehyde group was extremely unstable, no n-alkanals were found in the bitumen extracted by high-temperature subcritical water [12].

Fig 7. Composition changes of bitumen 2 samples with extraction time. Fig 7 shows the content changes of the major components in bitumen 2. As shown by the inset columns, with increasing extraction time, the content of n-alkanes significantly increases from 55 to 66% and then remains stable as the extraction time exceeds 150 h. When the extraction time is 70 h, the percentage of n-alkanes is less than that in bitumen 1, and it may be concluded that n-alkanes are easier to separate


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from the oil shale matrix than n-alkanoic acids and n-alkane-2-ones. The fraction of nalkanoic acids also increases at 150 h and then decreases significantly. The other distinct difference between bitumen 1 and bitumen 2 is the content of n-alkane-2-ones. We find that more n-alkane-2-ones remain in the residue, and in contrast, the contents of n-alkanoic acids are lower. Furthermore, it is possible that the n-alkenes undergo different oxidation reactions. Even though the content of aromatic hydrocarbons increases with the extraction time, it remains very low.

Fig 8. Content changes of n-alkanes in bitumen 2 with extraction time. Fig 8 provides information about the distribution of n-alkanes in bitumen 2. Because the decomposition of kerogen will produce bitumen 2, and then, the bitumen 2 will convert to bitumen 1 upon transport out of the kerogen matrix, the trends of n-alkanes with low Mw (carbon number: 12-19) and high Mw (carbon number: 28-36) in bitumen 2 are similar to those in bitumen 1 but slightly ahead. From 70 h to 150 h, the content of n-alkanes with low Mw decreases, but from 150 h to 350 h, the content increases. Meanwhile, the content of n-alkanes with high Mw increases from 70 h to 150 h and then decreases progressively. It is not difficult to infer that kerogen decomposition will


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first produce massive low Mw n-alkanes, and as the cleavage reaction continues, high Mw n-alkanes are produced in large quantity. When the extraction time is more than 150 h, massive long-chain n-alkanes break to produce short-chain n-alkanes. It is interesting that the content of middle-Mw n-alkanes (carbon number: 20-27) in bitumen 2 is always lower than that in bitumen 1 at each extraction time.

3.2.3 The organics in the spent aqueous solution

The TOC test results of the spent aqueous solution are shown in Table 2. Massive amounts of organic matter remain in the water, and the TOC content of the wastewater far exceeds the national wastewater discharge standards. The TOC content of wastewater increases from 70 h to 250 h and then decreases. With prolonged extraction, the kerogen further decomposes, and more water-soluble compounds are produced, so the TOC content of water is increased. When the extraction time is more than 250 h, the kerogen in the oil shale is almost completely decomposed, and no more watersoluble compounds are produced; however, the massive amount of bitumen dissolved in the spent aqueous solution will decompose in the long-term sub-critical water environment. The gas chromatogram analysis of the organics dissolved in the spent aqueous solution was conducted, and the compounds were identified by mass spectrographic analysis. These results indicate that the composition of the organics dissolved in the spent aqueous solution is very different from bitumen 1 and bitumen 2. The predominate components are cyclohexanone derivatives, isoparaffins and phenolic


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derivatives. Meanwhile, n-alkanes, naphthenic acids, heteroatoms and esters can also be found. It is apparent that most of the organic matter in the spent aqueous solution possesses oxygen-containing functional groups so that it can dissolve in water. Table 2. TOC test results for the spent aqueous solution. 70 h 150 h 250 h 350 h

TOC (g/L) 2.052 2.250 2.324 1.814

TC (g/L) 2.411 2.504 2.571 2.041

IC (g/L) 0.359 0.254 0.248 0.228

3.3 The composition of gaseous products

Fig 9. Gas chromatograms of gases collected from the extraction experiments. Fig 9 shows the gas chromatograms of the gas samples obtained from the time-


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series experiments. The relative concentrations of the components and the ratio of alkanes to alkenes are listed in Table 3. As shown in the table, CO2, CH4, H2 and C2H6 are the major components of the gas products. Among the organic gases, it is noted that CO2 has the highest content, which is similar to the results reported by Hu et al.[20] and Kristjan Kruusement[21], and it is possibly produced by the decarboxylation of carboxylic intermediates with thermal stress[22]. CH4 is the major compound in the hydrocarbon gases, followed by C2H6 and C3H8, showing a similar trend to that defined by ALD Spigolon[23]. The ratio of alkenes to alkanes in the evolved pyrolysis gases has been used to determine the reaction mechanisms of the pyrolysis process[24]. For example, Wang et al.[25] found that higher alkene ratios obtained at higher retorting temperatures could be attributed to increased cracking reactions in the secondary gas phase. With increasing extraction time, both the subsequent coking reactions of bitumen extracts and the hydrogenation reactions between the alkenes and the hydrogen from water[26] possibly result in decreases to the alkene to alkane ratio.


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Fig 10. Content changes of typical gases with extraction time. Fig 10 shows the effect of extraction time on the concentration changes of CH4, C2C6 hydrocarbons, CO and H2. The content of methane increases when going from 70 to 250 h before decreasing at 350 h. According to the research of Campbell et.al[27], the released CH4 results from the cleavage of methyl groups attached to the aromatic structures or aliphatic chains in oil shale. The decrease in the relative content of CH4 observed between 250 h and 350 h may be because other gases are produced more. In addition, the increased content of C2-C6 hydrocarbons shows that the molecular weight of the gases raises with the extraction time, which is possibly due to the simultaneous decomposition of aliphatic hydrocarbons with high carbon numbers found in bitumen. The content of CO decreases as the extraction is prolonged to 350 h. As is known, large amounts of CO originate from the cleavage of oxygen functional groups (except carboxylic groups) in the oil shale, indicating that those components may decompose entirely in sub-critical water at 300°C after a 250 h extraction. The H2 concentration


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drops to a minimum value of approximately 3% at 150 h and then shows a small increase. It was suggested by Lewan[11] that the generation of H2 in sub-critical water extraction may result from the interaction between water molecules and the oxygenated functional groups. The concentration changes in H2 observed before 150 h could possibly be ascribed to a decrease in this reaction, and H2 may also be consumed by reacting with the bitumen extracts in the sub-critical water environment. Table 3. Main compositions of gases collected from each experiment. Gases Inorganic gases Carbon monoxide Carbon dioxide Hydrogen Hydrocarbon gases Methane Ethane Propane Butane Isobutane Ethylene Propylene 1-Butylene Isobutylene cis-2-Butylene trans-2-Butylene Total alkanes Total alkenes Ethylene/Ethane Propylene/Propane Butylene/Butane Alkenes/Alkanes

Extraction time (h) 70

150

250

350

0.18 60.51 4.99

0.21 75.60 2.94

0.09 76.57 3.39

0.10 75.26 4.00

3.44 0.82 0.34 0.09 0.05 0.12 0.13 0.02 0.02 0.01 0.02 4.67 0.33 0.15 0.40 0.50 0.07

4.47 1.58 0.66 0.16 0.08 0.05 0.11 0.01 0.01 0.01 0.02 6.77 0.23 0.03 0.17 0.25 0.03

6.34 2.19 0.84 0.19 0.09 0.04 0.10 0.01 0.01 0.01 0.02 9.43 0.20 0.02 0.12 0.21 0.02

5.45 2.10 0.92 0.24 0.12 0.04 0.11 0.01 0.01 0.02 0.03 8.54 0.22 0.02 0.12 0.20 0.03


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3.4 The mineral composition changes and pore evolutions of the oil shale 3.4.1 The mineral composition of oil shales

Fig 11. XRD diffractograms of raw oil shale and spent shale for different extraction times. M-montmorillonite, I-illite, Q-quartz, F-feldspar, and C-calcite. Fig 11 shows the X-ray diffraction (XRD) analysis of the raw oil shale and the spent shale for different extraction times. It can be seen in the graph that the major minerals in the samples are composed of montmorillonite, illite, quartz, feldspar and calcite, and their contents exhibit no marked differences. The diffraction peaks of feldspar appear after 150 h; it is possible that amorphous SiO2 reacts with active Al2O3 and some other compounds, and feldspar forms as a result[28]. Meanwhile, the diffraction peaks of quartz decrease slightly after 150 h. The diffraction peaks of calcite decrease gradually, as calcite will decrease in the sub-critical water and produce CO2. 3.4.2 The nitrogen isothermal adsorption/desorption analysis of spent shale The adsorption/desorption isotherms of shale samples are presented in Fig 12. It is clear that original sample and the residue produce similar adsorption/desorption


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isotherms, taking on an S-shaped type II curve per IUPAC classifications[29]. When P/P0 < 0.9, the adsorption isotherm branch rises slowly; however, when P/P0 > 0.9, the adsorption quantity increases sharply. This observation is because capillary condensation takes place in a certain amount of mesopores and macropores in the samples. We find that the desorption isotherm branch detaches from its corresponding adsorption branch, forming a hysteresis loop. The shape of the hysteresis loops is identified as type H3 by IUPAC classification [30], indicating slit-shaped pores.

Fig 12. Nitrogen adsorption/desorption isotherms of the original sample and the spent samples. Fig 13 shows the pore volume distribution of the samples based on BJH theory. The volume of the micropores and mesopores increases with the extraction time except for a slight decrease at 150 h. This result implies that the mesopores develop with prolonged extraction time. With the kerogen cracking and bitumen diffusion from the oil shale, the micro- and mesopores develop.


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Fig 13. The pore volume distribution of the original sample and the spent samples.

4. CONCLUSIONS

In this study, Huadian oil shale was extracted by sub-critical water at 300°C over a series of extraction times. The results revealed that the kerogen in oil shale was almost completely transformed into bitumen over long time periods during lower temperature sub-critical water extraction, but some of the generated bitumen remained in the matrix. A long time was required for the shale oil to be released into the water because the transporting substrates of sub-critical water were insufficient, and tiny fractures existed in the oil shale matrix at such a low temperature. Furthermore, the optimal extraction time was 250 h. GC–MS analysis showed that the major components of bitumen 1 and bitumen 2 were n-alkanes, n-alkanoic acids, n-alk-2-ones and isoprenoid alkane. The initial stage of kerogen decomposition in sub-critical water produced massive low Mw n-alkanes, and as the cleavage reaction continued, high Mw n-alkanes were produced in a large quantity. Additionally, the carboxylic acid fragments were apparently more difficult to release from kerogen than the hydrocarbons. It is interesting that the content of middle


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molecular weight n-alkanes in bitumen 2 was always lower than that in bitumen 1. The secondary cracking reaction of bitumen 1 decreased the yield of oil, but the content of C2-C6 hydrocarbons increased. The organic matter dissolved in the spent aqueous solution consisted mainly of paraffins, isoparaffins, cyclohexanone derivatives and phenolic derivatives. The analysis of the oil shale residues showed that minerals were less reactive in sub-critical water except for feldspar and calcite. Furthermore, mesopores in the oil shale developed with extended extraction time, as more bitumen diffused out of the matrix and into the sub-critical water at 300°C.

ACKNOWLEDGEMENTS

This work was supported by the National Natural Science Foundation of China (No. 21406084); the Project of Jilin Province Development and Reform Commission of China, the Cooperative Project between Universities and Jilin Province, China (Grant No. SF2017-5-1), Natural Science Foundation of Jilin Province, China (No. 20160520086JH), the Program for JLU Science and Technology Innovative Research Team (Grant No. 2017TD-13), the Fundamental Research Funds for the Central Universities. Author 3 thanks the CSC-HUJI scholarship for providing the subsidy for his study in Israel. REFERENCES


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[1] Kartal, OE.; Akin, S.; Hascakir, B.; Karaca, H. Liquefaction of nigde-ulukisla oil shale: The effects of process parameters on the conversion of liquefaction products. Oil Shale, 2017, 34 (4), 336–353. [2] Jiang, X.M.; Han, X.X.; Cui, Z.G. New technology for the comprehensive utilization of Chinese oil shale resources. Energy 2007,32, 772-777. [3] Anto Raukas; Jaan-Mati Punning. Environmental problems in the Estonian oil shale industry. Energy & Environmental Science 2009,2, 723-728. [4] Brandt, A.R. Converting oil shale to liquid fuels: energy inputs and greenhouse gas emissions of the Shell in situ conversion process. Environmental Science & Technology 2008,42, 7489-95. [5] A.K. Burnham, R.L. Day, M.P. Hardy, P.H. Wallman, AMSO’s novel approach to in situ oil shale recovery, in: O.I. Ogunsola, A.M. Hartstein, O. Ogunsola (Eds.), Oil Shale: A Solution to the Liquid Fuel Dilemma, ACS Symposium Series 1032,Washington, 2010,149–160. [6] Xu, C.; Lad, N. Production of Heavy Oils with High Caloric Values by Direct Liquefaction of Woody Biomass in Sub/Near-critical Water. Energy & Fuels 2008,22,635-642. [7] Toor, S.S.; Rosendahl, L.; Rudolf, A. Hydrothermal liquefaction of biomass: a review of subcritical water technologies. Energy 2011,36, 2328-2342. [8] Herrero, M.; Cifuentes, A.; Elena Ibanez, E. Sub- and supercritical fluid extraction of functional ingredients from different natural sources: Plants, food-by-products, algae and microalgae A review. Food Chemistry 2006,98, 136–148. [9] Islam, M.H.; Jung, H.Y.; Park, J.H. Subcritical water treatment of explosive and heavy metals co-contaminated soil: Removal of the explosive, and immobilization and risk assessment of heavy metals. Journal of Environmental Management 2015,163, 262-269. [10] Weber, R.; Yoshida, S.; Miwa, K. PCB destruction in subcritical and supercritical water--evaluation of PCDF formation and initial steps of degradation mechanisms. Environmental Science & Technology 2002,36, 1839-1844. [11]Lewan, M.D. Experiments on the role of water in petroleum formation. Geochimica Et Cosmochimica Acta 1997,61,3691-3723. [12]Wang, Z.; Deng, S.; Qiang, G. et al. Subcritical Water Extraction of Huadian Oil Shale under Isothermal Condition and Pyrolysate Analysis. Energy & Fuels 2014,28, 2305-2313. [13] Deng, S.; Z Wang, Z.; Gao, Y.; Gu, Q.; Cui, X.; Wang, H. Sub-critical water extraction of bitumen from Huadian oil shale lumps. Journal of Analytical and Applied Pyrolysis 2012,98,151–158. [14] Sinag, A. Sub- and supercritical water extraction of goynük oil shale. Energy Sources 2004,26,885-890. [15] Yanik, J.; Yüksel, M.; Saglam, M. et al. Characterization of the oil fractions of shale oil obtained by pyrolysis and supercritical water extraction. Fuel 1995,74, 46-50. [16] Aljariri Alhesan, J.S.; Fei, Y.; Marshall, M.; Jackson, W.R.; Qi, Y.; Chaffee, A.L. Cassidy, P.J. Long time, low temperature pyrolysis of El-Lajjun oil shale. Journal of Analytical and Applied Pyrolysis 2018,13,135-141.


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[17] Fei, Y.; Marshall, M.; Jackson, W.R.; Qi, Y.; Auxilio, A.R.; Chaffee, A.L. et al. Long-Time-Period, Low-Temperature Reactions of Green River Oil Shale. Energy & Fuels 2018,32 (4), 4808-4822. [18] Brown, T.M.; Duan, P.; Savage, P.E. Hydrothermal Liquefaction and Gasification of Nannochloropsis sp. Energy & Fuels, 2010, (24), 3639–3646. [19] Jiang, H.; Song, L.; Cheng, Z. et al. Influence of pyrolysis condition and transition metal salt on the product yield and characterization via Huadian oil shale pyrolysis. Journal of Analytical and Applied Pyrolysis 2015,112, 230-236. [20] Hu, H.; Guo, S.; Hedden, K. Extraction of lignite with water in sub- and supercritical states. Fuel Processing Technology 1999,78, 645-651. [21] Kruusement, K.; Luik, H.; Waldner, M.; Vogel, F.; Luik, L. Gasification and liquefaction of solid fuels by hydrothermal conversion methods. Journal of Analytical and Applied Pyrolysis 2014,108, 265–273. [22] Lewan, M.D. Water as a source of hydrogen and oxygen in petroleum formation by hydrous pyrolysis. Am. Chem. Soc. Div. Fuel Chem 1992,37,1643-1649. [23] Spigolon, A.L.D.; Lewan, M.D. et al. Evaluation of the petroleum composition and quality with increasing thermal maturity as simulated by hydrous pyrolysis: A case study using a Brazilian source rock with Type I kerogen. Organic Geochemistry 2015,83–84, 27-53. [24] Ahmad, N.; Williams, R.T. Influence of particle grain size on the yield and composition of products from the pyrolysis of oil shales. Journal of Analytical and Applied Pyrolysis 1998,46,31–49. [25] Wang, S.; Jiang, X.; Han, X. et al, Effect of retorting temperature on product yield and characteristics of non-condensable gases and shale oil obtained by retorting Huadian oil shales. Fuel Processing Technology 2014,121, 9-15. [26] Leif, R.N.; Simoneit, B.R.T. The role of alkenes produced during hydrous pyrolysis of a shale. Organic Geochemistry 2000,31,1189-1208. [27] Campbell J H, Koskinas G J, Gallegos G, et al, Gas evolution during oil shale pyrolysis. 1. Nonisothermal rate measurements. Fuel 1980,59,718-726. [28] Fan, C.; Yan, J.; Huang, Y. et al, XRD and TG-FTIR study of the effect of mineral matrix on the pyrolysis and combustion of organic matter in shale char. Fuel 2015,139, 502-510. [29] Sing, K.S.W.; Everett, D.H.; Haul, R.A.W.; Moscou, L.; Pierotti, R. A.; Rouquerol, J. et al, Reporting physisorption data for gas/solid systems with special reference to the determination of surface area and porosity (recommendations 1984). Pure Appl Chem 1985,57,603–619. [30] Bai, J.; Wang, Q.; Jiao, G. Study on the Pore Structure of Oil Shale During LowTemperature Pyrolysis. Energy Procedia 2012,17, 1689 – 1696.


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Fig 1. Schematic of extraction experiments and testing methods for products. 164x82mm (300 x 300 DPI)


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Fig 2. Extract yields of bitumen 1 and bitumen 2. 79x62mm (600 x 600 DPI)


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Fig 3. Gas chromatograms of bitumen 1with extracting times. 79x119mm (600 x 600 DPI)


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Fig 4. Composition changes of bitumen 1 samples with extracting times. 79x59mm (600 x 600 DPI)


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Fig 5. Content changes of n-alkanes of bitumen 1 with extracting times. 79x60mm (600 x 600 DPI)


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Fig 6. Gas chromatograms of bitumen 2 with extracting times. 79x120mm (600 x 600 DPI)


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Fig 7. Composition changes of bitumen 2 samples with extracting times. 79x59mm (600 x 600 DPI)


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Fig 8. Content changes of n-alkanes of bitumen 2 with extracting times. 79x61mm (600 x 600 DPI)


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Fig 9. Gas chromatograms of gases collected from extraction experiments. 79x118mm (600 x 600 DPI)


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Fig 10. Content changes of typical gases with extraction time. 169x107mm (600 x 600 DPI)


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Fig 11. XRD spectrograms of raw oil shale and spent shale with different extracting times. M-Montmorillonite I-Illite Q-Quartz F-Feldspar C-Calcite. 79x60mm (600 x 600 DPI)


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Fig 12. Nitrogen adsorption/desorption isotherms of original sample and spent samples. 79x63mm (600 x 600 DPI)


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Fig 13. the pore volume distribution of original sample and spent samples. 79x55mm (600 x 600 DPI)


Sub-critical water extraction of Huadian oil shale at 300 Â°C

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