Article pubs.acs.org/EF
Green River Oil Shale Pyrolysis: Semi-Open Conditions T. V. Le Doan,†,‡ N. W. Bostrom,†,# A. K. Burnham,§ R. L. Kleinberg,*,† A. E. Pomerantz,† and P. Allix‡ †
Schlumberger-Doll Research, Cambridge, Massachusetts, United States TOTAL, S.A., Pau, France § American Shale Oil LLC, Rifle, Colorado, United States ‡
S Supporting Information *
ABSTRACT: Oil shale is a petroleum source rock that has not undergone the natural processes required to convert its organic matter to oil and gas. However, oil shale kerogen can be converted artificially to liquid and gaseous hydrocarbons by pyrolysis. Heating oil shale in place (in situ) has a number of operational, economic, and environmental advantages over surface retorts, particularly when the shale is too deep to mine. This work describes experiments conducted at temperatures and pressures appropriate to commercially viable in situ pyrolysis. The data are needed to construct models to plan, interpret, and optimize field experiments and commercial operations. The experiments also provide insights into the chemical compositions of the native state shale and all the products of pyrolysishydrocarbon and nonhydrocarbon gases, oil, bitumen, remaining pyrolyzable kerogen, residual organic matter, and inorganic matteras functions of thermal maturation. Numerous studies of Green River oil shale pyrolysis have been published over the years. Most of these have focused on the richest interval, the Mahogany (R-7) zone and have been performed in either open (atmospheric pressure) or closed (bomb) apparatus. The new elements of this work are as follows: (1) samples were taken from the deepest of the kerogen-rich layers of the Green River Formation, the mineralogically distinct R-1 zone; (2) experiments were performed under semi-open (controlled pressure) conditions. The data generated are therefore appropriate input to models used in conjunction with in situ controlled-pressure production tests of R-1 shale. In agreement with previous work, this investigation finds that processing shale at relatively low temperatures, for longer times, and at moderately elevated pressures, reduces yields but improves product quality relative to surface retort methods. The composition of the produced oil is generally uniform over the course of artificial maturation. It has a high H/C ratio and is predominantly composed of saturates and light aromatics, which are desirable for refinery operations. The oil has little sulfur, which is mostly in thiophene-containing moieties. Extracted bitumen has a high polar content, and its H/C ratio decreases as a result of oil and gas generation during maturation. Produced gas is rich in natural gas liquids.
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INTRODUCTION Oil shale has been pyrolyzed to produce hydrocarbon oils since the middle of the 19th century. Large scale production has usually involved mining the shale and retorting it under anaerobic conditions at atmospheric pressure, at temperatures near 500 °C, for times on the order of an hour. However, while surface retort technologies are appropriate for exploiting nearsurface oil shale deposits, in situ retorting is probably the most practical way to produce oil from resources that are more than 250 m below the surface. Temperatures are typically in the range 300−350 °C, and processing times are days to months. In Sweden, oil from shale was produced on a commercial scale by in situ retorting in the middle decades of the 20th century.1,2 Significant theoretical modeling and laboratory experiments were performed in the 1960s through the 1980s at Lawrence Livermore National Laboratory,3−5 IIT Research Institute,6,7 and the U.S. Bureau of Mines,8−11 among others.12 Field tests were performed by Unocal, using Raytheon technology, in the 1980s,13 and by Shell from 1981 to 2013.14−17 These methods have proved superior to the mining and surface retort method with respect to oil quality and environmental impact. New in situ field tests are being planned by American Shale Oil LLC (AMSO)18−20 and by ExxonMobil.21,22 There have been many studies of oil shale pyrolysis, but almost all have focused on the Mahogany (R-7) zone of the © XXXX American Chemical Society
Green River Formation. The Mahogany zone is one of the world’s richest sources of oil shale, but its proximity to potable water aquifers makes it a difficult target for in situ generation of oil and gas. The samples used in this work were taken from the deepest of the kerogen-rich layers of the Green River Formation, the R-1 zone of the Garden Gulch Member. This zone is a desirable target for oil shale production operations because it is hydraulically isolated from shallower fresh water aquifers.23 In order to analyze the results of field tests, and to specify optimal oil shale pyrolysis process conditions, kinetic models that describe the transformation of kerogen into oil and gas are needed.24 This work describes experiments performed to provide the data required to construct these models. In addition to temperature and time, the pressure at which gases and vaporizable liquids are extracted is a variable that can be used to optimize the process for oil and gas yield and quality. Therefore, a semi-open laboratory pyrolysis system was built, modeled after that of Burnham and Singleton.4 Because the apparatus is capable of operating over a range of pressures, it differs from those used in most other pyrolysis studies, which Received: June 24, 2013 Revised: October 4, 2013
A
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This system included an air-operated piston valve (2) actuated by a three-way solenoid valve (3) under computer control. When the solenoid valve was energized, the piston valve was closed, and pressure was allowed to build up in the vessel. When the reactor pressure exceeded the set point pressure Pset by a predetermined increment ε, the power supply was turned off, opening the piston valve. As a result, the gas and vaporized liquid were bled out of the top of the reactor until the pressure decreased to Pset − ε, at which point the solenoid valve was reenergized. The needle valve (1) controlled the rate of gas release, preventing rapid depressurization of the vessel when the piston valve was open. The tubing and valves through which vapors moved from the oven were wrapped with heating tape to ensure products remained in the gas phase until they reached the condenser, through which water thermostatted at 20 °C was circulated. Water and hydrocarbon liquid were recovered in the receiver (4) and later separated. Uncondensed gases inflated a Tedlar polyvinylfluoride gas bag (9) which was submerged in a tank of water. As the gas bag inflated, water was displaced from the tank into a cylinder, in which the water height was measured (10), thus determining the gas volume. Typically, the 1L capacity gas bag had to be emptied several times during a pyrolysis experiment. Once the gas bag was full, collection was suspended, and a sample was taken using valves 5, 6, and 8. While the gas bag was emptied and evacuated for reuse, the pressure in the pyrolysis vessel increased, as illustrated below. A sample tube (7) was used to transport the gas to a gas chromatograph for composition measurement. The thermal program of a typical experiment is shown in Figure 2 (red line). The pressure vessel was first heated at the maximum rate (approximately 200 °C/h) to 180 °C, which is below the minimum pyrolysis temperature on these time scales. Then, the vessel was heated at a controlled rate until the plateau temperature Tf was reached. Temperature ramps were sufficiently slow so that temperatures did not vary significantly between the air temperature in the oven and the temperature of the shale inside the pressure vessel. The vessel was held at the plateau temperature for a predetermined plateau duration. At the conclusion of the experiment, the pressure was reduced to ambient pressure. Experiments were performed under various operating conditions over ranges of pressure (1−5 MPa), heating rate (2−120 °C/h), plateau temperature (300−425 °C), and plateau duration time (5− 12.5 h). Therefore, the isobaric experiments combine isothermal and nonisothermal elements. A formal Design of Experiment protocol, based on the response surface method, was employed to maximize the amount of information under the constraint of a fixed number of experiments. This program, which emphasized endpoint conditions, was supplemented with experiments at intermediate thermal maturations, for the purposes of an accompanying study of the physical and chemical characteristics of pyrolysis products. The list of experiments is provided in the Supporting Information. Figure 2 also shows the pressure (blue line) and the volume of generated gases (including the initial charge of nitrogen; brown line) during a typical experiment. At the beginning of the experiment, the sample was heated (red line) as quickly as possible to about 180 °C. Then, the sample was heated to 394 °C at a heating rate of 63 °C/h and stayed at this final temperature for 7.5 h. The pressure (blue line) oscillates in a sawtooth pattern between Pset − ε and Pset + ε. The pressure exceeds Pset + ε when the valves are closed to empty the gas bag (pink arrows). At the conclusion of heating, the vessel is depressurized. The cumulative volume of gas (brown line) increases except during gas bag manipulations. Figure 3 diagrams the sequence of analyses of the products of oil shale pyrolysis. Before pyrolysis, native state oil shale was characterized by Modified Fischer Assay, Rock Eval, elemental analysis (CHNSO), nuclear magnetic resonance (NMR), Fourier-transform infrared spectroscopy (FTIR), and density, surface area, and pore volume (D +SA+PV) measurements. After pyrolysis, the quantities of hydrocarbon gases (C1 to C5), CO2, and H2 were measured by gas chromatography using flame ionization and thermal conductivity detection (GC-FID, GC-TCD).
were conducted under either open cell (atmospheric) or closed cell (bomb) conditions. Experiments were performed with homogenized replicate samples of drill cuttings from the target interval and were conducted under various operating conditions over ranges of pressure (1−5 MPa), heating rate (2−120 °C/ h), plateau temperature (300−425 °C), and time at plateau temperature (5−12.5 h). The temperature and pressure ranges correspond to those planned for the pilot study. A comprehensive analytical program was undertaken to characterize native state oil shale and all products of pyrolysis. These data allow us to establish an empirical compositional kinetic model for oil shale pyrolysis. Preliminary work has been reported elsewhere.25
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EXPERIMENTAL METHODS
The rock materials used in this study originated in the Piceance Basin, Rio Blanco County, Colorado, see Supporting Information. The Bureau of Land Management research, development, and demonstration (RD&D) lease is in Township 2S.98W, in the heart of the world’s richest oil shale province, with 3 million barrels of oil equivalent in place per acre.26 All experiments used oil shale from the middle cuttings of the R-1 zone (Well BH-1, 2012−2088 ft) of the illite-rich Garden Gulch Member of the Green River Formation. A reverse circulation drilling method used naturally occurring groundwater and air to transport the cuttings to the surface. The room dry cuttings were used as received. The cuttings were homogenized and split into 93.2 g aliquots, as described in the Supporting Information, then crushed to 100−200 μm particle size. In this manner, precisely replicate starting materials were used, ensuring the experiments were not influenced by variations in mineralogy, diagenesis, kerogen origin or composition, or thermal history. The experiments used a general purpose 316 stainless steel pyrolysis vessel having an inner diameter of 38 mm and an inner length of 127 mm. Its maximum working pressure was 20 MPa at 425 °C. It was equipped with ports for temperature and pressure measurements and allowed for sampling of pyrolysis products from the top and bottom of the vessel; the bottom port was not used. The pressure vessel containing an aliquot of shale was flushed with nitrogen to displace air, charged to target pressure, and heated in an oven, see Figure 1. The temperature and pressure in the vessel were monitored during the experiment. Isobaric conditions were maintained by an automatic valve system that controlled the pressure in the vessel.
Figure 1. Pyrolysis laboratory schematic: (1) needle valve, (2) piston valve, (3) solenoid value, (4) liquids collector, (5) four-way valve, (6) shut-off valves, (7) sample tubes, (8) three-way valve, (9) gas bag, (10) liquid level measurement. B
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Figure 2. Temperature, pressure and gas volume profile for an example experiment. Ramp, 63 °C/h; plateau temperature, 394 °C; plateau duration, 7.5 h; pressure, 4.0 MPa.
Figure 3. Product analyses flowchart, with lists of analytical procedures. followed by boric acid to remove neoformed fluorides. The organic isolate was characterized by Rock-Eval, CHNSO, FTIR, XANES, and D+SA+PV. To perform two-dimensional gas chromatography, samples were injected into a gas chromatograph equipped with a two-stage thermal modulator system, primary and secondary fused silica open tubular capillary GC columns, and a flame ionization detector (FID). The modulator served as an interface between the two GC columns. The primary column was a conventional high resolution capillary GC column coated with a cross-linked methyl silicone stationary phase, which separates molecules based on volatility. The secondary GC column was coated with cross-linked polyethylene glycol; it is short and narrow, for fast GC separations based on polarity and polarizability. The modulator accumulated, focused, and injected fractions eluting off the primary column onto the secondary column, which was connected to the FID. Compounds were identified by the two retention times and quantified by the FID response. A template was used to identify the boundaries between the different hydrocarbon types. A second method of quantifying oil composition was Iatroscan thin layer chromatography with flame ionization detection (TLC-FID). First, asphaltenes were precipitated with n-heptane, then dried and
The gas chromatograph was calibrated against standard gas samples, and GC data were combined with gross gas volume measurements to determine the weight of each gas fraction produced during pyrolysis. The amount of H2S was quantified by Dräger tubes. The recovered oil and water were separated by centrifuge and quantified. It was determined that the amount of water collected depended on ephemera such as laboratory ambient humidity while the sample was being prepared. Therefore, the water was not analyzed further. The chemical composition of oil was determined by CHNSO analysis, two-dimensional gas chromatography (2D GC-FID), Iatroscan thin layer chromatography with flame ionization detection (TLC-FID), gel permeation chromatography (GPC), high field NMR spectroscopy, and sulfur K-edge X-ray absorption near-edge structure (XANES) spectroscopy. The spent shale remaining after pyrolysis was subjected to RockEval, CHNSO analysis, NMR, FTIR, and D+SA+PV measurements. Bitumen was extracted with 9:1 dichloromethane/methanol. The composition of extracted bitumen was analyzed by Rock-Eval, CHNSO, TLC-FID, GPC, NMR, and XANES. The bitumen-extracted spent shale was demineralized by removing silicates and carbonates with hydrochloric acid and hydrofluoric acid27 C
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weighed. The maltene residual was resolved into saturates, aromatics, and resins by TLC and measured by the calibrated detector. A third method of quantifying oil composition is gel permeation chromatography (GPC). A column is filled with microporous gel in which smaller analytes are trapped for longer times than larger analytes. There is no discrimination between saturates, aromatics, and polars. The molecular weight distribution is determined from the measured retention volume by means of a calibration curve. In this work, a Jordan 500A column with a differential refractometer was used. Oil composition was also measured by high-resolution liquid-state 13 C and 1H NMR spectroscopy. Samples were diluted in CDCl3, and 0.05 M Cr(acac)3 was added as a relaxation agent. 13C NMR measurements employed a Varian Mercury MVX-300 NMR spectrometer operating at a resonance frequency of 75.36 MHz and a Varian 5 mm broad-band ATB-PFG probe. Spectral acquisition parameters include a 45° tip angle, 2 s relaxation delay, and 0.65 s acquisition time. Inverse gated high power proton decoupling was used to prevent NOE enhancements. 1H NMR measurements employed the Varian spectrometer operating at 299.941 MHz and a Varian 5 mm four-nucleus probe. Spectral acquisition parameters include a 45° tip angle, 2 s relaxation delay, and 3.91 s acquisition time. The molecular environment of sulfur was measured using K-edge Xray absorption near edge structure (XANES) spectroscopy.28−33 X-ray fluorescence intensity was recorded as the sample was excited with tunable, monochromatic X-rays provided by a synchrotron. The absorption spectrum of sulfur varies with molecular environment, allowing XANES data to be inverted to yield the relative abundance of sulfur-containing moieties, such as those illustrated in Figure 4.
model compound spectra, with the recorded abundances proportional to the fitted weights.
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RESULTS Rock-Eval results from a random selection of 13 native state oil shale samples are given in Table 1; table columns are defined in the Supporting Information. Excellent reproducibility suggests that the homogenization was effective. Figure 5 presents the evolution of the organic fraction of shale with increasing thermal maturity. The horizontal scales are measures of organic maturation based on a time− temperature index (lower scale) and calculated vitrinite reflectance (EASY%Ro; upper scale), described in the Supporting Information. Remaining pyrolyzable kerogen (PK) and residual organic matter (ROM; potential coke) were obtained by Rock-Eval analysis of spent shale after bitumen extraction. ⎤m ⎡ 1 PK = ⎢S1 + S2 + S3 + S3CO + S3′CO⎥ SSBE ⎦ m0 ⎣ 2 ROM =
(1)
RC mSSBE 0.87 m0
(2)
The terms in these equations are products of Rock-Eval analysis, as described in the literature34,35 and in the Supporting Information. Equations 1 and 2 are normalized by the ratio of the mass of the spent shale after bitumen extraction, mSSBE, to the mass of the native state sample, m0. The conversion from weight fraction residual organic carbon, RC, to weight fraction residual organic matter, ROM, is based on the estimated composition of char following Fischer assay-like pyrolysis of Green River oil shale,36 CH0.42N0.056O0.02S0.008, implying that the char was 87% carbon by weight. With increasing thermal maturity, pyrolyzable kerogen (yellow bars) converts first primarily to bitumen (blue bars), with minor amounts of oil and gas (green and red bars, respectively) produced under relatively mild conditions. As maturation proceeds, bitumen disappears simultaneously with substantial production of lighter hydrocarbons. The residual organic matter (potential coke) of the shale (black bars) at first remains fairly constant as maturation proceeds, then increases, which suggests that coking plays a role in bitumen conversion. As the process proceeds, the total amount of organic matter, as a fraction of the original shale weight, remains within a few percent of the native state value (uppermost horizontal line), an expression of mass balance closure, as discussed in the Supporting Information. Thus, under the conditions of these experiments, the primary pathway of organic maturation is via conversion of pyrolyzable kerogen to bitumen and subsequently from bitumen to oil and gas, which appear to be produced simultaneously. The window of maximum oil generation is approximately in accord with the accepted range of vitrinite reflectance, 0.55%
Figure 4. Sulfur-containing moieties resolved by XANES. Detected sulfate can also represent inorganics. XANES measurements were made on Beamline 9-BM at the Advanced Photon Source at Argonne National Laboratory. The fluorescence signal was measured with a Stern−Heald−Lytle detector separated from a helium-purged sample chamber by a 2.5-μm-thick AlMylar window. Energy was calibrated against a sodium thiosulfate preedge feature at 2469.20 eV. Spectra were fit to linear combinations of
Table 1. Rock-Eval Data for 13 Homogenized and Split Native State Oil Shale Samples
mean value standard deviation minimum value maximum value relative error (%)
TOC (wt %)
S1 (mg/g)
S2 (mg/g)
Tmax (°C)
PI
HI (mg/gC)
OI (mg/gC)
RC (wt %)
MinC (wt %)
13.02 0.41 12.37 13.65 3.1
5.5 0.5 5.0 6.3 9.1
112.23 2.79 108.12 116.67 2.5
438.1 0.9 437.0 439.0 0.2
0.05 0.01 0.04 0.05 11.4
862.31 14.06 839.00 881.00 1.6
5.38 0.65 5.00 7.00 12.1
3.20 0.27 2.88 3.54 8.3
2.11 0.12 1.91 2.36 5.9
D
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Figure 5. Evolution of organic fractions of shale with increasing thermal maturity. The uppermost horizontal line is the mass fraction of organic matter in the native state shale. The second horizontal line is the native state pyrolyzable organic matter (kerogen + bitumen) as determined by Rock-Eval. The lowest horizontal line is the expected oil generation under Modified Fischer Assay conditions. The amount of hydrocarbon gas produced by the most mature sample (rightmost bar) is an estimate.
Figure 6. Evolution of chemical composition of oils with thermal maturity, as determined by 2D GC-FID.
Ro to 1.15% Ro.37 Actual production of oil is compared to two laboratory estimators. The Modified Fischer Assay method specifies heating native state oil shale at 12 °C/min to a temperature of 500 °C and collecting the oil produced for a further 40 min.38,39 Only produced oil and water are measured. It is designed to simulate production of oil by a typical surface retort process used on mined shale. For the material used here, the Modified Fischer Assay was 29.1 gal/ton, where the units are the U.S. gallon and the U.S. short ton. The density of Modified Fischer Assay oil is 0.89 g/cm3, so the equivalent weight fraction of oil produced from shale is FA =
This quantity is represented in Figure 5 by the black horizontal line labeled FA. Under the most severe conditions used in this series of experiments, oil yield reached about 63% by weight of the oil produced by Modified Fischer Assay. Slower heating rates, lower pyrolysis temperatures, and higher pressures all reduce yield relative to the Modified Fischer Assay method.5 Another estimator of potential oil recovery is Rock-Eval pyrolyzable organic matter (the sum of bitumen and pyrolyzable kerogen) of the native state shale.34,35 In the Rock-Eval process, shale is pyrolyzed to 650 °C. This method differs from the Modified Fischer Assay in that both oil and gas are measured. Native state pyrolyzable organic matter is represented in Figure 5 by the black horizontal line labeled POM/NS. This is higher than the maximum amount of oil plus hydrocarbon gas produced in the present experiments. Some
(29.1 gal/ton)(3785 cm 3/gal)(0.89 g/cm 3)
= 0.108 g/g
9.072 × 105 g/ton (3) E
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Figure 7. Evolution of SARA composition of oils with thermal maturity, as determined by Iatroscan thin layer chromatography with flame ionization detection (TLC-FID).
details of the Rock-Eval method are provided in the Supporting Information. Oil. Figure 6 shows the evolution of chemical composition of oils with thermal maturity as determined by 2D GC-FID. Samples are ordered according to their maturity on the horizontal axis. The chemical composition of produced oils is substantially constant across the range of thermal maturities. The oils contain about 70−80% by weight of saturated compounds (green bars). This high proportion of saturates is explained by the nature of type I kerogen in the Green River Formation, which is highly aliphatic.40−42 Weight fractions of monoaromatic compounds (blue bars) are 10−20% at all maturities. Polyaromatic compounds (red, yellow, and purple bars), which cause rapid deactivation of catalyst activity in refinery processes, do not constitute important fractions. A minor fraction (gray bars), 3−13% by weight, cannot be classified as either saturates or aromatics. We expect that these are polar components that passed through the GC columns. The fraction of oil that did not pass through the columns is not accounted for here but is expected to be minimal because the oil phase is defined as the fraction that is volatile under oven conditions. There is disagreement between saturate and aromatic fractions as determined by 2D GC-FID and Iatroscan thin layer chromatography with flame ionization detection (TLCFID) results shown in Figure 7. The results of the two measurements are cross-plotted in Figure 8. On the other hand, the two methods agree on assays of the polar fraction. The gel permeation chromatography results suggest that the molecular size of the C11+ fraction of oils is almost independent of thermal maturity, in agreement with 2D GC results, see Figure 9. GPC measures only the C11+ fraction of oil, so to compare the results obtained by this method with the results obtained by 2D GC-FID, the latter have been normalized by the ratio of the weight of entire oil to the weight of the C11+ fraction of oil. Additionally, the 2D GC-FID residual fraction is neglected; this is expected to result in a 10% error because the residual fraction is approximately 10% of the total 2D GC-FID signal, see Figure 6. Figure 10 shows the comparison between GPC and 2D GC-FID derived compositions, and generally good agreement is found.
Figure 8. Comparison of SARA fractions determined by Iatroscan TLC-FID and 2D GC-FID methods.
Organic CHNSO elemental analysis (Huffman Laboratories, Golden, CO) was performed on the six oils with the highest time−temperature index values. The results are compared to two retort oils and to an internationally traded conventional crude oil in Table 2, along with density data. Concentrations of arsenic, nickel, and vanadium, all measured by ICP-OES, were less than the 5 ppm detection limit of this technique. Iron was found to be less than 7 ppm. Mercury, measured by cold vapor atomic absorption, was less than 0.2 ppm in all cases. These results can be compared to the metal concentrations in a variety of conventional crude oils45,46 and pyrolysis oils.5 NMR measurements were performed on samples with log(TTIARR) values of 0.732, 0.732, 0.948, and 0.948. Spectra for these four samples are nearly identical, as expected from their similar severities of pyrolysis, and consistent with the general independence of oil composition on pyrolysis severity as shown in the 2D GC and Iatroscan measurements reported here for all pyrolysis oils. 13C NMR was used to distinguish aliphatic and aromatic carbon,47,48 and these oils were found to contain 15.6% aromatic carbon and 84.4% aliphatic carbon. 13C NMR identifies slightly more aliphatic carbon and slightly less aromatic carbon than 2D GC. This result is expected, as F
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Figure 9. Evolution of molecular size of the C11+ fraction determined by the GPC method for oils produced over a range of thermal maturities.
Table 3. Relative Abundance of Proton Types Distinguished by 1H NMR Spectroscopy
Table 2. Elemental Analysis of Arabian Light Crude Oil and Three Pyrolysis Oils
density (g/cm3) °API H/C (atomic) S (wt %) N (wt %) a
TOSCO shale oil44
PARAHO shale oil44
semi-open shale oila
0.86
0.91
0.89
0.81−0.85
33 1.84
23 1.58
27 1.60
35−43 1.78−1.88
1.7 0.1
0.76 1.96
0.63 2.15
0.74−0.95 0.46−0.66
relative abundance (%) 28.7 47.5 7.8 11.4 4.1 0.2 0.4
shorter chains due to secondary cracking at elevated pressure in the present experiments.49 The olefin content of these shale oils is considerably smaller and shifted toward internal olefins over terminal olefins compared to the shale oils produced by open pyrolysis of lacustrine kerogens.49 Olefin production is typically suppressed at high pressure, as hydrogen produced from labile donors preferentially hydrogenates olefins rather than escaping the system as is more common at low pressure.50 The range of sulfur contents for high TTI oils is given in Table 2. XANES results from selected pyrolysis oils are presented in Figure 11. Sulfur speciation in pyrolysis oils is found to be nearly independent of pyrolysis conditions. As
Figure 10. Comparison of oil compositions (C11+) as determined by GPC and 2D GC-FID methods.
Arabian light crude43
proton type CH3 CH2 CH alpha aromatic olefin, terminal olefin, internal
This work.
alkylated aromatics are partitioned fully into the aromatic class by 2D GC but are divided by carbon between the aromatic and aliphatic classes by NMR. 1 H NMR results are presented in Table 3. On the basis of hydrogen NMR, the samples were approximately 4% aromatic and 95% aliphatic (summing the CH3, CH2, CH, and alpha protons). This result is consistent with the 13C results, as aliphatic carbons are attached to more protons than aromatic carbons are. The ratio of CH3 to CH2 is greater than typically found for shale oils produced by open (atmospheric pressure) pyrolysis of lacustrine kerogens, a result of the formation of
Figure 11. Distribution of forms of sulfur in oils of various maturities. G
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observed in previous studies,51−53 the sulfur speciation of oils is dominated by thiophenes, and in this respect they are similar to some naturally occurring crude oils.32 The influence of pressure on the yield and quality of oils, as measured by 2D GC, is shown in Figures 12−14. Higher
Figure 14. Weight of chromatographic components, as a percentage of the weight of produced oil. Heating rate = 20 °C/h, plateau temperature = 359 °C, plateau time = 10 h; log(TTIARR) = −0.151, calculated % Ro = 0.90. The lines are guides for the eye.
and 50 atm, while there are significant increases in C4 and C6 alkyl aromatics. Further examples are provided in the Supporting Information. Bitumen. Figure 15 shows the evolution of saturate− aromatic−resin−asphaltene (SARA) fractions of extracted
Figure 12. Weight of chromatographic components of produced oil, as a percentage of the weight of rock pyrolyzed. Heating rate = 20 °C/h, plateau temperature = 359 °C, plateau time = 10 h; log(TTIARR) = −0.151, calculated % Ro = 0.90. The lines are guides for the eye.
Figure 13. The data of Figure 12, with weight of chromatographic components plotted as a percentage of the weight of produced oil. The lines are guides for the eye.
Figure 15. SARA analysis of bitumens extracted from spent shale. Saturates (green bars); aromatics (orange bars); resins + asphaltenes (gray bars).
pressure inhibits the vaporization of oil, thereby increasing secondary cracking reactions. This reduces the yield of oil, due to coking, but improves oil quality by reducing the quantity of heavy fractions. Figure 12 shows the production of each compound class on an absolute basis (weight of hydrocarbon as a percentage of shale weight). At lower pressures, production of each compound class is greater than at higher pressures. The data of Figure 12 are replotted in Figure 13, with the amount of each component shown as a weight percent of the oil produced. These show that for a fixed quantity of oil, elevated pressure gives a more desirable mix of components. Further examples are provided in the Supporting Information. Similar to the saturated fraction, elevated pressure reduces heavy aromatic fractions and increases light aromatic fractions relative to total oil produced. For example, in Figure 14, the C10+ alkyl aromatics produced at 10 atm are largely gone at 30
bitumens with increasing thermal maturity as determined by TLC-FID. In contrast to the produced oils, the extracted bitumens are high in resins and asphaltenes. The atomic H/C ratio of extracted bitumen as determined by organic elemental analysis, Figure 16, decreases with increasing maturation. This is consistent with hydrogen depletion as a result of oil and gas generation and an accompanying increase of aromaticity. The simultaneous observation of H/C ratio decreasing with maturity while SARA fractionation is independent of maturity can be attributed to a change in the composition of the SARA fractions with maturity. The distribution of molecular weights (Figure 17, upper part) and the average molecular weight of bitumen (Figure 17, lower part) were determined by GPC. The average molecular weight of bitumen passes through a maximum with increasing H
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Figure 16. Evolution of atomic H/C ratio of extracted bitumens with increasing thermal maturity. The native state value is plotted at log(TTIARR) = −3.
Figure 18. Evolution of the sulfur content of extracted bitumen with increasing thermal maturity. The native state value is plotted at log(TTIARR) = −3.
Figure 19. XANES determination of sulfur moieties in bitumen.
Figure 17. Evolution of bitumen molecular size (upper part) and average molar weight (lower part) with thermal maturity, as determined by gel permeation chromatography.
thermal maturity, as observed in previous studies.54,55 There is a substantial gap between log(TTIARR) = 0.11 and 0.73; additional experiments in this range would be useful in better understanding these data. The sulfur content in extracted bitumens decreases with thermal maturity, see Figure 18. Sulfur in native state bitumen appears in a variety of moieties, with significant contribution from sulfoxide. Once subjected to pyrolysis, bitumen sulfur is increasingly found as thiophenic sulfur, Figure 19. Gas. The evolution of hydrocarbon gases with increasing thermal maturity is shown in Figures 20 and 21. Gas is predominantly generated in the vitrinite reflectance wet gas window, 1.15 < % Ro < 1.40,37 which corresponds to 0.6
