Subscriber access provided by Queen Mary, University of London
Fossil Fuels
Long time, low temperature reactions of Green River oil shale Yi Fei, Marc Marshall, W. Roy Jackson, Ying Qi, Anthony Romorosa Auxilio, Alan L. Chaffee, Martin L. Gorbaty, and Peter J Cassidy Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b00019 • Publication Date (Web): 13 Mar 2018 Downloaded from http://pubs.acs.org on March 26, 2018
Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.
is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.
Page 1 of 41 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
Long time, low temperature reactions of Green River oil shale Yi Feia, Marc Marshalla, W. Roy Jacksona, Ying Qia, Anthony R. Auxilioa, Alan L. Chaffeea*, Martin L. Gorbatyb and Peter J. Cassidyc
a
School of Chemistry, Monash University, Clayton, Victoria 3800, Australia
b
Fuels Science Consulting, 6635 Via Dante, Lake Worth, FL 33467, USA
c
The Sentient Group, Level 44, Grosvenor Place, 225 George Street, Sydney, NSW 2000, Australia
Corresponding Author * Tel.: +61 9905 4626. E-mail:
[email protected] 1 ACS Paragon Plus Environment
Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Abstract: Reactions of water washed chunks of a deeply buried Green River oil shale (28802920 feet, well below the water table) have been carried out in N2-H2O and CO-H2O for up to 28 days at temperatures in the range 280-370oC. Large variations in yields of liquid products were observed for reactions below 330-340oC. These were attributed to varying mineralogy in the chunks, as the variations disappeared for reactions of ground samples or reactions above 330340oC, where the chunks disintegrated. Liquid product yields of up to 70 wt% dry mineral matter free (dmmf) could be obtained from the chunks at temperatures as low as 320oC, provided long reaction times of 14 or 28 days were used. Particularly at lower temperatures, yields were higher under N2 than under CO but the quality of the CO-H2O products tended to be better than that of N2-H2O products. The liquid products contained 1-2 wt% nitrogen, were high in aliphatic material and contained significant amounts of heavily substituted aromatic rings. Keywords: Green River oil shale; liquefaction; oil structure; nitrogen-water; carbon monoxidewater; long reaction times; ground samples vs chunks
2 ACS Paragon Plus Environment
Page 2 of 41
Page 3 of 41 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
1
Introduction
There has been long standing interest in obtaining liquid products from Green River oil shales 1. The shales represent a major portion of the world’s oil shales 2 and have the capacity to produce large amounts of oil for transport, heating and other uses. The shales occur over a wide range of depths, with deposits stretching down to around 1000 m. In spite of this a large number of workers have described methods for extracting oil from the mined shale (ex-situ liquefaction). The methods are based on retorting the mined shale using different technologies such as those developed by the U.S. Bureau of Mines 3 and the Tosco process 4. The thickness and depth of burial of the Green River oil shale encouraged interest in ‘in situ’ processes, where the oil shale is not mined but pyrolysed in place, as early as 1924 5. The U.S. Bureau of Mines began study of ‘in situ’ retorting in 1963 by exploring methods of fracturing the shale to increase its low permeability and open up paths for hot gas introduction into the shale 6-8. They then progressed to field tests 9-11 and environmental monitoring 12. This work concentrated on physical methods to initiate increase in shale permeability and was not applied to more deeply buried shale where other methods could be used. Laboratory experiments supplemented field tests 13-15. In general, the laboratory experiments were carried out without added water. Since then, a number of ‘in situ’ processes have been developed e.g. by Sinclair Oil and Gas Co16, Shell16, Exxon 17, and Chevron 18 based on retorting. Advantages of an ‘in situ’ process include: exploitation of deep deposits becomes easier, mining, transportation and crushing are cheaper; no solid waste disposal so that the process is environmentally more desirable if mineral leaching or harmful side effects are absent or controllable; and lower grade oil shale can be economically utilized 16. Also ‘in situ’ processes, if carried out at low temperature, produce less CO2 and it may be possible to trap CO2 produced, thus reducing harm to the environment 19. Disadvantages of an ‘in situ’ process are the expense of drilling, the generally lower recovery of oil compared to that for an ‘ex situ’ process, contamination of aquifers and the difficulty of controlling heat propagation in the low permeability oil shale 16. The contamination of water supply could be overcome by a method patented by Shell involving the formation of ice walls round the extraction zone 20. The properties of some parts of the Green River deposit may assist in overcoming the permeability problem. The upper part of the deposit, which extends down to 1000 m below the surface, can be divided into three zones: the Mahogany zone at the top, compact and of low alkali content; the leached zone from which alkali, such as nahcolite, was removed by percolating water over geological time; and the saline zone containing large amounts of nahcolite and dawsonite 2. The leaching of the alkali has increased permeability of the leached zone and experiment and calculations have been made exploring the possibility of injecting superheated steam into the leached zone to obtain oil from it 21, 22. For the saline zone, several groups have considered preliminary removal of the nahcolite by various methods to introduce permeability into the oil shale followed by retorting to recover oil and perhaps dawsonite. Apart from the permeability benefits, the nahcolite and dawsonite are valuable products 23. Shell carried out experiments in which the nahcolite was leached out of the oil shale with hot water followed or accompanied by steam injection to retort the shale 24. The Multi-Mineral Corporation proposed to separate nahcolite by size separation after crushing the raw oil shale because nahcolite tends to concentrate in the finer size fraction 25, 26. Solution mining of nahcolite and dawsonite by injecting NaOH solution before retorting was suggested by Kalmar 27. A proposal for solution mining of nahcolite and recovery of some of the oil was made more recently by Daub 28. The saline zone of the Green River deposit includes dolomite, calcite, nahcolite and dawsonite, which are alkaline. The possibility arises of using this alkalinity, together with readily available water, to carry out CO-steam reactions of the kerogens in the shale in a manner that might be 3 ACS Paragon Plus Environment
Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
expected to lead to enhanced liquefaction. The water itself might increase conversion and improve the quality of the oil 29 so that CO-H2O reactions should be compared with N2-H2O rather than dry N2 reactions. Reactions of low rank coals with CO and water have been shown to be promoted by addition of alkalis such as sodium aluminate 30. Similar evidence for CO promotion comes from reactions of a Jordanian oil shale in the presence of water 31. Reactions of Green River oil shale in CO-H2O 32-35 gave yields at least equal to those obtained by Fischer Assay at low temperatures and oil differing in its characteristics from conventional retorted oil. They did not consider the effect of added alkali. All the CO-H2O reactions discussed above used relatively short reaction times and were carried out ‘ex situ’. Hot water or steam has also been used as a reactant to reduce the viscosity and molecular weight of heavy oils to permit their recovery from underground reservoirs and upgrade these oils by removing heteroatoms such as S 36-38. The water reacts with oil compounds to remove heteroatoms and breaks up to liberate hydrogen which can hydrogenate other oil compounds 37. Metal 36, 37 or carbon 39 catalysts are usually added to promote hydrogenation and bond cleavage and inhibit polymerization 37. Like CO-H2O reactions, these reactions involve hydrogen from water but the mechanism of catalyst action is different; the alkali catalysts for the CO-H2O reaction promote production of an intermediate which reacts with the organic substrate 40. Thus, the CO-H2O reactions of oil shale will not necessary evolve in the same way as aquathermolysis reactions. The earlier work on CO/H2O reactions of oil shale and coal led us to believe that it would be worthwhile investigating the effect of CO on reactions of a Green River Formation shale from the saline zone in the presence of water at low temperature (280-370oC) and long reaction times (14 to 28 days). The temperature range was chosen on the basis of the results of short-time reactions of dry Colorado oil shale in similar autoclaves in Amer et al41. Some earlier work on long reaction time dry pyrolysis Colorado oil shale 15, 42-45 has been published, but only brief accounts of the effect of reaction conditions on yield or product characteristics have been published15, 43, 45. Two physical forms of oil shale were studied. The first was a powder, of sufficiently small particle size that 10 g representative samples could be easily obtained. In practice, pieces of much larger size would be used, so that experiments were also carried out on 2-5 g chunks obtained from the same bore and depth interval as the powder. 2 2.1
Materials and methods Chemicals
CO and N2 were purchased from British Oxygen Company (BOC). Liquid-chromatography grade dichloromethane (CH2Cl2), n-hexane (C6H14) and tetrahydrofuran (THF) were supplied by Merck. Hydrochloric acid (32%), UNIVAR grade, was bought from Ajax Finechem Pty Ltd. 2.2
Preparation of oil shale samples
A suite of C11-C17)
heavier oil (>C17)
N2
320
8
51
35
14
N2
320
82
45
24
31
CO
320
22
50
32
17
32
30
37
oil shale powder
29 ACS Paragon Plus Environment
Energy & Fuels 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 30 of 41
Table 7 Surface areas and pore volumes for the original oil shale powder and chunks and for the THF insolubles from three chunk reactions. Reaction conditions: ~10 g charge, 1:1 H2O:oil shale, heat up time 30-60 minutes, gas pressure 3 MPa (cold), 14 day reaction time in 100 mL autoclaves. The errors are standard deviations from the least-squares fits. pore av pore macropore mesopore CH2Cl2 solubles surface area surface area volume o (N ) (CO ) vol vol width (N2) gas T ( C) +H2O+HC gas 2 2 (CO2) wt% dmmf powder chunks N2 N2 CO
320 320 320
82 8 22
2
m /g 1.20 ± 0.03 0.30 ± 0.01 5.69 ± 0.10 4.22 ± 0.08 3.04 ± 0.05
3
cm /g 0.0047 0.0039 0.0027 0.0052 0.0040
17.5 14.5 10.1 19.5 15.0
nm 21 29 29 30 27
30 ACS Paragon Plus Environment
3
cm /g 0.256
0.009
0.018
0.037
0.525 0.338 0.221
0.035 0.037 0.035
Page 31 of 41 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
Figure captions Figure 1 Arrhenius plots for 14 day chunk reactions. Reaction conditions: ~10 g charge, 1:1 H2O:oil shale, heat up time 30-60 minutes, gas pressure 3 MPa (cold) in 100 mL autoclaves. (a) N2 (b) CO Figure 2 Arrhenius plots for 28 day chunk reactions. Reaction conditions: ~10 g charge, 1:1 H2O:oil shale, heat up time 30-60 minutes, gas pressure 3 MPa (cold) in 100 mL autoclaves. (a) N2 (b) CO Figure 3 Alkene/alkane ratio for C2 and C3 gases produced in chunk reactions. The values for multiple reactions under the same conditions have been averaged. Reaction conditions: ~10 g charge, 1:1 H2O:oil shale, heat up time 30-60 minutes, gas pressure 3 MPa (cold), 14 day reaction time in 100 mL autoclaves. Figure 4 Comparison of TICs of py-GC-MS from oil shale powder and THF insolubles from a chunk reaction with only 8 wt% dmmf yield of CH2Cl2 solubles+H2O+HC gas. Reaction conditions: ~10 g charge, 1:1 H2O:oil shale, heat up time 30-60 minutes, N2 pressure 3 MPa (cold), 320oC reaction temperature,14 day reaction time in 100 mL autoclaves. Figure 5 XRD of THF insolubles from chunk reactions with 8 wt% dmmf yield of CH2Cl2 solubles+H2O+HC gas (low conversion) and 82 wt% dmmf yield of CH2Cl2 solubles+H2O+HC gas (high conversion). Reaction conditions: ~10 g charge, 1:1 H2O:oil shale, heat up time 30-60 minutes, N2 pressure 3 MPa (cold), 320oC reaction temperature,14 day reaction time in 100 mL autoclaves.
31 ACS Paragon Plus Environment
Energy & Fuels
a
b 4.8
4.4
4.0
y = -9,483.33x + 19.72 R² = 0.45 3.6
3.2
2.8
2.4
2.0 0.00160
0.00165
0.00170
0.00175
0.00180
ln(CH2Cl2 sol+H2O+HC gas) wt% dmmf
4.8
ln(CH2Cl2 sol+H2O+HC gas) wt% dmmf
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 32 of 41
4.4
4.0
3.2
2.8
2.4
2.0 0.00155
0.00185
y = -10,438.26x + 20.87 R² = 0.38
3.6
0.00160
0.00165
1/T (K-1)
1/T (K-1)
Y Fei et al. Figure 1
32 ACS Paragon Plus Environment
0.00170
0.00175
0.00180
Page 33 of 41
b
a
4.8
4.4
y = -13,629.55x + 27.05 R² = 0.75
4.0
3.6
3.2
2.8
ln(CH2Cl2 sol+H2O+HC gas) wt% dmmf
4.8
ln(CH2Cl2 sol+H2O+HC gas) wt% dmmf
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
4.4
y = -14,408.44x + 28.00 R² = 0.47
4.0
3.6
3.2
2.8
2.4
2.4
2.0 0.00164
2.0 0.00164 0.00166
0.00168
0.00170
0.00172
0.00174
0.00166
0.00168
0.00170
0.00176
1/T (K-1) 1/T (K-1)
Y Fei et al. Figure 2
33 ACS Paragon Plus Environment
0.00172
0.00174
0.00176
Energy & Fuels
N2 C2 N2 C3 CO C2 CO C3
2.4
2.2
alkene/alkane
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 34 of 41
2.0
0.4
0.2
0.0
-0.2 280
290
300
310
320
330
340
350
360
o
Temperature ( C)
Y Fei et al. Figure 3
34 ACS Paragon Plus Environment
370
380
Page 35 of 41
oil shale powder
THF insol
1.4E+06
9.0E+05 8.0E+05
1.2E+06
7.0E+05 1.0E+06
Abundance
6.0E+05
Abundance
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
8.0E+05
6.0E+05
5.0E+05 4.0E+05 3.0E+05
4.0E+05 2.0E+05 2.0E+05
1.0E+05
0.0E+00
0.0E+00 0
5
10
15
20
25
30
35
40
45
50
0
5
Time (min)
10
15
20
Time (min)
Y Fei et al. Figure 4
35 ACS Paragon Plus Environment
25
30
35
40
45
Energy & Fuels
low conversion
high conversion CD203
400
400
CD210
dolomite
dolomite
350
350
plagioclase 300
plagioclase
300
Intensity (a.u.)
Intensity (a.u.)
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 36 of 41
250 200 150 100 50
250 200 150 100 50 0
0 0
10
20
30
40
50
60
70
80
0
90
10
20
30
40
50
2 θ (degrees)
2 θ (degrees)
Y Fei et al. Figure 5
36 ACS Paragon Plus Environment
60
70
80
90
Page 37 of 41
b
a 4.8
4.4
4.0
y = -9,483.33x + 19.72 R² = 0.45
3.6
3.2
2.8
2.4
2.0 0.00160
0.00165
0.00170
0.00175
0.00180
0.00185
ln(CH2Cl2 sol+H2O+HC gas) wt% dmmf
4.8
ln(CH2Cl2 sol+H2O+HC gas) wt% dmmf
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
4.4 4.0
y = -10,438.26x + 20.87 R² = 0.38
3.6 3.2
2.8 2.4 2.0 0.00155
0.00160
0.00165
1/T (K-1)
1/T (K-1)
Y Fei et al. Figure 1
ACS Paragon Plus Environment
0.00170
0.00175
0.00180
Energy & Fuels
b
a
4.8
4.4
y = -13,629.55x + 27.05 R² = 0.75
4.0 3.6 3.2 2.8
ln(CH2Cl2 sol+H2O+HC gas) wt% dmmf
4.8
ln(CH2Cl2 sol+H2O+HC gas) wt% dmmf
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 38 of 41
4.4
y = -14,408.44x + 28.00 R² = 0.47
4.0 3.6
3.2 2.8 2.4
2.4 2.0 0.00164
2.0 0.00164 0.00166
0.00168
0.00170
0.00172
0.00174
0.00166
0.00168
0.00170
0.00176
1/T (K-1)
1/T (K-1)
Y Fei et al. Figure 2
ACS Paragon Plus Environment
0.00172
0.00174
0.00176
Page 39 of 41
N2 C2 N2 C3 CO C2 CO C3
2.4
2.2
alkene/alkane
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
2.0
0.4
0.2
0.0
-0.2 280
290
300
310
320
330
340
350
360
o
Temperature ( C)
Y Fei et al. Figure 3
ACS Paragon Plus Environment
370
380
Energy & Fuels
oil shale powder
THF insol
1.4E+06
9.0E+05
8.0E+05
1.2E+06
7.0E+05 1.0E+06
Abundance
6.0E+05
Abundance
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 40 of 41
8.0E+05 6.0E+05
5.0E+05 4.0E+05 3.0E+05
4.0E+05 2.0E+05 2.0E+05
1.0E+05
0.0E+00
0.0E+00 0
5
10
15
20
25
30
35
40
45
50
0
Time (min)
5
10
15
20
Time (min)
Y Fei et al. Figure 4
ACS Paragon Plus Environment
25
30
35
40
45
Page 41 of 41
high conversion
low conversion CD203
400
400
CD210
dolomite
350
dolomite 350
plagioclase
300
plagioclase
300
250
Intensity (a.u.)
Intensity (a.u.)
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Energy & Fuels
200 150 100
250 200 150 100 50
50
0
0 0
10
20
30
40
50
60
70
80
90
0
10
20
30
40
50
2 θ (degrees)
2 θ (degrees)
Y Fei et al. Figure 5
ACS Paragon Plus Environment
60
70
80
90
