16
C h e m i c a l a n d R e t o r t i n g P r o p e r t i e s of Selected A u s t r a l i a n Oil S h a l e s A. EKSTROM, H. J. HURST, and C. H. RANDALL Lucas Heights Research Laboratories, CSIRO Division of Energy Chemistry, Private Mail Bag 7, Sutherland, NSW, 2232, Australia The rates of o i l , hydrogen, methane, carbon dioxide and carbon monoxide evolution during the retorting of five Australian oil shales at linear heating rates have been determined and analysed in terms of the Anthony-Howard model for non-isothermal kinetics. Significant differences in the retorting properties of these shales were obtained, particularly with respect to the rates of the hydrogen and carbon dioxide evolution. Much of the present understanding of the chemical processes occurring during the heating and retorting of oil shales is based on work carried out with shales from the American Green River deposit (1-3). However, this shale is not typical of oil shales found in other deposits, and comparative studies of the chemical properties and retorting chemistry of a variety of shales might provide further insights into the undoubtedly very complex chemistry of these materials. This paper presents results of some laboratory scale studies of the chemical and retorting properties of representative samples from five Australian oil shale deposits. In general terms, the results indicate that these shales differ significantly in their chemical properties both from each other and from the shale of the Green River deposit. Experimental Procedures The kinetics of oil and gas formation during the retorting of the shales were determined using an apparatus essentially identical to that described by Campbell et al (_2). Heating rates of 3 K/min were used and the argon carrier gas flow rates were 130 cc/min for the determination of oil formation, and 30 cc/min for determination of the rates of gas evolution. The shale samples used in these studies were sized, and dried at 110°C for 12 hours prior to use. e
0097-6156/ 83/ 0230-0317S06.00/ 0 © 1983 American Chemical Society
318
GEOCHEMISTRY AND CHEMISTRY OF OIL SHALES
Déminéralisation of the shales was c a r r i e d out using HF/HC1 d i g e s t i o n on -90 μ m sized samples, followed by extensive washing with demineralised water. The ash content of the kerogens so obtained was determined by heating samples to 800°C i n a i r . Solvent e x t r a c t i o n studies of the demineralised shale were c a r r i e d out using conventional soxhlet e x t r a c t o r s . TGA s t u d i e s were c a r r i e d out using a computer-controlled Cahn thermobalance (Model No. RG2000) of conventional design. Elemental analyses were performed on samples d r i e d at 110 C and were c a r r i e d out by the A u s t r a l i a n M i c r o a n a l y t i c a l Service of the A u s t r a l i a n Mineral Development L a b o r a t o r i e s . e
Results and D i s c u s s i o n The samples of shale used i n t h i s work a l l o r i g i n a t e d i n various shale deposits located near the c o a s t a l areas of c e n t r a l Queensland. These deposits are b e l i e v e d to be of T e r t i a r y age and of l a c u s t r i n e o r i g i n , and i n contrast to the Green River deposit contain only small amounts of mineral carbonates. As summarised i n Table 1, the chemical composition of these shales d i f f e r widely, ranging from the Nagoorin carbonaceous shale with an organic carbon content of 65%, to the Duaringa shale with an organic carbon content of 11%. The p r e c i s e o r i g i n and nature of the black or carbonaceous shales found i n the Nagoorin and Condor deposits are not completely understood at present but, from a chemical viewpoint, s i g n i f i c a n t d i f f e r e n c e s between the black and normal shales are r e a d i l y apparent. Thus the black shales are g e n e r a l l y c h a r a c t e r i s e d by a high kerogen content of lower H/C r a t i o and a markedly lower o i l y i e l d per gram of organic carbon i n the shale. As w i l l be shown below, the k i n e t i c s of the gas e v o l u t i o n from the black shales a l s o d i f f e r from those of the normal s h a l e s . The r e s u l t s of e x t r a c t i o n of the kerogens i s o l a t e d from the Stuart and Nagoorin shales with solvents of i n c r e a s i n g p o l a r i t y (Table 2) i n d i c a t e that these kerogens contain s i g n i f i c a n t proportions of r e l a t i v e l y low molecular weight, and presumably polar compounds. The f r a c t i o n of kerogen e x t r a c t a b l e with a given solvent appears to be comparable with the r e s u l t s of s i m i l a r studies on the Green River kerogen (4) and indeed with those obtained for bitumenous coals (5,6). The appearance of the extract ranged from pale waxes for the less polar solvents to black, l u s t r o u s s o l i d s for p y r i d i n e , dimethyl formamide and dimethyl sulphoxide. The nature of e x t r a c t s are not known at present, but elemental a n a l y s i s on the dimethyl sulphoxide e x t r a c t s showed these to have a lower H/C and higher 0/C, S/C and N/C r a t i o s than the o r i g i n a l kerogen. This r e s u l t suggests that these e x t r a c t s are composed of heteroatom c o n t a i n i n g aromatic compounds. This very t e n t a t i v e conclusion i s supported by TGA r e s u l t s which showed that p y r o l y s i s of the e x t r a c t s r e s u l t e d i n a s i g n i f i c a n t l y higher proportion of involatile residues when compared to the o r i g i n a l kerogen.
12 25
12.3 19.3
93
178
Condor
Stuart
Data supplied Determined on These f i g u r e s Determined on e
by Southern P a c i f i c Petroleum (NL). shale d r i e d at 110°C f o r 12 hours. are approximate only. kerogen d r i e d at 110 C f o r 12 hours.
0.78
1.48
4.7
(a) (b) (c) (d)
14
86
0.92 1.48
0.76
0.24
1.11
1.42
0.36
O i l Y i e l d as cc of o i l / g organic carbon
0.93
H/C Ratio of Kerogen(d)
0.3
3.9
0.4
Duaringa
11.0
33
28.3
69
Condor Carbonaceous
0.2
72
65.2
232
Nagoorin Carbonaceous
Ash Content of Kerogen (wt. %)
Kerogen Content (wt.%)(c)
Organic Carbon(b)
Sample
%
Fischer Assay(a) (Litres/ Tonne)
TABLE I. SUMMARY OF THE PROPERTIES OF OIL SHALES USED
|
m
GEOCHEMISTRY AND CHEMISTRY OF OIL SHALES
320
TABLE I I . EFFECT OF SOLVENT POLARITY ON THE EXTRACTION OF KEROGEN
% Kerogen E x t r a c t e d Solvent
Stuart
Hexane
2.4
2.0
Acetone
4.4
5.8
Chloroform
6.0
6.2
Methanol
7.9
3.2
Pyridine
9.9
16.4
Dimethyl f ormamide
19.5
25.6
Dimethylsulphoxide
27.2
30.2
Nagoorin
16.
EKSTROM ET AL.
321
Australian Oil Shales
The r e t o r t i n g p r o p e r t i e s of the various o i l shales heated at a l i n e a r rate of 3°K/min i n an i n e r t gas atmosphere are summarised i n Table 3. The most notable features of these data i s the r e l a t i v e l y high water y i e l d obtained from the r e t o r t i n g of two carbonaceous shales, the poor o i l y i e l d ( r e l a t i v e to the F i s c h e r assay) obtained by t h i s technique and the very high concentrations of organic carbon remaining i n the char for the two carbonaceous shales. The low o i l y i e l d s appear to be at l e a s t i n part a consequence of the low heating rates used and recent work (7) showed that at a heating rate of 15°K/min, an o i l y i e l d equivalent to the F i s c h e r assay can be obtained for the Condor shale. In t h i s r e s p e c t , the Condor shale studied i n the present work appears to d i f f e r s i g n i f i c a n t l y from the Green River shale, for which i t has been shown (8,9) that the o i l yields decrease s i g n i f i c a n t l y only at heating rates below l K/min. It i s p o s s i b l e that the much greater e f f e c t observed for the present shales i s a r e f l e c t i o n of the greater tendency of the o i l produced to undergo coking r e a c t i o n s . T y p i c a l r e s u l t s of k i n e t i c studies on the rates of o i l formation from various shales ( F i g u r e 1, Table 4) show some d i f f e r e n c e s i n k i n e t i c behaviour amongst the various shales, although the general appearance of the curves and the temperatures at which the o i l y i e l d s are maximum are s i m i l a r to those reported for the Green River Shale ( 2 ) . Least squares analyses of these data i n terms of the Anthony-Howard model (3,10) f o r non-isothermal k i n e t i c s (Table 4) showed that the r e s u l t s of the Nagoorin, Condor, Stuart and Duaringa shales could be reproduced q u i t e w e l l by a s i n g l e process with a c t i v a t i o n energies i n the range 200-232 kJ mol" and r e l a t i v e l y small (^0-5 kJ mol-1) d i s t r i b u t i o n parameters. By comparison, the a c t i v a t i o n energy for the e v o l u t i o n of o i l from the Green River shale heated at 2°K/min has been determined (3) as 219 kJ mol-1. Only i n the case of the Condor Carbonaceous shale was i t necessary to consider two distinct processes f o r the o i l formation, i n which the f i r s t process was responsible f o r 54% of the t o t a l o i l y i e l d . The e f f e c t s of temperature on the rates of hydrogen, methane, carbon monoxide and carbon dioxide e v o l u t i o n from the f i v e o i l shales are shown i n Figures 2-5, the i n t e g r a t e d gas y i e l d s summarised i n Table 5, and the a c t i v a t i o n parameters f o r various representative c o n t r i b u t i n g processes determined by a n a l y s i s of the data i n terms of the Anthony-Howard equation compiled i n Table 6. The accuracy with which the gas e v o l u t i o n curves could be described by t h i s procedure i s i l l u s t r a t e d i n f i g u r e 6, which compares the c a l c u l a t e d and observed rates of methane e v o l u t i o n from the Condor carbonaceous s h a l e . However, other cases, e.g., the H e v o l u t i o n p r o f i l e from Duaringa shale, were much more complex, and f i t s of the Anthony-Howard equation to only the major c o n t r i b u t i n g processes were attempted. e
1
2
6.2 10.3
179
86
Stuart 5.5 2.9
4.7
12.7
(c) Expressed as % of weight
of d r i e d
shale
8 0
6 7
P a r t i c l e s i z e : - -3.3 mm
83.6
75.9
82.3
3.8
6.0
7 9
6 0
79.9
+ Losses
3.0
6.1
Gas
15 1
9.7
12.8
Char %
62.4
Water %
Oil %
(c)
C h a r a c t e r i s t i c s (a)
Product Y i e l d s
Summary o f R e t o r t i n g
(a) Heating r a t e of 3 C/minute i n helium flowing at 130 cc/minute. (b) Samples d r i e d at 120 C f o r 12 hours
e
3.4
93
Condor
e
14.3
69
Condor Carbonaceous
Duaringa
20.1
232
F i s c h e r Assay Litres/Tonne
Nagoorin Carbonaceous
Sample
Weight Loss on D r y i n g ( b ) %
Table I I I .
+1.4
6.8
14.8
5.2
50. 1
75.8
Organic Carbon i n Char %
Oil
Fischer
Yield
73
85
75
99
62
Assay)
(% of
c/3
> r m
χ
τι Ο r
< Ο
Η
c73
> α ο χ m
Ά
m
Π χ
Ο m Ο
Ν) Ν)
16.
EKSTROM ET AL.
Australian Oil Shales
323
TEMPERATURE (DEGREES C) Figure 1. Effect of temperature on the rate of oil evolution expressed per gram of organic carbon. Key: Curve I, Nagoorin shale; Curve 2, Condor carbonaceous shale; Curve 3, Stuart shale.
14.0
Duaringa 225
215
232
195 206
5
5
0.05
1 8
5
430
445
455
420 480
420
CO
Temperature at which r a t e of o i l formation i s maximum
Values determined by l e a s t
(c) kJ mol -1
σ
(a) Heating rate o f 3°C/minute, c a r r i e r gas flow rate o f 130 cc/minute. squares f i t of data to Anthony-Howard equation. (b) LogjQ (Preexponential f a c t o r ) (c) D i s t r i b u t i o n parameter of a c t i v a t i o n energies.
13.0
Stuart
12.0 12.0
201
12.4
14.0
Process (1) (2)
Log (A)
Condor
Condor Carbonaceous
Nagoorin Carbonaceous
Sample
Activation Energy kJ mol -1
(b)
TABLE IV. SUMMARY OF ACTIVATION PARAMETERS FOR OIL FORMATION^)
TEMPERATURE (DEGREES C)
DURING A H2 EVOLUTION
Figure 2. Effect of temperature on the rate of hydrogen evolution expressed per gram of organic carbon. For the Condor shale, Curve 1 represents the normal shale; Curve 2 represents the carbonaceous shale.
CONDOR H2 EVOLUTION
Figure 3. Effect of temperature on the rate of methane evolution expressed per gram of organic carbon. For the Condor shale, Curve 1 represents the normal shale; Curve 2 represents the carbonaceous shale.
r m oo
>
3C
00
r
g
Ο τι
Η
Ο η m
2!
>
οο Η
2
ο m Ο η χ m
Ο
U) Ν)
1.1
TEMPERATURE (DEGREES C)
DURINGA CO EVOLUTION
Figure 4. Effect of temperature on the rate of carbon monoxide evolution expressed per gram of organic carbon. For the Condor shale, Curve 1 represents the normal shale; Curve 2 represents the carbonaceous shale.
TEMPERATURE (DEGREES C)
CONDOR CO EVOLUTION
TEMPERATURE (DEGREES C)
DURINGA C02 EVOLUTION
Figure 5. Effect of temperature on the rate of carbon dioxide evolution expressed per gram of organic carbon. For the Condor shale, Curve 1 represents the normal shale · Curve 2 represents the carbonaceous shale. '
TEMPERATURE (DEGREES C)
CONDOR C02 EVOLUTION
™
4 (33) 7 (36) 3 (29)
13 (110)
-
11 (100)
Condor
Stuart
(a) Heating r a t e : - 3.0°C/minute (b) At 0°C and 0.1 MPa pressure. of organic carbon.
6 (52)
17 (86)
21 (171)
17 (60)
73 (113)
CO 2
7 (63)
13 (67)
20 (162)
7 (58)
23 (35)
co
Figures i n brackets are the gas y i e l d s expressed as cc
14 (50)
28 (100)
Condor Carbonaceous
Duaringa
20 (31)
4
47 (72)
CH
Gas Y i e l d s (cc/g) (b)
Nagoorin Carbonaceous
Sample
TABLE V. TOTAL GAS YIELDS TO 850°C(a)
Figure 6. Comparison of the observed and calculated rate of methane evolution expressed per gram of organic carbon from Condor carbonaceous shale. Key: , calculated from the Anthony-Howard equation using the parameters summarized in Table VI; ·, experimental data.
.8
£3
16.
EKSTROM ET AL.
Australian Oil Shales
331
Hydrogen. Examination of the hydrogen e v o l u t i o n p r o f i l e s shows a s t r i k i n g d i f f e r e n c e between those observed f o r the carbonaceous shales and those of the normal shales. For the two carbonaceous s h a l e s , hydrogen e v o l u t i o n reaches a maximum i n the temperature range 700-720°C with a minor c o n t r i b u t i o n from a process having a maximum at 600°C. As summarised i n Table 6, the a c t i v a t i o n energies are i n the range 300-320 k J m o l " l f o r the 600°C process, and 360-380 k J mol-1 f o r the 700°C process. The hydrogen e v o l u t i o n from these samples thus occurs i n a temperature range i n which the secondary p y r o l y s i s r e a c t i o n s of the residues which remain after the primary bitumen decomposition i s complete are thought to take place (2). In c o n t r a s t , the hydrogen e v o l u t i o n rates from the Condor and Duaringa d e p o s i t s resemble those observed f o r the Green R i v e r Shale (2) and show a sharp peak at 460 C, c l o s e to the temperature at which the o i l formation i s maximum. For the Duaringa shale t h i s process i s associated with an a c t i v a t i o n energy of ^ 165 k J mol-1 and i s followed by f u r t h e r hydrogen e v o l u t i o n obviously comprising many processes o c c u r r i n g i n the secondary p y r o l y s i s r e g i o n . e
Methane. The methane e v o l u t i o n p r o f i l e s f o r a l l f i v e shale samples are s u r p r i s i n g l y s i m i l a r , but occur at s i g n i f i c a n t l y higher temperatures than has been observed (2) f o r the Green River shale. Although some methane e v o l u t i o n accompanies the o i l formation, the major part i s formed i n the secondary p y r o l y s i s r e g i o n . At l e a s t three major processes with maxima i n the v i c i n i t y of 500, 580 and 700°C appear to c o n t r i b u t e to the t o t a l methane formation. A c t i v a t i o n energies f o r these processes were determined f o r Condor carbonaceous shale and are summarised i n Table 6. Carbon D i o x i d e . The carbon d i o x i d e e v o l u t i o n p r o f i l e s f o r the Nagoorin, Uûïâringa and Condor carbonaceous shales are characterised by significant contributions commencing at temperatures as low as 150°C. I t i s u n l i k e l y that these processes are the r e s u l t of m i n e r a l decomposition r e a c t i o n s , and t h e i r presence must r e f l e c t a c o n t r i b u t i o n from t h e r m a l l y unstable components of the kerogen. A further major c o n t r i b u t i o n to the CO^ y i e l d from these shales was found at temperatures corresponding to the maximum r a t e of o i l f o r m a t i o n , but l i t t l e CO2 formed i n the secondary p y r o l y s i s temperature range. In t h i s r e s p e c t , the behaviour of these shales d i f f e r s s i g n i f i c a n t l y from the Green River shale which were reported (2) to show only a n e g l i g i b l e C0 e v o l u t i o n r a t e accompanying the o i l r e l e a s e , but a very large r a t e at temperatures above 550°C r e s u l t i n g from the decomposition of the carbonate m i n e r a l s . The CO2 e v o l u t i o n from the Condor and Stuart shales shows sharp peaks at 500°C superimposed on a peak corresponding to the temperature at which the o i l e v o l u t i o n occurs. These sharp w a s
2
(a) (b) (d) (d)
2
co
H2
Duaringa
1
1
1
1
!
3
1
1
3
1
Process
460
450
460 500 580
600 730
9.0
9.7
9.7 12.9 12.9
15.8 15.8
3.0 8.0 15.0 8.0 8.0
165
174
178 223 249
297 361
120 148 256 287 330
318 384 110 140 182
17.0 17.0 8.0 8.0 8.0
570 700 280 400 600 300 430 500 570 700
Ε kJ mol-1
(a) Log (A) s-1
Temperature at which r a t e of process i s maximum, °C
LoglO ( P r e e x p o n e n t i a l f a c t o r D i s t r i b u t i o n parameter of a c t i v a t i o n energy, F r a c t i o n a l C o n t r i b u t i o n of the process considered to the t o t a l gas y i e l d . Only the process with a maximum r a t e at the i n d i c a t e d temperature was c o n s i d e r e d
CO
CH4
CO2
H2
CH4
9
2
C0
H
Gas
Stuart
Condor
Condor Carbonaceous
Nagoorin Carbonaceous
Sample
1.00
1.00
1.00 0.40 0.60
0.26 0.74
0.40 0.60 0.36 0.42 0.22
0.14 0.86 0.23 0.57 0.20
(c) F r a c t ion
i n the a n a l y s i s of the d a t a .
0.05
11
0.05 10 21
23 29
18 6 12 14 20
20 31 8 8 8
(b) σ kJ mol-1
TABLE VI. SUMMARY OF REPRESENTATIVE PARAMETERS DETERMINED BY FITTING THE ANTHONY-HOWARD EQUATION TO THE RATES OF GAS EVOLUTION
C/5
r m
X >
r
16. EKSTROM ET AL.
Australian Oil Shales
333
peaks are probably associated with the decomposition of mineral constituents of the shale, but further work with acid washed shales would be required to confirm this proposition. Carbon Monoxide. All shale samples showed a significant peak in the CO evolution rates in the temperature range over which oil evolution occurs. At these relatively low temperatures, it is unlikely that the reaction between CO2 residual char could be a significant source of carbon monoxide (2), and it appears that for these shales and in contrast to the Green River shale (2), the decomposition of the kerogen results in the formation of CO. In the case of the Stuart shale, the processes leading to the formation of the CO in the low temperature range are characterised by a mean activation of % 174 kJ mol-1 and a distribution of 11 kJ mol-1 (Table 6). In conclusion, the results of this study have shown that the retorting properties, and particularly the gas evolution profiles observed for these five selected Australian shales differ significantly from similar results obtained for Green River shales. However, of particular interest are the results obtained for the two carbonaceous shales. The retorting of these materials was found to be characterised by the evolution of hydrogen in a temperature range normally associated with secondary pyrolysis reactions, by an oil yield low in comparison to the high organic carbon content of these shales, and by the consequent very high residual organic carbon in the spent shale. Preliminary NMR studies (11) of the oil produced from the Condor shales have also shown the presence of high concentrations of phenolic materials only in the oil from the carbonaceous material. These properties are more characteristic of brown and even bituminous coals, and it is appears that the kerogen of the carbonaceous shales contains a substantial proportion of material of lignin origin (12). A pétrographie comparison of these shales and a more detailed comparison of the composition of the oil produced from the carbonaceous and normal shales may provide further confirmation of this hypothesis. a n d
Acknowledgments We wish to thank Mr. John Gannon of Southern Pacific Petroleum NL for the samples of oil shale used in this work and Mr. Jack Kristo for his assistance in the experimental work. Literature Cited 1. 2.
Campbell, J . H . , Koskinas, G.J. and Stout, N.D. Fuel (1978), 57, 376. Campbell, J . H . , Koskinas, G.J. Galligos, G. and Gregg, M. Fuel (1980) 59, 718.
334 3. 4. 5. 6.
7. 8. 9. 10. 11. 12.
geochemistry and chemistry of oil shales Campbell, J.H., Galligos, G. and Gregg, M. Fuel (1980) 59, 727 Robinson, W.E. 'Kerogen of the Green River Formation' Chpt. 26 in 'Organic Geochemistry, Methods and Results' G. Eglinton and M.J.J. Murphy ed. Springer-Verlag Belin, 1969. Marzec, Α., Juzwa, Μ., Betley, K. and Sobkowiak, M. Fuel Process. Technol. (1979), 2, 35. Marzec, Α., Juzwa, M. and Sobkowiak, M. in 'Gasification and liquefaction of coal'. Symposium on the gasification and liquefaction of coal, Katowice, Poland, April 1979. Coal/Sem. 6/R. 62 United Nations, Economic Commission for Europe, (1979). Ekstrom, A. and Randall, C.H. unpublished observation. Campbell, J . H . , Koskinas, G . J . , Stout, N.D. and Coburn, T.T. In-Situ (1978) 2, 1. Evans, R.A. and Campbell, J.H. In-Situ, (1979) 3, 33. Anthony, D.B. and Howard, J.B. AIChEJ. (1976) 22, 625. Ekstrom, A. and Fookes, C., unpublished observation. The authors thank Dr. J . Saxby for drawing their attention to this interpretation.
RECEIVED April 7, 1983
