- Email: [email protected]
Implications from several oil shale project studies
Implications studies Allan
J. Moore,
from
several
Bruce C. Wright,
oil shale project
Phil J. Redann”
and A. John Gannon”
Central Pacific Minerals NL, GPO Box 4024, Sydney 2001, Australia *Southern Pacific Petroleum NL, 143 Macquarie Street, Sydney 2000, Australia
Implications from recent project studies on the Duaringa, Nagoorin and Stuart oil shale deposits are discussed. A brief summary of status for the Condor project is also presented, along with implications from these studies for future research.
(Keywords: oil shale; geology; resources)
Despite the decrease in world enthusiasm for alternative fuel projects, Southern Pacific Petroleum N.L. and Central Pacific Minerals N.L. remain committed to the early development of Queensland oil shales, which they regard as Australia’s best prospect for oil self-sufficiency into the 1990s. Accordingly, these companies have maintained steady progress both on their own and in conjunction with others in addressing the technological and commercial aspects of shale oil development. This paper presents reserve estimates for the companies’ oil shale deposits and summarizes progress since last reported ‘3’ for the Duaringa, Nagoorin, Stuart and Condor deposits. The locations and in situ resources for seven oil shale deposits in which the companies have a substantial interest are presented in Figure 1. Current developments for the Rundle joint venture with Esso Exploration and Production Australia Limited are outlined elsewhere3.
DUARINGA The Duaringa Basin comprises an elongated trough extending NNW containing Tertiary rocks superimposed on the structurally deformed eastern margin of the Bowen Basin. The Duaringa oil shale resource is estimated to contain 3.72 x IO9 barrels of in-situ shale oil with an average grade of 82 1 tonne-’ at zero retort moisture (LTOM) based on a cut-off grade of 50 LTOM and a minimum mining thickness of 4m 4. The resource is contained in two parallel, extensive, thin seams of kerogenous shale overlain by up to 100m of barren sediments. The lower seam ranges in thickness from 10 to 15 m and in grade from 63 to 92 LTOM; it lies near the base of three mesas or plateaus which extend NNW over a distance of z 100 km and range up to ~20 km wide. The upper seam averages ~8 m thick and is separated from the lower seam by 20 to 25 m of barren mudstone; the oil shale ranges in grade from 46 to 66 LTOM. *This paper was presented at the ‘Third Australian Shale’, Lucas Heights, Australia, 15-16 May 1986 0016-2361/87,‘030298-03S3.00 ? 1987 Butterworth & Co. (Publishers)
298
Ltd
FUEL, 1987, Vol 66, March
Workshop
on Oil
During the first half of 1985 the companies conducted a pre-feasibility study to examine the technical and economic viability of the development of the deposit. The project concept was based on mining and retorting 66 000 tonnes per stream day of oil shale to produce 20650 barrels per day of synthetic crude oil. At this retort feed rate the total oil shale requirement for a 30-year project life is 544 million tonnes or 5 % of the known resource. Each of the three plateaus contains more than enough oil shale to satisfy the requirements of this project. Two mining factors, oil shale grade and strip ratio, were found to be important criteria. There are major cost benefits in maximizing oil shale grades for retorting and in minimizing the amount of overburden to be removed in mining. The Central and Northern plateaus contain oil shales with the highest grade; the Southern and Central plateaus have the lowest strip ratios. The Central plateau best meets both requirements and was therefore selected for study; it contains z 4200 x lo6 tonnes of oil shale with grades greater than 50 LTOM. The 30-year requirement is only 13 y0 of this tonnage, so an area was identified on the northern edge of the Central Plateau which contained the required project tonnage at a volumetric overburden ratio of 2.7:1 and a grade of 70 LTOM. In-situ moisture is z 30 mass % (wet basis). When compared with other deposits Duaringa has several disadvantages; the shale is of medium grade; the in-situ moisture is high, requiring substantial amounts of energy for thermal drying; and the deposit is remote from existing infrastructure. The impact of these factors on the on-site energy balance results in a requirement for supplemental fuel. In the study case, this fuel took the form of z 2000 tonnes per stream day of coal, and became a substantial cost penalty. For these reasons the pre-feasbility study concluded that development of the Duaringa deposit in the short term would not be commercially viable. However, on the basis that the real price of oil will return to 1985 levels by 1990 and then progressively increase through the end of the century, the project could show an adequate return on investment if constructed in the late 1990s.
Implications from oil shale studies: A. J. Moore et al.
rt/ tw nsville
QUEENSLAND
Deposit
I
Condor
In situ resources 9.65
Duaringa
3.72
Lowmead
0.738
Nagoorin
2.65
Nagoorin south
0.467
Rundle
2.65
Figure 1
Eastern Queensland
(log barrels) I
oil shale deposits
NAGQORIN The Nagoorin Technical Screening Study (NTSS) was initiated early in 1985 by the companies and their joint venture partners, Esperance Minerals N.L. and Greenvale Mining N.L.‘. The NTSS reviewed all information from previous Nagoorin investigations, including resource and research data. Attention was focussed on selection of process technology and on potential constraints on project development associated with process technology, mining, waste disposal, environmental and infrastructure factors. Pilot plant, demonstration plant and commercial development scenarios were included. Almost all process-related research on Nagoorin oil shales has concentrated on Unit Cc which dominantly comprises Type III kerogens’. These kerogens are highly aromatic with a high concentration of oxygenated carbon. Pyrolysis results in significant evolution of
carbon dioxide and higher gas production but lower overall carbon conversion than for the Type I kerogens, which are dominant in most other major Queensland oil shale deposits. For Unit Cc, pyrolytic gas and oil are evolved at temperatures above the normal retorting range, 50& 550”C8. This raises the possibility of retorting these oil shales in two or more temperature stages to maximize oil and gas yields and minimize oil coking losses. Partially combusted Unit Cc spent shale would be adequate as a heat carrier in a lines retort process with z 10 % of the residual carbon burnt to satisfy process heat requirements’. Lean phase fluid bed transport reactors may be preferred for primary combustion to avoid accumulations of secondary pyrolysis tar in the combustor. The large excess of reactive carbon residue could make an attractive fuel for power generation, steam raising or gasification. Raw shale oils produced by retorting Nagoorin carbonaceous oil shales have similar boiling ranges to those from other deposits. However, they are expected to be more aromatic and to have higher heteroatom contents than other shale oils5, but the presence of long straight-chain paraffins should offset any commercial disadvantage due to high aromaticity and permit production of an acceptable synthetic crude oil. Severe hydrotreatment of the raw shale oil would be required, consuming large quantities of hydrogen; however hydrocarbon gas streams from the retort and the upgrading plants should be sufficient to meet the needs for hydrogen plant feedstock and project fuel gas. The deposit is suitable for small- to large-scale open cut development using conventional mining and materials handling technology. A preliminary environmental review suggests that development could proceed in a safe and environmentally acceptable manner. The NTSS has laid the groundwork for development planning which will be essential before a comprehensive feasibility study can be conducted. The next stage of work will emphasize the promising potential for retorting the carbonaceous oil shales.
STUART The Stuart oil shale deposit lies within the southern half of the Narrows Graben which is about 30 km long, up to 6 km wide and comprises a thick sequence of Tertiary oil shale. The whole graben contains in excess of 5 x lo9 barrels of shale oil. The Rundle deposit lies within the northern part of the graben’. Stuart can be nominally divided into two portions, Stuart South and Stuart North. The Kerosene Creek Member is the uppermost seam in Stuart North and contains the highest grade oil shale within the deposit. Drilling of the Kerosene Creek Member in Stuart North has outlined an insitu shale oil resource of 111.7 million barrels with an average yield of 134 LTOM (using a cut-off grade of zero LTOM). Five sub-units can be distinguished in the member with a wide range of average grades (777179 LTOM). This presents an opportunity for selective mining and initial studies showed that mine grades varying from 140 to 200 LTOM can be achieved. Increased mine grades result in both increased strip ratios and reduced resource recovery, and economics will determine the eventual mining option adopted for
FUEL,
1987,
Vol 66, March
299
Implications
from oil shale studies: A. J. Moore et al.
development. The possibility of mining high grades and the proximity of the area to Gladstone, make the Stuart deposit an ideal choice for an initial commercial development. In early 1985, the companies commenced a study to examine the technical and economic feasibility of an initial commercial development. The study was based on a Lurgi LR retort processing 10000 tonnes/stream day of raw shale with a surface moisture content of 22.5 mass% and producing 8950 barrels per stream day of product oil, which included light oil, middle oil and naphtha, suitable for processing by conventional refineries. The mine grade selected for this pre-feasibility study was 185 LTOM and the resulting volumetric overburden ratio was 2.23: 1. The total cost including contingencies was estimated to be $A328 million (at 1st quarter 1985) and, at the then ruling price for marker crude of $US28 per barrel, showed a commercially acceptable rate of return on an unescalated, all equity basis. When debt was introduced into the financing plan and escalation taken into account, the rate of return on equity increased attractively. In the current oil pricing climate, however, $A328 million is seen as a large capital outlay for an initial development. potential to Recent analysis * indicates considerable optimize the retorting and combustion processes with high precision kinetic and scale-up data. The companies are continuing to explore ways to reduce further the entry cost on one of the most attractive shale properties in the world for an initial development. CONDOR Further reviews of the Condor Oil Shale Feasibility Study results’ were conducted by the companies’ engineers while negotiations with the Japan Australia Oil Shale Corporation (JAOSCO) were in progress. An extension to the original period of exclusive negotiation was granted to JAOSCO to permit further consideration of proposals from them for an agreement dealing with the next stage of the Condor Project. Following negotiations, this period expired and the companies are now free to commence discussion with other interested parties in addition to JAOSCO. On-site meteorological monitoring has been maintained with data being recorded for future analysis.
development of characterization techniques. This approach has been eminently logical and sensible but, if not adjusted in the future, will lead to the inertia which has characterized many synfuels programmes, in which more than 20 years have been spent developing techniques with little progress in later stage research. Excluding high risk innovation, the companies’ efforts are concentrated on basic process research with particular emphasis on retorting, combustion and drying in order of importance. An example of such a programme is the project ‘Comparative Processing Characteristics of Australian Oil Shales’, a collaborative research programme with the CSIRO Division of Energy Chemistry, and supported by the National Energy Research Development and Demonstration Program’. Research results from this programme have been reported” 16. It is believed that, for the companies’ future research programmes to make a worthwhile contribution to development of an oil shale industry, each programme, either by itself or in conjunction with other programmes, must provide a complete body of data. Pyrolysis results should be integrated with geology and organic micropetrography. Organic carbon conversion data also should be routinely developed. Retorting, combustion and kinetic data must be produced with closure of material and elemental balances, and hydrogen consumptions must be measured when hydrotreating crude shale oils. As the emphasis changes from technique development to process research, the production of precise, complete results which will not have to be replicated in the future commands a high priority. REFERENCES
6 I
RESEARCH
8
A significant expansion of Australian oil shale research occurred in the 1980s. Full reports of this effort have been published 9 - l1 . Much of the increased research effort has been focussed on the seven deposits in Figure 1. For convenience, logical stages of a research programme leading to a commercial development can be summarized as: 1. basic geology and interpretation; 2. oil shale characterization; 3. shale oil characterization; 4. basic process research on oil shale and shale oil; 5. reactor research; and 6. process engineering and flowsheet development. Most research programmes to date have been focussed on stages 1, 2 and 3, with emphasis on
300
FUEL,
1987,
Vol 66, March
9 10 11 12 13 14 15 16
Ivanac, J. F., ‘Proc. First Australian Workshop on Oil Shale’, Lucas Heights, 1983, p. 12 Redann. P. J. and Poole, D. R., ‘Proc. Second Australian Workshop on Oil Shale’, Brisbane, 1984, p. 15 Neale, R. C. and Thompson, B. J., ‘Proc. Third Australian Workshop on Oil Shale’, Lucas Heights. 1986, p. 21 Dixon, D. A. and Pope, G. J., ‘Proc. Third Australian Workshop on Oil Shale’, Lucas Heights. 1986, p.46 Southern Pacific Petroleum N.L., Central Pacific Minerals, N.L., Esperance Minerals, N.L., Greenvale Mining N.L., Nagoorin Technical Screening Study, January 1986, unpublished He&ridge, D. A. and Hutton, A. C., ‘Proc. Third Australian Workshop on OiI Shale’, Lucas Heights, 1986, p. 40 Henstridge, D. A. and Missen, D. D. Am. Assoc. Prt. GPO/. Bull. 1982.66, 719 Southern Pacific Petroleum N.L., Central Pacific Minerals N.L., CSIRO Division of Energy Chemistry, Comparative Processing Characteristics of Australian Oil Shales, National Energy Research and Development and Demonstration Program Project No. 702, March 1986 ‘Proc. First Australian Workshop on Oil Shale’, Lucas Heights, 1983 ‘Proc. Second Australian Workshop on Oil Shale’, Brisbane, 1984 Alfredson, P. G., ‘Proc. 18th Oil Shale Symposium’, Col. Sch. Mines 1985, p. 162 Wall, G. C. and Smith, S. J. C. Fuel 1987, 66, 345 Levy, J. H., Mallon, R. G. and Wall, G. C. Fuel 1987,66, 358 Dung, N. V., Wall, G. C. and Kastl, G. Furl 1987.66, 372 Charlton, B. G. File/ 1987, 66, 384 Charlton, B. G. Furl 1987,66, 388
J. Moore,
from
several
Bruce C. Wright,
oil shale project
Phil J. Redann”
and A. John Gannon”
Central Pacific Minerals NL, GPO Box 4024, Sydney 2001, Australia *Southern Pacific Petroleum NL, 143 Macquarie Street, Sydney 2000, Australia
Implications from recent project studies on the Duaringa, Nagoorin and Stuart oil shale deposits are discussed. A brief summary of status for the Condor project is also presented, along with implications from these studies for future research.
(Keywords: oil shale; geology; resources)
Despite the decrease in world enthusiasm for alternative fuel projects, Southern Pacific Petroleum N.L. and Central Pacific Minerals N.L. remain committed to the early development of Queensland oil shales, which they regard as Australia’s best prospect for oil self-sufficiency into the 1990s. Accordingly, these companies have maintained steady progress both on their own and in conjunction with others in addressing the technological and commercial aspects of shale oil development. This paper presents reserve estimates for the companies’ oil shale deposits and summarizes progress since last reported ‘3’ for the Duaringa, Nagoorin, Stuart and Condor deposits. The locations and in situ resources for seven oil shale deposits in which the companies have a substantial interest are presented in Figure 1. Current developments for the Rundle joint venture with Esso Exploration and Production Australia Limited are outlined elsewhere3.
DUARINGA The Duaringa Basin comprises an elongated trough extending NNW containing Tertiary rocks superimposed on the structurally deformed eastern margin of the Bowen Basin. The Duaringa oil shale resource is estimated to contain 3.72 x IO9 barrels of in-situ shale oil with an average grade of 82 1 tonne-’ at zero retort moisture (LTOM) based on a cut-off grade of 50 LTOM and a minimum mining thickness of 4m 4. The resource is contained in two parallel, extensive, thin seams of kerogenous shale overlain by up to 100m of barren sediments. The lower seam ranges in thickness from 10 to 15 m and in grade from 63 to 92 LTOM; it lies near the base of three mesas or plateaus which extend NNW over a distance of z 100 km and range up to ~20 km wide. The upper seam averages ~8 m thick and is separated from the lower seam by 20 to 25 m of barren mudstone; the oil shale ranges in grade from 46 to 66 LTOM. *This paper was presented at the ‘Third Australian Shale’, Lucas Heights, Australia, 15-16 May 1986 0016-2361/87,‘030298-03S3.00 ? 1987 Butterworth & Co. (Publishers)
298
Ltd
FUEL, 1987, Vol 66, March
Workshop
on Oil
During the first half of 1985 the companies conducted a pre-feasibility study to examine the technical and economic viability of the development of the deposit. The project concept was based on mining and retorting 66 000 tonnes per stream day of oil shale to produce 20650 barrels per day of synthetic crude oil. At this retort feed rate the total oil shale requirement for a 30-year project life is 544 million tonnes or 5 % of the known resource. Each of the three plateaus contains more than enough oil shale to satisfy the requirements of this project. Two mining factors, oil shale grade and strip ratio, were found to be important criteria. There are major cost benefits in maximizing oil shale grades for retorting and in minimizing the amount of overburden to be removed in mining. The Central and Northern plateaus contain oil shales with the highest grade; the Southern and Central plateaus have the lowest strip ratios. The Central plateau best meets both requirements and was therefore selected for study; it contains z 4200 x lo6 tonnes of oil shale with grades greater than 50 LTOM. The 30-year requirement is only 13 y0 of this tonnage, so an area was identified on the northern edge of the Central Plateau which contained the required project tonnage at a volumetric overburden ratio of 2.7:1 and a grade of 70 LTOM. In-situ moisture is z 30 mass % (wet basis). When compared with other deposits Duaringa has several disadvantages; the shale is of medium grade; the in-situ moisture is high, requiring substantial amounts of energy for thermal drying; and the deposit is remote from existing infrastructure. The impact of these factors on the on-site energy balance results in a requirement for supplemental fuel. In the study case, this fuel took the form of z 2000 tonnes per stream day of coal, and became a substantial cost penalty. For these reasons the pre-feasbility study concluded that development of the Duaringa deposit in the short term would not be commercially viable. However, on the basis that the real price of oil will return to 1985 levels by 1990 and then progressively increase through the end of the century, the project could show an adequate return on investment if constructed in the late 1990s.
Implications from oil shale studies: A. J. Moore et al.
rt/ tw nsville
QUEENSLAND
Deposit
I
Condor
In situ resources 9.65
Duaringa
3.72
Lowmead
0.738
Nagoorin
2.65
Nagoorin south
0.467
Rundle
2.65
Figure 1
Eastern Queensland
(log barrels) I
oil shale deposits
NAGQORIN The Nagoorin Technical Screening Study (NTSS) was initiated early in 1985 by the companies and their joint venture partners, Esperance Minerals N.L. and Greenvale Mining N.L.‘. The NTSS reviewed all information from previous Nagoorin investigations, including resource and research data. Attention was focussed on selection of process technology and on potential constraints on project development associated with process technology, mining, waste disposal, environmental and infrastructure factors. Pilot plant, demonstration plant and commercial development scenarios were included. Almost all process-related research on Nagoorin oil shales has concentrated on Unit Cc which dominantly comprises Type III kerogens’. These kerogens are highly aromatic with a high concentration of oxygenated carbon. Pyrolysis results in significant evolution of
carbon dioxide and higher gas production but lower overall carbon conversion than for the Type I kerogens, which are dominant in most other major Queensland oil shale deposits. For Unit Cc, pyrolytic gas and oil are evolved at temperatures above the normal retorting range, 50& 550”C8. This raises the possibility of retorting these oil shales in two or more temperature stages to maximize oil and gas yields and minimize oil coking losses. Partially combusted Unit Cc spent shale would be adequate as a heat carrier in a lines retort process with z 10 % of the residual carbon burnt to satisfy process heat requirements’. Lean phase fluid bed transport reactors may be preferred for primary combustion to avoid accumulations of secondary pyrolysis tar in the combustor. The large excess of reactive carbon residue could make an attractive fuel for power generation, steam raising or gasification. Raw shale oils produced by retorting Nagoorin carbonaceous oil shales have similar boiling ranges to those from other deposits. However, they are expected to be more aromatic and to have higher heteroatom contents than other shale oils5, but the presence of long straight-chain paraffins should offset any commercial disadvantage due to high aromaticity and permit production of an acceptable synthetic crude oil. Severe hydrotreatment of the raw shale oil would be required, consuming large quantities of hydrogen; however hydrocarbon gas streams from the retort and the upgrading plants should be sufficient to meet the needs for hydrogen plant feedstock and project fuel gas. The deposit is suitable for small- to large-scale open cut development using conventional mining and materials handling technology. A preliminary environmental review suggests that development could proceed in a safe and environmentally acceptable manner. The NTSS has laid the groundwork for development planning which will be essential before a comprehensive feasibility study can be conducted. The next stage of work will emphasize the promising potential for retorting the carbonaceous oil shales.
STUART The Stuart oil shale deposit lies within the southern half of the Narrows Graben which is about 30 km long, up to 6 km wide and comprises a thick sequence of Tertiary oil shale. The whole graben contains in excess of 5 x lo9 barrels of shale oil. The Rundle deposit lies within the northern part of the graben’. Stuart can be nominally divided into two portions, Stuart South and Stuart North. The Kerosene Creek Member is the uppermost seam in Stuart North and contains the highest grade oil shale within the deposit. Drilling of the Kerosene Creek Member in Stuart North has outlined an insitu shale oil resource of 111.7 million barrels with an average yield of 134 LTOM (using a cut-off grade of zero LTOM). Five sub-units can be distinguished in the member with a wide range of average grades (777179 LTOM). This presents an opportunity for selective mining and initial studies showed that mine grades varying from 140 to 200 LTOM can be achieved. Increased mine grades result in both increased strip ratios and reduced resource recovery, and economics will determine the eventual mining option adopted for
FUEL,
1987,
Vol 66, March
299
Implications
from oil shale studies: A. J. Moore et al.
development. The possibility of mining high grades and the proximity of the area to Gladstone, make the Stuart deposit an ideal choice for an initial commercial development. In early 1985, the companies commenced a study to examine the technical and economic feasibility of an initial commercial development. The study was based on a Lurgi LR retort processing 10000 tonnes/stream day of raw shale with a surface moisture content of 22.5 mass% and producing 8950 barrels per stream day of product oil, which included light oil, middle oil and naphtha, suitable for processing by conventional refineries. The mine grade selected for this pre-feasibility study was 185 LTOM and the resulting volumetric overburden ratio was 2.23: 1. The total cost including contingencies was estimated to be $A328 million (at 1st quarter 1985) and, at the then ruling price for marker crude of $US28 per barrel, showed a commercially acceptable rate of return on an unescalated, all equity basis. When debt was introduced into the financing plan and escalation taken into account, the rate of return on equity increased attractively. In the current oil pricing climate, however, $A328 million is seen as a large capital outlay for an initial development. potential to Recent analysis * indicates considerable optimize the retorting and combustion processes with high precision kinetic and scale-up data. The companies are continuing to explore ways to reduce further the entry cost on one of the most attractive shale properties in the world for an initial development. CONDOR Further reviews of the Condor Oil Shale Feasibility Study results’ were conducted by the companies’ engineers while negotiations with the Japan Australia Oil Shale Corporation (JAOSCO) were in progress. An extension to the original period of exclusive negotiation was granted to JAOSCO to permit further consideration of proposals from them for an agreement dealing with the next stage of the Condor Project. Following negotiations, this period expired and the companies are now free to commence discussion with other interested parties in addition to JAOSCO. On-site meteorological monitoring has been maintained with data being recorded for future analysis.
development of characterization techniques. This approach has been eminently logical and sensible but, if not adjusted in the future, will lead to the inertia which has characterized many synfuels programmes, in which more than 20 years have been spent developing techniques with little progress in later stage research. Excluding high risk innovation, the companies’ efforts are concentrated on basic process research with particular emphasis on retorting, combustion and drying in order of importance. An example of such a programme is the project ‘Comparative Processing Characteristics of Australian Oil Shales’, a collaborative research programme with the CSIRO Division of Energy Chemistry, and supported by the National Energy Research Development and Demonstration Program’. Research results from this programme have been reported” 16. It is believed that, for the companies’ future research programmes to make a worthwhile contribution to development of an oil shale industry, each programme, either by itself or in conjunction with other programmes, must provide a complete body of data. Pyrolysis results should be integrated with geology and organic micropetrography. Organic carbon conversion data also should be routinely developed. Retorting, combustion and kinetic data must be produced with closure of material and elemental balances, and hydrogen consumptions must be measured when hydrotreating crude shale oils. As the emphasis changes from technique development to process research, the production of precise, complete results which will not have to be replicated in the future commands a high priority. REFERENCES
6 I
RESEARCH
8
A significant expansion of Australian oil shale research occurred in the 1980s. Full reports of this effort have been published 9 - l1 . Much of the increased research effort has been focussed on the seven deposits in Figure 1. For convenience, logical stages of a research programme leading to a commercial development can be summarized as: 1. basic geology and interpretation; 2. oil shale characterization; 3. shale oil characterization; 4. basic process research on oil shale and shale oil; 5. reactor research; and 6. process engineering and flowsheet development. Most research programmes to date have been focussed on stages 1, 2 and 3, with emphasis on
300
FUEL,
1987,
Vol 66, March
9 10 11 12 13 14 15 16
Ivanac, J. F., ‘Proc. First Australian Workshop on Oil Shale’, Lucas Heights, 1983, p. 12 Redann. P. J. and Poole, D. R., ‘Proc. Second Australian Workshop on Oil Shale’, Brisbane, 1984, p. 15 Neale, R. C. and Thompson, B. J., ‘Proc. Third Australian Workshop on Oil Shale’, Lucas Heights. 1986, p. 21 Dixon, D. A. and Pope, G. J., ‘Proc. Third Australian Workshop on Oil Shale’, Lucas Heights. 1986, p.46 Southern Pacific Petroleum N.L., Central Pacific Minerals, N.L., Esperance Minerals, N.L., Greenvale Mining N.L., Nagoorin Technical Screening Study, January 1986, unpublished He&ridge, D. A. and Hutton, A. C., ‘Proc. Third Australian Workshop on OiI Shale’, Lucas Heights, 1986, p. 40 Henstridge, D. A. and Missen, D. D. Am. Assoc. Prt. GPO/. Bull. 1982.66, 719 Southern Pacific Petroleum N.L., Central Pacific Minerals N.L., CSIRO Division of Energy Chemistry, Comparative Processing Characteristics of Australian Oil Shales, National Energy Research and Development and Demonstration Program Project No. 702, March 1986 ‘Proc. First Australian Workshop on Oil Shale’, Lucas Heights, 1983 ‘Proc. Second Australian Workshop on Oil Shale’, Brisbane, 1984 Alfredson, P. G., ‘Proc. 18th Oil Shale Symposium’, Col. Sch. Mines 1985, p. 162 Wall, G. C. and Smith, S. J. C. Fuel 1987, 66, 345 Levy, J. H., Mallon, R. G. and Wall, G. C. Fuel 1987,66, 358 Dung, N. V., Wall, G. C. and Kastl, G. Furl 1987.66, 372 Charlton, B. G. File/ 1987, 66, 384 Charlton, B. G. Furl 1987,66, 388