Coal and coal-bearing strata as oil-prone source rocks?

Coal and Coal-bearing Strata as Oil-prone Source Rocks?

Geological Society Special Publications Series Editor A. J. FLEET

GEOLOGICAL SOCIETY SPECIAL PUBLICATION NO 77

Coal and Coal-bearing Strata as Oil-prone Source Rocks? EDITED BY

A N D R E W C. S C O T T Geology Department, Royal Holloway University of London AND

A N D R E W J. F L E E T BP Exploration, Sunbury-on-Thames

1994 Published by The Geological Society London

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Contents FLEET,A. J. & SCOTT, A. C. Coal and coal-bearing strata as oil-prone source rocks: an overview General studies

POWELL, T. G. & BOREHAM, C. J. Terrestrially sourced oils: where do they exist and what are our limits of knowledge? COLLINSON, M. E., VAN BERGEN, P. F., ScoTT, A. C. & DE LEEUW, J. W. The oilgenerating potential of plants from coal and coal-bearing strata through time: a review with new evidence from Carboniferous plants PHILP, P. R. Geochemical characteristics of oils derived predominantly from terrigenous source materials STOUT, S. A. Chemical heterogeneity among adjacent coal microlithotypes implications for oil generation and primary migration from humic coal MACGREGOR, D. S. Coal-bearing strata as source rocks - a global overview

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31 71 93 107

Case histories

THOMPSON, S., COOPER, B. S. & BARNARD,P. C. Some examples and possible explanations for oil generation from coals and coaly sequences MATCHETTE-DOWNES, C. J., FALLICK, A. E., KARMAJAYA, & ROWLAND, S. A maturity and palaeoenvironmental assessment of condensates and oils from the North Sumatra Basin, Indonesia CURRY, D. J., EMMET'r, J. K. & HUNT, J. W. Geochemistry of aliphatic-rich coals in the Cooper Basin, Australia, and Taranaki Basin, New Zealand: implications for the occurrence of potentially oil-generative coals BAGGE, M. A. & KEELY, M. L. The oil potential of Mid-Jurassic coals in northern Egypt ScoTT, A. C. & FLEET, A. J. Coal and coal-bearing strata as oil-prone source rocks: current problems and future directions

119

201

Index

207

139

149 183

Coal and coal-bearing strata as oil-prone source rocks: an overview ANDREW

J. F L E E T 1 & A N D R E W

C. S C O T T 2

1Bp Exploration, BP Research and Engineering Centre, Chertsey Road, Sunbury-on-Thames, Middlesex, TW16 7LN, UK 2Department of Geology, Royal Holloway University of London, Egham, Surrey TW20 OEX, UK Abstract: Despite many advances in our knowledge over the last decade, understanding of why some coals and coal-bearing strata are oil prone, and our ability to predict such sequences ahead of drilling in petroleum exploration, is relatively poor. Here we review the current status of the knowledge, highlighting contributions made in this volume. Oil-prone coals are hydrogen rich. Those which are generally acknowledged to have given rise to significant oil accumulations occur either as low latitude Tertiary deposits or within late Jurassic-Palaeogene sequences of the Australian region. Oils derived solely from coals and other terrigenous kerogens can be recognized using, geochemical criteria. Recognition of oil-prone coals and associated mudrocks visually or geochemically, however, is problematical. What controls the expulsion of petroleum in the liquid phase from coalbearing sequences is probably the critical factor. Our knowledge of the botanical, depositional and diagenetic controls which determine the formation of oil-prone coaly sequences, and hence our ability to predict their presence, is currently empirical and lacks understanding of the inputs and processes involved.

This book sets out to review the current status of our understanding of the formation of oil accumulations from coals. It is not concerned just with coals sensu stricto but also with the organic-rich mudrocks found in coal-bearing strata. Similarly although the focus is very much on kerogen derived from terrigenous material it is impossible to exclude some consideration of sequences of coals and mudrocks containing algal kerogen because coal accumulation and lacustrine sedimentation often sit at opposite ends of a depositional continuum in space and/or time (e.g. Powell & Boreham). Microbial biomass is a third, and very probably often significant, contributor to terrigenous kerogen (e.g. Curry e t M.). Non-marine source rocks can be estimated to account for less than 10% of world oil (Fleet & Brooks 1987) and much of this non-marine contribution is from lacustrine source rocks, accounting for 85-95% of the oil in areas such as Brazil, China and Indonesia (Katz et al. 1991). Despite being a poor relation as an oil source in global terms, oil-prone coal sequences are recognized as key oil source rocks in at least Southeast Asia, Australia and New Zealand. Even in these regions the critical factors which make coals and their associated mudrocks oil prone is debated. Elsewhere, for instance in Arctic North America and the North Sea, the

ability of coal sequences to source oil is contenious. Stratigraphically oil-prone coals are mainly limited to late Jurassic and younger sequences (e.g. Macgregor) but some workers question any implied causal link (e.g. D u r a n d & Paratte 1983). Understanding why coal-beating sequences are oil prone can unlock a predictive capability for petroleum exploration and so help to reduce exploration risk.

Background The link between oils and terrigenous organic matter was first made by Hedberg (1968). He recognized that high-wax, low sulphur oils were commonly associated with non-marine, often coal-bearing, strata, though he correctly suggested that both terrigenous organic matter and non-marine aquatic matter could be the source materials of these oils. Since then, various workers have reviewed the question of which factors make coal-bearing strata oil prone or, at least, which control the expulsion of liquid-phase petroleum from these strata (e.g. D u r a n d & Parratte 1983; Murchison 1987). Most recently a symposium of the American Chemical Society reviewed the topic (Hunt 1991 et seq.) through a number of case studies and laboratory approaches. As geochemical and related thinking on oil-prone coals has edged

From Scott, A. C. & Fleet, A. J. (eds), 1994, Coaland Coal-bearingStrata as Oil-prone Source Rocks? Geological Society Special Publication No. 77, pp. 1-8.

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A. J. FLEET & A. C. SCOq~F

forward since Hedberg's (1968) observations, thinking on coal formation and palaeobotany have evolved rapidly (e.g. Scott 1987; Bertrand 1991). There is now a need to try and fully integrate the contributions which different disciplines can make to understanding oil-prone coals. This book represents an attempt to begin to draw these disciplines together. T h e issues

The underlying question behind this book is what factor(s) make(s) coals or coal-bearing strata capable of expelling petroleum in the liquid phase? Implicit in this question is understanding the relative contributions of liquids and gases which any coal-bearing sequence can expel in response to a particular thermal history. The reason for the question is that petroleum explorers need to be able to predict ahead of drilling both sourcing systems and the phases and composition of petroleum in prospects. In this book we attempt to review our current understanding of at least the major issues which need to be resolved if we are to approach answering this underlying question. • How do we recognize oil-prone coals and associated mudrocks if we have samples for analysis and how do we characterize oils derived from coal-bearing sequences? Which parameters, or combination of parameters, do we use for these tasks (e.g. visual, geochemical, palaeobotanical)? • What botanical input or depositional environment or early diagenetic conditions, or combination of these, governs the formation of oil-prone coal-bearing sequences? Can a predictive model, which can be used prior to drilling, be derived from understanding these factors? • How do variations in generation, expulsion behaviour and secondary migration determine whether or not coal-bearing sequences give rise to oil? Characterization Microscopy and geochemistry have been used alone and in combination in attempts to try and distinguish oil-prone coals from other coals (e.g. Murchison 1987). The key overriding factor is that the coals are rich in hydrogen relative to carbon. Hunt (1991) has suggested that this translates into approximate thresholds for the following parameters of: • H/C ratios > 0.9

• Hydrogen Indices > 200 • liptinite contents > 15% Powell & Boreham argue that none of these can be used in isolation: 'the overall petrographic composition of coal is a poor guide to its petroleum potential' and 'there is not a simple relationship between the elemental composition of terrigenous kerogen, the gross pyrolysis yield by Rock-Eval and the yield of normal hydrocarbons in pyrolysis gas chromatography'. They suggest that a combination of a mass balance approach and pyrolysis is the best indicator of expelled liquid and gaseous petroleum from coals. The problems with using microscopy are partly those of the mismatches between the terminologies of coal petrology and kerogen typing and the actual biological components from which individual macerals or kerogen constituents come (Collinson et al.), but they also relate to the often imperfect characterization of organic matter which can be made microscopically. For instance, Curry et M. suggest that microbial biomass is a significant contributor to the Permian coals of the Cooper Basin, Australia, which are the source of oils found in Jurassic and older reservoirs of the basin (Powell & Boreham). Under the microscope these coals are inertinite rich and very low in liptinites. Another factor which may be significant in militating against using coal macerals for recognizing oil proneness is that it is possibly the association of macerals, the microlithotype, rather than the macerals themselves, which controls the expulsion of generated liquid petroleum from coals (Stout). The recognition of oils derived from coals can be as important as characterizing coals themselves. Recognition that produced or seeped oil in a basin is from coals will either open up new plays if a coal source has not previously been identified in the basin or allow typing of the sourcing system operating in the basin (e.g. Matchette-Downes e t al.). The 'correlation' will not, of course be to coals sensu stricto but to sequences containing terrigenous organic matter. As Hedberg (1968) pointed out, the clues to this type of source will be high wax and low sulphur; what will confirm the diagnosis will be high pristane/phytane ratios (e.g. > 3 - 4 Powell & Boreham). Biomarker molecules in the oils, the origins of which can be linked back to land plant communities, can add further evidence to the 'correlation' (e.g. Philp). Biomarker evidence alone may, however, be equivocal since biomarkers may be derived from terrigenous organic matter deposited in a marine or lacustrine environment. The Niger Delta

AN OVERVIEW offers a good example of this dilemma. The oils of the delta are cited as classic examples of oils derived from terrigenous kerogen as they contain the biomarker oleanane which is believed to be derived from flowering plants (Hills & Whitehead 1966; Peters & Moldowan 1993). No source rock, though, has been unequivocally identified in the literature. The delta top sequences which have been sampled through drilling seem to contain no rich source rock but may make up in thickness what they lack in quality and richness (Bustin 1988). Alternatively, or in addition, the pro- and (?)pre-delta Akata shales, which are unsampled in potential source kitchens, may be the source (Weber & Daukoru 1975): these mudrocks could contain abundant terrigenous organic matter which was • deposited beyond the delta front. Isotopes provide another way of characterizing coals and their petroleum products. To date they have generally been used for characterizing the total carbon or bulk fraction of a kerogen, oil or gas. Isotope analysis of individual molecules has largely been restricted to simple C1-Cs hydrocarbon constituents of gases but over recent years gas chromatograph-mass spectrometers capable of compound-specific isotope analysis have come into use. Nevertheless isotope analysis is currently probably at its most useful for characterizing gases and for oiloil and oil-source correlations. Isotopes offer a principal line of evidence for the origin of gases, potentially distinguishing biogenic gas, oilassociated gas and thermogenic gas which is not associated with oil (e.g. Schoell 1983; Clayton 1991). They are, therefore, important in studying the petroleum generated from coal-bearing strata which, even when containing liquid products, also contain high proportions of gas (see below). In contrast, the use of carbon isotopes to characterize kerogen as non-marine or marine is not as straightforward as it was once considered. Based on recent organic matter, non-marine kerogens have been characterized as having lighter carbon isotope compositions (81aC of about - 27%o) relative to marine kerogens (d13C of about - 20%0) (e.g. Tissot & Welte 1984). However, recent studies (e.g. Clayton in press) suggest that this has only been the situation since Miocene times; previously the relationship was reversed, the relative difference varying through the Phanerozoic.

Prediction: input, depositional environment, diagenesis In potentially coal-bearing basins there is a need in petroleum exploration to predict ahead of

3

drilling whether any coal-bearing strata present are oil prone. Similarly, if the presence of oil-prone coal-bearing sequences has been identified from sediment samples or deduced from oil samples there is a need to predict the distribution of the oil-prone coaly facies. This need then becomes one of assessing the probable gas : oil ratios (GOR) of the petroleum expelled from these facies so as to predict GORs of individual prospects. Any of these predictions requires an ability to identify or understand the factors which determine whether a coal is oil prone. In terms of facies distribution the botanical origin of the organic input to the sediments, the depositional environment and early diagenesis may all play a part, very possibly in a close interrelationship. (They may also ultimately determine expulsion behaviour from the coals and, therefore, oil proneness: see next section.) The botanical input to coal depositional environments will have varied through geological time as plant communities have evolved and will have also been governed by climate and other environmental factors (Collinson & Scott 1987). Thomas (1982) drew attention to these likely controls and argued that, at least in Australian basins, the dominance of conifers in swamp floras since the Jurassic, and the evolution of the angiosperms from Late Cretaceous times, meant that there was a relatively abundant input of potentially oil-prone detritus which became preserved as exinite. Thompson et al. (1985 and this volume) added another dimension to this kind of reasoning when considering the Tertiary oil-prone coal sequences of Southeast Asia. They suggested that the oil-prone coals in these basins resulted from preferential preservation of potentially oilprone detritus in coastal plain environments under everwet, tropical conditions. Cawley & Fleet (1987) suggested these strands of reasoning might be knitted together and point to Cretaceous and younger tropical and subtropical lower delta-plain deposits as being the prime sites of oil-prone coal development. The papers in this volume suggest that at least two other types of organic input need to be taken into account when considering the prediction of oil-prone coals. They are microbial biomass added during diagenesis and resinite. As discussed above, microbial biomass probably accounts for the oil-prone nature of the Permian coals from the Cooper Basin, Australia. What might control the development of microbial biomass in abundance and whether such biomass is a significant contributor to all oil-prone coals is currently an open question. The contribution

4

A. J. FLEET & A. C. SCOTT

of resinite to the oil potential of coals has been much debated (see discussion in Powell & Boreham). In general its presence does not seem critical to the potential but in one area, the Beaufort-Mackenzie Delta region of northern Canada, resinite has been argued to be the key terrigenous kerogen component present (Snowden 1991). Macgregor's statistical analysis of the distribution of oil-prone coals bears out the hypothesis that oil-prone coals are Jurassic and younger phenomena at least as far as significant accumulations ( > 50 million barrels of recoverable oil) of coal-sourced oil are concerned. He find~ that significant oil-prone coal-bearing sequences are restricted to two 'fairways': • Tertiary basins within 20 ° of the palaeoequator; • Late Jurassic-Eocene basins formed on the Australian and associated plates. Macgregor's analysis only relates to extant oil accumulations and is subject to the observation that coals may have given rise to significant oil accumulations in early times which have subsequently been destroyed by tectonic disruption, oil to gas cracking etc. Certainly this is one view Durand & Paratte (1983) took of previous observations of the stratigraphic distribution of coalsourced oils. Their alternative view was that all coals are capable of generating oil so expulsion must be the critical factor for the petroleum potential of coals. The innovative studies of Collinson e t al. support the latter view. Their studies of the components of Carboniferous coals suggest that such materials would have been sources of the constituent compounds of oil. Whether they gave rise to expelled liquids, though, is an open question. Overall our ability to predict oil-prone coal-bearing sequences remains a matter of debate. Such strata may either generally be restricted to Cretaceous and younger sequences, because of botanical input or some as yet unrecognized control on oil expulsion, or they may be expected throughout post-Devonian sequences but in association with fewer oil accumulations the older they are.

Generation, expulsion and migration For any given thermal history oil-prone coal and other terrigenous kerogens generally generate oil (Cs+) at higher temperatures than the aquatic kerogens of marine and lacustrine source rocks (e.g. Tissot et al. 1987; Horsfield et al. 1988; Noble et al. 1991). An exception is probably resinite, or at least diterpenoid resinite which, because of its labile nature, may be responsible

for causing earlier significant generation in some sequences (see discussion by Snowden 1991 and Powell & Boreham). As discussed above, the critical factor which determines whether or not coals and associated sediments give rise to oil may be expulsion. Controls on expulsion are debated. Broadly they range from generated oil having to exceed some threshold value to fracturing (e.g. Duppenbecker et al. 1991 and Pepper 1991 and references therein). The threshold which must be exceeded is either some percentage of the source-rock pore network, above which it is assumed interconnected pores form pathways out of the source rock, or some value above which adsorption by the source rock, on, say, the kerogen matrix, is exceeded. The dominance of a particular control on oil expulsion may depend on the source rock: for instance adsorption onto kerogen may only become critical in source rocks with relatively moderate or low hydrogen indices (e.g. of 200-300); • oil-prone coals which are generally acknowledged to have given rise to significant oil accumulations occur either as low latitutde Tertiary deposits or within late JurassicPalaeogene sequences of the Australian region; • oils derived solely from coals and other terrigenous kerogen have pristane/phytane ratios > 3-4. The key areas which we need to address in order to advance our understanding further, and how we might progress, are summarized at the end of this volume by Scott & Fleet. This volume arises from a joint meeting of the Coal and Petroleum Groups of the Geological Society held in London in June 1992. We thank all the contributors and participants at the meeting for the lively discussion which, although not providing sudden revelations, did clarify current wisdom and outstanding issues. We would like to thank the staff of the Geological Society, particularly Heide Gould and Helen Softley, without whom the meeting would not have taken place. Finally we thank the contributors to this volume, the reviewers and Angharad Hills and Joanna Cooke of the Geological Society Publishing House for ensuring this volume appeared in a reasonable time frame.

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HUNT, J. 1991. Generation of gas and oil from coal and other terrestrial organic matter. Organic Geochemistry, 17,673-680. KATZ, B. J., KELLEY, P. A., ROYLE, R. A. & JORJORIAN, T. 1991. Hydrocarbon products of coals as revealed by pyrolysis-gas chromatography. Organic Geochemistry, 17,711-722. LEYTHAEUSER,D. & POELCHAU,H. S. 1991. Expulsion of petroleum from type III kerogen source rocks in gaseous solution: modelling of solubility fractionation. In: ENGLAND, W. A. • FLEET, A. J. (eds) Petroleum Migration. Geological Society, London, Special Publication, 59, 33-46. MURCHISON, D. G. 1987. Recent advances in organic petrology and organic geochemistry: an overview with some reference to 'oil from coal'. In: SCOTT, A. C. (ed.) Coal and Coal-bearing Strata: Recent Advances. Geological Society, London, Special Publication, 32,257-302. NOBLE, R. A., Wu, C. H. & ATKINSON,C. D. 1991. Petroleum generation and migration from Talang Akar coals and shales offshore N.W. Java, Indonesia. Organic Geochemistry, 17, 363-374. PARNELL, J. 1988. Lacustrine petroleum source rocks in the Dinantian Oil Shale Group, Scotland: a review. In: FLEET, A. J., KELTS, K. & TALBOT, M. R. (eds) Lacustrine Petroleum Source Rocks. Geological Society, London, Special Publication, 40,205-217. PEPPER, A. S. 1991. Estimating the petroleum expulsion behaviour of source rocks: a novel quantiative approach. In: ENGLAND, W. A. 8Z FLEET, A. J. (eds) Petroleum Migration. Geological Society, London, Special Publication, 59, 9-32. PETERS, K. E. & MOLDOWAN, J. M. 1993. The biomarker guide: interpreting molecular fossils in petroleum and ancient sediments. Prentice Hall, New Jersey. PITTION, J. L. & GOUADIAN,J. 1985. Maturity studies of the Jurassic 'coal unit' in the three wells from the Haltenbanken area. In: THOMAS,B. M. et al. (eds) Petroleum Geochemistry in Exploration of the Norwegian Shelf. Graham & Trotman, London, 205-212. SCHOELL,M. 1983. Genetic characterization of natural gases. American Association of Petroleum Geologists Bulletin, 67, 2225-2238. ScoTT, A. C. (ed.) 1987. Coaland Coal-bearing Strata: Recent Advances. Geological Society, London, Special Publication, 32. 1989. Observations on the nature and origin of fusain. International Journal of Coal Geology, 12,443-475. SNOWDEN, L. R. 1991. Oil from type III organic matter; resinite revisited. Organic Geochemistry, 17,743-747. THOMAS, B. M. 1982. Land-plant source rocks for oil and their significance in Australian basins. Australian Petroleum Exploration Association Journal, 22, 164-178. , MOLLER-PEDERSEN, P., WHITAKER, M. F. & SHAW, N. D. 1985. Organic facies and hydro-

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Terrestrially sourced oils: where do they exist and what are our limits of knowledge? - a geochemical perspective T. G. POWELL

& C. J. B O R E H A M

Australian Geological Survey Organization, GPO Box 378, Canberra, A. C. T., Australia 2601 Abstract: There are relatively few well-documented cases where significant amounts of oil

(> 500 million barrels) have their origin from coals or their associated carbonaceous shales. The best-documented cases are from Australia and Indonesia and possibly the North Sea. The extensive debate as to whether coals as such or their associated carbonaceous shales are the source for oil has been essentially sterile: it has failed to take into account the heterogeneous nature of coals, the variety of their floral origins and the continuity of mineral dilution from pure coal to carbonaceous shale. Each case must be considered on its merits. The overall petrographic composition of coal is a poor guide to its petroleum potential. Sub-microscopic lipids of bacterial and also plant origin occur in vitrinite and inertinite and contribute significantly to petroleum potential. Suberinite and cutinite are the maj or source of waxy hydrocarbons. Hydrogen Indices measured on the immature versions of documented terrigenous source rocks are surprisingly low falling in the range 200-350 and occasionally lower. There is not a simple relationship between the elemental composition of terrigenous kerogen, the gross pyrolysis yield by Rock-Eval and the yield of normal hydrocarbons in pyrolysis gaschromatography. Our assessment of liquid potential in marginal source rocks, wherein most terrigenous sediments lie, is far from perfect. A combination of the mass balance approach in conjunction with pyrolysis studies has been shown to be the most effective way of demonstrating source potential and hydrocarbon products (gas vs. oil) expected from these marginal source rocks. There is clear evidence that significant amounts of gas are generated in the conventional oil window, and that high gas to oil ratios facilitate migration from the leaner source rocks. Comparative maturation studies on oils and gas-condensates show that they can be generated at similar maturation levels. The majority of terrigenous oils and condensates are paraffinic and the oils may have a high wax content. Exceptions occur when resin is a significant source in which case there is an increased proportion of naphthenic and aromatic hydrocarbons. Oils derived from coalbearing sequences have high pristane to phytane ratios (> 4.0); they have a high proportion of iso- and anteiso-alkanes derived from bacterial sources; hopanes predominate over steranes which are dominated by the Cz9 member. A variety of diterpenoid hydrocarbons may be found which relate to the nature of the parent flora and increasingly can be used for oil-source correlation in non-marine sequences.

H e d b e r g (1968) was the first to recognize that a significant n u m b e r of oils on a w o r l d w i d e basis had a terrestrial origin. His criteria w e r e b a s e d on the wax c o n t e n t and the paraffinic n a t u r e of the oils implying an origin f r o m the cuticular waxes of land plants. As an a p p r e c i a t i o n of the i m p o r t a n c e of lacustrine source rocks grew, it also b e c a m e a p p a r e n t that f r e s h w a t e r algae and possibly b a c t e r i a (Powell 1986 and r e f e r e n c e s t h e r e i n ) could also be a source for waxes and paraffinic h y d r o c a r b o n s . This, in effect, r e d u c e d the n u m b e r of examples w h e r e i n oils of waxy origin could be a t t r i b u t e d to a land plant source. Thus the n u m b e r of d o c u m e n t e d cases w h e r e significant v o l u m e s of oil can u n e q u i v o c a l l y be

d e m o n s t r a t e d to have an origin in coals or their associated c a r b o n a c e o u s shales r e m a i n s relatively few (Table 1). R e c e n t reviews ( M u r c h i s o n 1987; Powell & B o r e h a m 1991; B o r e h a m & Powell, in press) have discussed in detail the g e o c h e m i c a l and organic petrological issues r e l a t e d to the n a t u r e of, and recognition of, oil-prone source rocks in terrestrial s e q u e n c e s , the m o l e c u l a r c o m p o sition of n o n - m a r i n e oils and their precursors and the issue of migration. This p a p e r concentrates on a general o v e r v i e w of terrestrially d e r i v e d oils in the context of the e v a l u a t i o n of terrestrial s e q u e n c e s for p e t r o l e u m , concentrating on the e v i d e n c e available f r o m the case

From Scott, A. C. & Fleet, A. J. (eds), 1994, Coal and Coal-bearing Strata as Oil-prone Source Rocks? Geological Society Special Publication No. 77, pp. 11-29.

11

12

T . G . POWELL & C. J. BOREHAM

Table 1. Terrigenous oil provinces - documented case studies Source rock

Country Basin/Province

Age

Hydrogen Indices

Reference

Late CretaceousTertiary Permian Jurassic Permian

200-350

Moore etal. 1992

150-300 200-400 150-250

Vincent etal. 1985

Eocene-Palaeocene

130-250

Issler & Snowdon 1990

Jurassic

?

Huang etal. 1991

Late Oligocene Middle Miocene

250-400 200-350

Noble etal. 1991 Durand & Oudin 1979

Late Cretaceous Tertiary

?

Czochanska etal. 1988

Late CretaceousTertiary

< 200

Bustin 1988

Jurassic

275

Forbes et al. 1991

Australia Gippsland Basin Cooper/Eromanga Basin Bowen/Surat Basin

Boreham (unpublished)

Canada Beaufort-Mackenzie Basin

China Turpan Basin

Indonesia Ardjuna Sub-basin, Java Mahakam DeltaKutei Basin, Kalimantan

New Zealand Taranaki Basin

Nigeria Niger Delta

Norway Haltenbanken area, N. Sea

Note: Hydrogen Indices are measured on immature samples.

histories and the uncertainties remaining in our understanding of generation of petroleum in land plant-dominated terrestrial sequences.

Examples of documented terrigenous petroleum systems Table 1 lists the best-documented cases of terrigenous petroleum systems in which coal or terrestrial organic matter in associated carbonaceous shales is deemed to be the source for oils and associated gas condensates. Examples where there is deemed to be a significant algal component to the source, such as occurs in many lacustrine sequences, are specifically excluded. The decision is an arbitrary one since there is a continuum between deposition of terrestrial organic matter in swamps through flood plain lakes to large lake systems developed in tectonic depressions (Powell 1986). At any point in this continuum algae may become a contributing source and, of course, in large lake systems may become the dominant source material (Powell 1986). This largely excludes the Chinese non-marine basins

where the preponderance of high-wax oil appears to originate from algal-dominated lacustrine source rocks, although there are references in the literature to coals being the source for some oils (e.g. Huang et al. 1988). The Turpan Basin may be a case in point (Huang et al. 1991). It was suggested early in the development of modern petroleum geochemistry in Australia that a significant proportion of Australian oil and gas reserves in the Gippsland, C o o p e r Eromanga and Bowen-Surat basins were derived from terrigenous source rocks in which coal was a significant if not the dominant component (Brooks & Smith 1967, 1969; Brooks et al. 1971; Powell & McKirdy 1972). The Gippsland Basin in Australia is by any standards a major hydrocarbon province with initial reserves estimated at 4.2 billion barrels of oil and condensate and 9.1 trillion cubic feet (TCF) of gas (Moore et al. 1992). Early in its exploration history it was recognized that the hydrocarbons were probably of terrigenous origin, but it is only more recently that there has been widespread acceptance of the terrigenous nature of the Gippsland Basin source rocks. They consist of a mixture of coals

TERRESTRIALLY SOURCED OILS and carbonaceous shales of late Cretaceous age deposited in a lower delta plain setting (Moore et al. 1992) (Table 1). The organic matter was derived from cool temperate coniferous forest (Shanmugan 1985). The Taranaki Basin in New Zealand is also oil and gas bearing with many characteristics similar to the Gippsland Basin. Again coals and associated shales of late Cretaceous to early Tertiary age are the identified source rocks (Czochanska et al. 1988; Weston et al. 1989). The Cooper-Eromanga Basin sequence in central Australia is another classic sequence in which the terrigenous nature of the source was suggested early in its exploration (Brooks et al. 1971; Powell & McKirdy 1972). The Permian fluviatile source sequence is dominated by coals and is the predominant source for the oil and gas-condensate in Permian and Triassic reservoirs (Vincent et al. 1985). The source rocks were deposited in a cold temperate climate in an inter-montane setting (Hobday 1987). The overlying Eromanga Basin is oil prone and contains the majority of the recoverable oil reserves in the basin complex. Perhydrous Jurassic coals were deposited in a fluviatile-lacustrine environment under warm humid conditions and have the potential to generate oil. However, they are thin and lack lateral continuity. Oil source rock correlations based on plant biomarkers (Alexander et al. 1988) and volumetric and migration considerations (Vincent et al. 1985) demonstrate that most oils reservoired in Jurassic and older rocks originate from the Permian coal sequences. Some contribution from Jurassic sources has been recognized in a few instances (Alexander et al. 1988). Small oil pools occur in Cretaceous lacustrine sands and have been demonstrated to originate in adjacent lacustrine carbonaceous shales containing terrestrial organic matter (Powell et al. 1989). The Bowen-Surat basins in southern Queensland have only minor reserves, but again the oils originate from Permian terrigenous source rocks showing some degree of marine influence (Philp & Gilbert 1986). A very large proportion of oil in Indonesia either has a lacustrine (algal) or terrigenous source (Robinson 1987). In the case of Sumatran fields it is often difficult to determine the relative importance of a purely terrigenous source (Katz & Mertani 1989). However, there are two published cases of major reserves associated with terrigenous sources in Indonesia. In the Mahakam Delta (Kutei Basin) Kalimantan, terrigenous source rocks of Miocene Age are located in the delta plain facies and consist of interbedded coals and shales and give rise to

13

major oil and gas reserves (Durand & Oudin 1979). Similarly in the Ardjuna Sub-basin of NW Java, coals and associated carbonaceous shales in the Talang Akar Formation of late Oligocene age have been documented as the source for the very significant reserves in that basin (Gordon 1985; Horsefield et al. 1988; Pramono et al. 1990; Noble et al. 1991). In both cases the organic matter is derived from deltaic facies in a tropical setting. The Tertiary section of the Niger Delta has long been considered to be an example of a terrigenous oil province (Hedberg 1968; Reed 1969). No identified rich source rocks have been identified - aUochthonous terrigenous organic matter is widely dispersed in the finer-grained facies. The highest concentration of organic matter and the most oil-prone organic matter occurs in the floodplain deposits. The poor quality of the source rocks has been compensated by their great volume (Bustin 1988). The Beaufort-Mackenzie Basin, Canada is a significant hydrocarbon province and, like the Niger Delta, consists largely of a Tertiary Delta in which allochthonous terrigenous organic matter appears to be the source (Snowdon 1978). Unlike the other examples, resin compounds appear to be a major component of the source material and the oils are naphthenicaromatic rather than paraffinic. Oil-source correlations have shown that the EocenePalaeocene Richards Formation is the source (Brooks 1986a, b). Once again the source organic matter is derived from coniferous species growing at high latitudes. This particular example is discussed in more detail below. It has been proposed that Jurassic coals are a major source for liquid hydrocarbons in the Haltenbanken region in the Norwegian Sector of the North Sea and recent volumetric studies have suggested that that source is adequate to account for the known reserves (Forbes et al. 1991). Other examples are emerging of significant oil resources being derived from autochthonous and/or allochthonous terrestrial organic matter, e.g. Brunei (Scherer & Hitam 1992) and Sarawak (Woodroof & Carr 1992), but neither have been extensively documented in the literature.

Implications of depositionai environment and flora for characteristics of source rocks in terrigenous sequences Over the last 10 years there has been considerable debate as to whether coals as such can be a source for oil or whether it is the dispersed

14

T. G. POWELL & C. J. BOREHAM

organic matter in associated shales which is the primary source for petroleum in coal-bearing sequences. The authors' view is that this debate has been essentially sterile, because it has failed to take into account the heterogeneous nature of coals and the variety of depositional conditions under which they are formed and the continuum in mineral dilution from pure coal to carbonaceous shale. Much of our knowledge of the physicochemical structure of coals is essentially confined to Euramerican Carboniferous coals which are economically important as thermal coals or for coke manufacture. By definition these coals are of low ash - otherwise they would not be economic - and they are derived from a particular flora (lycopsids) that dominated in the Carboniferous (Collinson & Scott 1987). They were probably deposited in a particular depositional environment to account for their low ash content (McCabe 1984). It is noteworthy that none of our case histories (Table 1) relate to Carboniferous coals. Indeed, with the notable exception of the Permian coals of the Cooper Basin, all examples of non-marine oils are derived from coal-bearing sequences which are much younger and from source materials derived from more advanced plants than those represented in the Carboniferous. In addition, the range of coal depositional environments represented by the case histories, both in terms of climate and depositional setting, is far broader than is represented by the Carboniferous coals. A particular case is the Permian coals of the Cooper Basin, Australia which were deposited in a cool temperate setting far removed from marine influence (Hobday 1987). Differing flora and depositional settings impose their own structure on coals seams. Ash contents are continuously variable from carbonaceous shale through to pure coals which may be allochthonous or autochthonous in origin. From these observations it is clear that the particular model of coal structure and physico-chemical properties represented by Euramerican Carboniferous coals is an inappropriate basis to argue the general merits of in situ generation and migration of oil from coal. Indeed many nonmarine source rocks identified as 'coals' would not be economically exploitable coals from the standpoint of their ash content. Reiteration of some key quotes and conclusions from a paper by McCabe (1984) on the depositional environments of coal illustrate the points made above: 'Care should be exercised in using coal as a paleoclimatic indicator. It is certainly not an indicator of warm temperatures or a high rainfall.'

'Swamps vary in their morphology, vegetation type, degree and type of degradation of organic matter and the input of clastic sediment. All these factors are important in determining coal's quality. Raised swamps and floating peats, may be important in the formation of low ash coals.' 'The composition of peat/coal is as variable as any other sedimentary rock. Facies analysis of coal seams can provide important indications relative to the nature of the depositional environment. The composition of a coal is also important in determining its utilisation.' 'Peat can accumulate in any depositional setting. The importance of deltas as sites for peat accumulation has probably been greatly over-emphasized in the literature.' Quite apart from the wide variety of depositional environments in which coal or carbonaceous sediments can accumulate, the original peat-forming vegetation has undergone major changes through the geological record (Collinson & Scott 1987). Particular features which affect peat formation and composition include (Collinson & Scott 1987): • nature and timing of leaf fall; • proportions of lignin and cellulose; • presence/absence of open water and marginal aquatic plants; • overall community diversity and the interactions between members of the community. These factors have clearly changed in response to plant evolution. Indeed the evolution of the depositional conditions within the coal-forming environment will in itself inevitably lead to changes in the plant community and affect the composition of peats that are formed. A very significant factor that must be taken into account in considering the variability in composition of potential coal source rocks is the dramatic degradation and reduction in plant biomass that accompanies peat accumulation (Clymo 1987). The mass of peat ultimately preserved represents only a very small fraction (a few percent) of the plant mass originally deposited. This volume reduction occurs as a result of dehydration, extensive microbiological activity and ongoing chemical reactions not mediated by biological activity. The resulting organic accumulation consists of the remnant plant tissues impregnated with, and set in, a matrix of homogenized decay products. Given the variation in depositional conditions of peat preservation this process is a source of very significant heterogeneity in the preserved coals and carbonaceous shales. A direct implication of

TERRESTRIALLY SOURCED OILS this process is that bacterial organic matter would be expected to be a very significant component of the preserved organic material. Estimates of bacterial biomass in peats are of the order of 15% (Stach et al. 1982). It is clear from this discussion that the physicochemical properties of organic-rich shales, high ash coals and pure coals will be extremely variable and that in turn their ability to generate hydrocarbons and yield them for migration will be extremely variable and each case must be considered on its merits. Furthermore it has been demonstrated in several of the case examples cited in Table 1 that the overall geochemical composition of coals is identical with that of the organic matter in the associated shales (Durand & Oudin 1979; Vincent et al. 1985). The question of the ultimate source depends on arguments related to the efficiency of migration out of shales compared with coals. The relative masses of organic matter in coal compared with shale is also a factor in attributing source (Moore et al. 1992). Terrigenous organic matter as a source for hydrocarbons

Coal consists of a complex mixture of microscopic components, termed macerals, which are distinguishable one from another on the basis of their morphology and physical properties. Three major maceral groups are identifiable (Table 2). In most instances coal macerals are derived Table 2. Coal maceral nomenclature (after Stach et al. 1982) and inferred hydrocarbon potential

Liptinite (Exinite)

Vitrinite

Inertinite

Maceral Sporinite Cutinite Resinite Suberinite Lipodetrinite Exsudatinite Telinite Collinite Vitrodetrinite Semifusinite Fusinite Macrinite Sclerotinite Inertodetrinite Micrinite

ultimately from extant plant components. The inertinite and vitrinite macerals are derived predominantly from the structural parts of plants. Sporinite, cutinite, resinite and suberinite are the primary macerals of the liptinite group and are derived from spores, cutin, resin and suberin respectively. The various forms of alginite (algae), which are the predominant maceral in most marine and lacustrine source rocks, are absent or only occur in trace amounts in most coals with the notable exception of boghead coal. The elemental composition of isolated macerals reflects to some degree the original composition of the plant precursors (Fig. la) although they are substantially modified during the biochemical stages and early thermal stages of coalification (see above). Lipinite is richer in hydrogen than vitrinite which in turn is richer than inertinite (van Krevelen 1961). The maceral groups therefore occupy different pathways or coalification tracks with thermal maturation. These pathways are similar to the pathways for Types I - I V organic matter defined for sedimentary rocks in general (Tissot et al. 1974; Harwood 1977). Geochemical measurements and oil potential

Overall c o m p o s i t i o n

Maceral group

15

Hydrocarbon potential Hydrogen-rich; precursors for oil and gas

Hydrogen-poor, mainly precursors forgas Very hydrogenpoor; largely inert, but may produce gas at very late stages of maturation

Since hydrogen is the limiting factor in the generation of hydrocarbons from sedimentary organic matter, theoretical considerations suggest that the hydrocarbon potential of terrigenous organic matter may be explained in terms of the relative proportions of hydrogenpoor and hydrogen-rich components. Thus the associations of the microscopic components of coal with particular hydrogen content forms an empirical basis for the use of petrography in source rock assessment. However, quantitative knowledge of the hydrocarbon-generating capacity of individual macerals is lacking, but observations on organic matter types in general (Powell 1978, 1988a) suggest that in order for a source rock to be effective, 10-20% of its organic matter must equate with Type I organic matter, or 20-30% must equate with Type II organic matter. The bulk atomic H/C ratios would therefore fall in the range 0.8-0.9 (Powell 1988a) or Hydrogen Indices in Rock-Eval analysis above 220-300 before any oil expulsion is implied (Powel11988a; Hunt 1991; Noble et al. 1991). There are, however, many uncertainties in translating these percentages to proportions of maceral components to enable an organic petrographic means of quantifying oil source potential (see below).

16

T. G. POWELL & C. J. BOREHAM 2.0

A

2.0-

B

evolution path of Type I

RESIN ii

oE 1.0

~ :

1.s

T ~ ~

II !

Mean evolution path of

.

.

.

.

-

1.o -

/j

....

/ //

0.5

~

t

1

/

j

.i"

-

le evolution path o f Type IV

O.5-

oi,

;.2

o'.3

o:,

O/C (Atomic Ratio)

o'.~ o o

o'.t

o12

o'.3

oi,

01s

O/C ( Atomic Ratio)

Fig. 1. Comparison of kerogen types, evolution paths and petrographic components of coal based on atomic ratios. (A) Types I-III (Tissot et al. 1974); Type IV (Harwood 1977). Shaded area represents field of kerogen composition. (B) Petrographic components of coal (van Krevelen 1961).

More than any other type of source rock, the critical issue for the evaluation of potential terrigenous source rocks is the threshold concentration of hydrocarbons required to allow migration out of the source rock. This is not a simple question since it relates to rate of generation, gas-oil ratios and phase behaviour. These can only be evaluated properly by quantitative modelling of hydrocarbon generation and migration in each particular case. However, it is possible to make some general observations related to these theoretical concepts. Firstly, the range of Hydrogen Indices derived from Rock-Eval analysis of the immature source rocks in the case histories (Table 1) varies considerably. They range from 150 to 300 for coals and shales in the Cooper Basin, Niger Dalta, Mahakam Delta, and Beaufort-Mackenzie Basin through to over 400 for some coals and shales in the Ardjuna Sub-basin. Values around 200 appear to predominate in source rocks of the Niger Delta, Mahakam Delta and Beaufort-

Mackenzie Basin. Any source rock model must account for an apparent wide variation in labile kerogen content and for the low values observed, although it is not clear if the effect of the mineral matrix has been taken into effect in the Rock-Eval measurements in all cases (cf. Powell et al. 1989). Failure to do so may account for some low Hydrogen Indices reported for shales. Powell et al. (1991) have clearly shown that the correlation between Hydrogen Index and elemental composition of kerogen breaks down for coals with atomic H/C ratios in the range 0.8-1.0. They also have clearly shown that for a given Hydrogen Index there is a wide range in the pyrolysable yield of straight chain hydrocarbons and vice versa. Since most non-marine oils are paraffinic (greater than about 50% paraffins, Tissot & Welte 1984) the yield of paraffins on pyrolysis is in the most non-marine source rocks a suitable indicator of their ability to yield oil for migration. An exception is where

TERRESTRIALLY SOURCED OILS resin sources predominate (Snowdon 1980). It follows from these observations that the precursors of non-marine oil are set in a matrix which itself has varying degrees of lability under pyrolysis conditions. This labile matrix apparently contributes very little to hydrocarbon generation under natural conditions. This concept is perfectly understandable in that terrigenous organic matter, which is for the most part aromatic in structure, produces amongst the most hydrogen-rich oils found in nature. These observations re-emphasize the heterogeneous nature of coal and place limitations on the use of elemental analysis and the empirical interpret-. ation of bulk pyrolysis results in the determination of source potential in marginal quality terrigenous source rocks.

Petrographic considerations Thomas (1982) has suggested that differences in hydrocarbon source potential between Palaeozoic, Mesozoic and Tertiary coals may be related to the evolution of successive floras and climatic controls. Our studies (Powell et al. 1991) of Australian coals and carbonaceous shales from different ages and environments have shown that they have overlapping compositions with samples of a particular age tending to one extreme or another. They could be ordered with decreasing oil potential as follows Jurassic> Cretaceous = Upper Cretaceous - Tertiary > Permian=Triassic. Whereas this sequence follows the broad trends in petrographic composition (i.e. relative proportions of vitrinite, liptinite and inertinite) of Australian coals (Cook 1975; Thomas 1982) there is only a poor correlation between geochemical and petrographic compositions at the maceral group level on individual samples. Analysis of the petrographic and geochemical data (elemental ratios, Rock-Eval and quantiative pyrolysis gaschromatography) showed a better relationships between maceral composition and the ability to yield normal hydrocarbons on pyrolysis. The principal results are as follows: • Liptinite-poor ( C7) of a substantial proportion of the samples studied fall in the range 10-20mg per gram organic carbon (Powell et al. 1991). Although assessment of normal hydrocarbon yield is an appropriate measure of source potential for paraffinic oils, it would not be effective for source rocks in which resin is the predominant source material since the dominant hydrocarbon products would be naphthenic and aromatic in composition. A judicious combination of Rock-Eval pyrolysis and quantitative pyrolysis gas chromatography makes it possible to measure the hydrocarbon potential of most terrigenous source rocks and to infer the proportion of that potential which is attributable to oil and gas. However, these procedures do not quantify the potential for formation of commercial petroleum pools: here we need a mass balance approach described below. Furthermore, there is an increasing weight of observational evidence that the gas to oil ratio of generated hydrocarbons in combination with the temperature history is a major determinant of the timing and expulsion efficiency of petroleum from coals and associated carbonaceous shales. Modelling in each specific case is the only satisfactory way of addressing these issues (e.g. Noble et al. 1991).

20

T. G. POWELL & C. J. BOREHAM

M a s s balance a p p r o a c h to p e t r o l e u m potential Obviously while there is scope for future developments in empirical approaches to delineating source richness and maturation, only a mass balance approach is likely to yield a quantitative assessment of petroleum plays. The approach adopted here is that adopted by Cooles et al. (1986). Kerogen is classified into three types. Labile kerogen is capable of producing oil and gas, refractory kerogen generates primarily gas, while inert kerogen has no hydrocarbon generative potential. To represent petroleum generation and migration, a simple algebraic scheme based on organic carbon mass balance was devised by Cooles et al. (1986). A carbon deficit in a mature source rock compared with its immature analogue, implies that the carbon has been lost by migration from the source rock. The carbon content of an immature source rock is divided between free-oil carbon, reactive carbon (labile plus refractory kerogen) and inert carbon. The free oil content can be determined either from measurement of RockEval S1 or from solvent extractable organic matter and corrected for heavy-end and lightend hydrocarbon losses respectively (Cooles et al. 1986). The reactive carbon can be determined from Rock-Eval $2 while the inert carbon is the difference between TOC content and the sum of the free oil and the reactive carbon. A similar proportioning of carbon is obtained from the mature correlative. However, in order to compare the mature and immature correlatives and calculate the volumes of petroleum generated and migrated, it is assumed that there is a common starting point for the mature and the immature rock and there is no loss or additions to the inert carbon content as the sediment matures. Since sediments have variable TOC contents, the inert carbon content in the mature analogue is normalized to the inert carbon content of the immature analogue. Applying this normalization factor to correct free-oil and reactive carbon in the immature analogue enables the calculation of the Petroleum Generation Index (PGI) and the Petroleum Expulsion Efficiency (PEE) which are defined as follows: PGI =

Petroleum generated + Initial petroleum Total petroleum potential

PEE =

Petroleum expelled Petroleum generated + Initial petroleum

PGI defines the proportion of the total petroleum potential (free oil plus reactive

kerogen in the immature rock) that has been generated from the source rock at various stages of maturity. PEE is a measure of the extent of expulsion and relates to the difference between the calculated amount of petroleum that is liberated at a given PGI value and the amount of petroleum actually retained in the source rock. The data for the Westphalian coals only cover the maturation range equivalent to vitrinite reflectance levels of 1.0-3.0% R0. These data show that gas generation from refractory kerogen is essentially complete by a maturation level corresponding to 2.0% R0 vitrinite reflectance. This observation is consistent with the occurrence of coal-sourced gas in the Southern North Sea where the gas pools are associated with vitrinite reflectance levels of between 1 and 2% R0 in the Carboniferous (Barnard & Cooper 1983). Laboratory studies on US Carboniferous coals (Hiss 1986) indicate that significant gas generation occurs at lower maturation levels (

Fig. 2. n-Alkane distributions for an oil derived from marine source rocks and its associated wax which precipitated out during production.

Isoprenoids The ratio of the isoprenoids, pristane and phytane, has long been associated with the nature of depositional environments following the pioneering work of the Australian geochemists Brooks & Smith (1969) and Powell & McKirdy (1973). Their concepts were later reviewed and modified by Didyk et al. (1978) and ten Haven et al. (1987) who showed that in certain environments this ratio may also be affected by alternative sources for both pristane and phytane. In the earlier work it was assumed that both pristane and phytane were derived from the phytol side-chain of chlorophyll. More recently it has been shown that pristane can be

derived from a-tocopherol and phytane from the bis-phytanyl ethers which occur in archeabacteria. The recent development of the combined gas chromatographic-isotope ratio mass spectrometric technique has given u s the opportunity to determine whether or not in a particular sample, the pristane and the phytane are indeed derived from the same source material. For example, Freeman et aL (1990) have shown that in the case of the Messel oilshale these isoprenoids do indeed have different sources. However, for two of the Gippsland Basin oils, namely the Turrum and Barracouta oils, the isotopic values for the pristane and phytane were virtually identical as shown in

Fig. 1. n-Alkane distributions for (a) an oil derived from terrigenous source materials from the Cooper Basin, Australia; (b) a sample of Ozocerite extending to at least C70 and probably to C10oor higher in some samples when determined by High Temperature Gas Chromatography.

76

R P. PHILP 2. 6Z3C isotopic compositions (relative to PDB) of pristane and phytane for two Gippsland crude oils

Table

Sample

Pristane

Phytane

Barracouta Turrum

28.1 26.6

28.6 26.9

Table 2. Differences in the values between the two oils probably reflect differences in the maturity level of the samples. Following the early work, and in light of the more recent modifications, it would appear that rather than trying to assign a specific value of the Pr/Ph ratio to indicate the nature of the depositional environment it is better to say that where this ratio is greater than 4, or possibly even 5, then the original depositional environment was probably oxidizing. This was illustrated in an earlier paper by Powell (1988) who plotted worldwide distributions for Pr/Ph values for oils derived from terrigenous source materials. The histogram maximized in specific values of the region around values of 3 to 5. Pr/Ph values below this value should be treated with some degree of caution and care taken to see if alternative sources may also be responsible for the lower values rather than simply differ-

ences in the nature of the depositional environment. In addition to Pr and Ph, many of the oils often contain high concentrations of long-chain isoprenoids ranging up to at least C40 or C45 (Fig. 3). The majority of these compounds are regular isoprenoids and not the more unusual head-to-head compounds commonly associated with archeabacteria. Whilst the presence of these compounds may reflect the enhanced levels of microbial activity in the original oxic depositional environments, the possibility that they are also derived from polyprenols known to be associated with higher plant waxes cannot be excluded. For example, solanesol (C4s) was isolated from tobacco leaves where it was found partly as fatty acid esters (Rowland et al. 1956); Lingren (1965) isolated a series of C30 to C4s terpenolds, betualprenols from birch wood and in 1964 Burgos et al. identified a Cllo isoprenoid substance as a metabolic product of Aspergillum fumigatus. It is anticipated that detailed studies of the isotopic composition of these long chain compounds will provide additional information on the origin of these compounds. Sesquiterpanes

Abundant concentrations of sesquiterpanes were unequivocally identified for the first time in a number of Australian crude oils known to be

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'

. . . .

I N C R E A S I N G R E T E N T I O N TIME - - - >

Fig. 3. Long-chain head-to-tail isoprenoids determined by SIM of the ion at m/z 183 in an oil from the Taranaki Basin, New Zealand.

OILS DERIVED FROM TERRIGENOUS SOURCE MATERIALS sourced from terrestrial source material (Fig. 4). Earlier reports by Bendoraitis (1974) had tentatively identified the presence of various bicyclic compounds in a highly degraded seep of unspecified origin. The early work of Alexander et al. (1983, 1984) identified the major sesquiterpanes previously detected by Philp et al. (1981), to be based on the drimane and eudesmane structures. In view of the apparent absence of eudesmanes in samples older than Devonian, it was concluded that the eudesmanes were associated with an input from higher plants. The abundance of the drimanes in these older sediments led to the conclusion that they were associated with a microbial input. However, these conclusions may need to be reconsidered since drimane precursors have also been found in higher plants. In all probability these sesquiterpanes are more of an indication of the bacterial activity in the more oxic type of depositional environments responsible for the accumulation of the higher plant material. Indeed Alexander et al. (1984) have also shown that in certain cases there was a similarity between the distributions of the hopanes and the drimanes supporting the idea that the sesquiterpanes may indeed be derived from the hopanes and formed via a microbial mechanism. Early papers also proposed that the distribution of sesquiterpanes ranged from C14 to C~6 but a recent paper by Wang et al. (1990)

Ioo~

77

has shown that these compounds extend to C24 in a Chinese coal sample. Various other types of sesquiterpanes have also been found in oils derived from terrigenous source materials. These include cadalanes known to be derived from resin precursors particularly in oils from the Far East (van Aarsen et al. 1992) and cedrene and cuparene derivatives have also been found in Chinese oils known to contain a predominance of higher plant source material (Yongsong et al. 1991). In summary, sesquiterpanes such as the drimanes in particular, and possibly the eudesmanes, reflect the degree of microbial activity during the original episode of deposition as much as the terrigenous source input. The possibility of using these compounds as maturity indicators has not been investigated in detail but is something that may be potentially useful (Noble et al. 1987). Care also needs to be taken in sample preparation if one is to look at these compounds in quantitative detail since they are relatively volatile and can be easily lost during sample preparation.

Diterpanes Tri- and tetracyclic terpanes in the C19 and C2o range have long been known to be associated with resins from higher plants (Thomas 1969). The presence of their hydrocarbon analogues in

HOMODRIMANE

DRIMANE

m / z 123

] ' ' '

' / '

" '

'

I

'

'

~

'

1

~

'

'

'

I

'

'

'

'

I

'

INCREASING RETENTION TIME - - - >

Fig. 4. Sesquiterpanes in an oil derived from terrigenous source material as determined by SIM of the ion at m/z 123.

78

R . P . PHILP Vl] loo%

vI

III

,,,e. ~4,--,,',,,' ~ '

'

'

IV

IX

Iv,,-'S.~,,- - ~

I

'

~

'

'

I

'

'

'

'

I

'

~

'

'

I

'

INCREASING RETENTION TIME

'

~

'

I

'

~

'

'

--->

Fig. 5. Typical diterpane distribution in a crude oil from the Gippsland Basin. Major components (peaks I-IX) are identified in Table 3.

oils and source rocks has been used to establish a higher plant input to the source rocks. Diterpanes are abundant in many oils known to contain higher plant materials from countries such as Australia, New Zealand, Taiwan, Papua New Guinea, and Indonesia in the Southern Hemisphere (Philp et al. 1981; Alexander et al. 1988; Weston et al. 1989). An example of the diterpane distribution in a crude oil is shown in Fig. 5 and their identities listed in Table 3. Other areas such as the Beaufort-Mackenzie Delta region in Canada where the source rocks contain vast quantities of resinite also contain high

Table 3. Major diterpanes identified in oils derived f r o m terrigenous source materials Compound Peak number

Name

I

8fl(H)-labdane 4fl(H)- 19-norisopimarane rimuane 17-nortetracyclane

II III IV V VI VII VIII IX

ent-beyerane

iso-pimarane 16fl(H)-phyllocladane ent- 16ct(H)-kaurane 16a(H)-phyllocladane

concentrations of diterpanes (Snowdon & Powell 1982). Perhaps the most widely studied oils in terms of their diterpane distributions are those from the Gippsland and Taranaki basins of Australia and New Zealand respectively (Fig. 5; Philp et al. 1981; Weston et al. 1989). After an early report of these compounds in the Gippsland Basin oils by Philp et al. (1981), Alexander and coworkers published a series of papers detailing the identity of many of these compounds, changes to their stereochemistry with increasing maturation and assignment of specific structures to different plant types (R. Alexander et al. 1987, 1988; Noble et al. 1985a, b, 1986). The 12 diterpanes most commonly found in crude oils and sediments can be classified into 6 families on the basis of structural similarities, namely the labdane, abietane, pimarane, beyerane, kaurane and phyllocladane families (Fig. 6a and b). A table summarizing the frequency of published reports of the occurrence of these compounds in various plant types was published by R. Alexander et al. (1987) and Noble et al. (1985a) and is reproduced as Table 4. Diterpenoids based on the labdane, abietane, pimarane, beyerane, kaurane and phyllocladane structures typically occur in gymnosperms. Kauranoid-type diterpenoids are probably an ubiquitous component of all angiosperms. In contempary resins, pimarane-

OILS DERIVED FROM TERRIGENOUS SOURCE MATERIALS

79

Podocarpaceae

ent-Beyerane

17-Nortetracyclane

16J3(H)-Phyllocladane

($TEREOCHEMISTRYUNASSIGNED)

(a)

16c~(H)-ent-Kaurane

Araucariaceae

(Agathis - Kauri Pine)

15,19-Bisnorlabdane

(b)

16c~(H)-Phyllocladane

Fichtelite

19-Norlabdane

Rimuane

Labdane

19-Norisopimarane

Isopimarane

Fig. 6. Typical diterpenoid structures present in (a) Podocarpacean (gymnosperm) resins; (b) Araucariacean (gymnosperm) resins. type diterpenoids occur in conifers of the Pinaceae and Cupressaceae families and the southern conifer families of Podocarpaceae and Araucariaceae. Precursors of phyllocladane occur widely in the Podocarpaceae and kauranes in the Podocarpaceae, Araucariaceae, and Taxodiaceae. Labdane-type diterpanes were identified in the Athabasca tar sands and considered to have a microbial origin. However, labdane precursors are also present in southern conifers and if the labdanes occur in the absence of their higher homologues it is likely they are derived from conifers and not of a microbial origin.

Whilst most of the characteristic properties of oils from terrigenous source materials are associated with the saturate fractions of the crude oils there are a number of interesting and associated studies related to the aromatic fractions particularly with the diterpenoids. The most significant study in this area is by Alexander et al. (1988), who used aromatic biomarkers derived from various diterpenoids to differentiate oils derived from Permian sediments in the Australian Cooper Basin versus those derived from the younger Jurassic sediments of the overlying Eromanga Basin. The rationale for this is rather simple. The Arau-

+ + ---

++

+

+

+

+

+ ++

++

Pimarane a

--

--

++

+

Beyerane b

Tetracyclic

+ +

+ +

+ ++

+ + +

Kaurane

--

+ +

Phyllocladane

a P i m a r a n e s include i s o p i m a r a n e s a n d r i m u a n e s ; b includes s t a c h e n e s a n d h i b a e n e s ; + + + : w i d e s p r e a d ; + + : c o m m o n ; + : i n f r e q u e n t ; - - : r a r e or u n r e p o r t e d .

+

++

Angiosperms ( f l o w e r i n g plants) Gymnosperms ( m a i n l y conifers) Pteridophytes (ferns) Bryophytes ( m o s s e s a n d liverworts)

Abietane

Bicyclic l a b d a n e

Tricyclic

Occurrence of diterpenoids in land plants (reproduced from R. Alexander et al. 1987)

Plant t y p e

T a b l e 4.

oo

OILS DERIVED FROM TERRIGENOUS SOURCE MATERIALS cariaceae (kauri pines) became prominent in the early to mid-Jurassic and were absent from the older sediments. When the sediments from the Eromanga Basin were examined they were found to contain diterpanes characteristic of the Araucariaceae, whereas sediments from the Permo-Triassic Cooper Basin had different distributions of the saturate diterpanes and particularly the aromatic hydrocarbons. Aromatization of the resin-type diterpanes typically found in the Araucariaceae will lead to four major products, namely 1,2,5-trimethylnaphthalene, 1,7-dimethylnaphthalene, retene, and 1-methylphenanthrene (Fig. 7). If these compounds are not present in similar concentration or one or more is absent, then it can be said with a high degree of certainty that the sediments from which they are derived did not contain any resins from the Araucariaceae as was the case in the Cooper Basin sediments. In addition, it has been observed that isomerization reactions which occur to the diterpanes, occur before the onset of oil generation. Hence these compounds provide a useful indication of maturity in a region where the more commonly used vitrinite reflectance scale is inoperable. The two compounds used

81

here are kaurane and phyllocladane which can exist as both 16a(H) and 16fl(H) isomers. The 16fl(H) isomer is formed, from a precursor compound, in preference to the thermodynamically more stable 16a(H) isomer by a kinetically favoured reaction pathway. As the maturity level increases, the equilibrium distribution of the two isomers reaches a ratio of approximately 4 : 1 (Fig. 8; G. Alexander et al. 1987; R. Alexander et al. 1987). Finally, it has also been proposed by R. Alexander et al. (1987) that ratio of diterpanes/hopanes can be used as an indicator of oxicity. As the environment becomes more oxic the relative amounts of hopanes will increase due to higher levels of microbial activity hence lowering this ratio. (Resin compounds from angiosperms and found in oils from Indonesia will be discussed below.)

Sesterterpanes Sesterterpanes are terpanes based on a C 2 4 hydrocarbon skeleton and are generally tetracyclic compounds and are particularly abundant in certain oils derived from terrigenous source

NATURAL PRODUCTS

R=H, CH 3 ROOC d " N)

R.

Agathicacidand Methylagathate

.

.

Communolsand Communieacid

AROMATIC BIOMARKERS

1,2,5-Trimethylnaphthalene

H2OH , COOH . .

~

R=CH2OH , COOH R Sandaracopimaradienoland Sandaracopimaricacid

SATURATED BIOMARKERS

1,7-Dimethylnaphthalene 15,19-Bisnorlabdane 91

Retene

Abieticacid

1-Methylphenanthmae

19-Norlabdane

Labda~

MATURATION

19-Norisopimarane

Fig. 7. Diagenetic pathways of diterpenoids proposed by Alexander et al. (1988).

Fichtelite

82

R . P . PHILP

~H

~ -

"~H

types, hopanes and non-hopanoid-type terpanes. It is easiest to deal with the two groups separately since the distribution of the latter is source related, whereas the former tend to reflect the oxicity of the depositional environment.

1613(H(4) )-Phyol cal dane 16ct(H)(1) -Phyol cal dane Fig. 8. Proposed isomerization reactions between the 16fl(H) and 16a(H)-isomers ofphyllocladane (shown) and kauranes.

materials. In an earlier paper it was proposed that significant concentrations of the 17,21-C24secohopane were particularly characteristic of oils derived from terrigenous source materials, particularly in the case of the Gippsland Basin, Australia (Philp & Gilbert 1986). Initially it was proposed that this was a source-related phenomenon, but more recently it has become apparent that it is not as much a source-related phenomena but rather a reflection on the nature of the original depositional environment. The nearshore deltaic environment or mire environment in which the source materials were deposited provided a relatively oxic-type environment. This, in turn, would lead to enhanced levels of bacterial activity and production of high levels of hopanoid precursors. The high levels of bacterial activity would subsequently lead to degradation of the hopanes and production of the 17,21-secohopanes, the lower end member of which is the C24 compound. Following the initial identification of the C24 secohopanes more recent work has shown the presence of a variety of degraded compounds in the oils derived from terrigenous source materials, including New Zealand, Nigeria, Indonesia and Taiwan (Woolhouse et al. 1992) (Fig. 9). Compounds tentatively identified include the C24 des-A-ring analogues of the oleananes, lupanes, and ursanes which are typically very abundant in many of these oils (Fig. 10). Whilst it may be proposed that these des-A-ring compounds form via some method of A-ring degradation, it should be noted that a number of ring-A fissioned derivatives of pentacyclic triterpen-3-ols have been reported (Baas 1985; Baas & van Berkec 1991; Baas et al. 1992).

Pentacyclic terpanes The pentacyclic terpanes found in oils from terrigenous sources can be divided into two

Hopanes

The distribution of hopanes in oils derived from predominantly terrigenous source materials is very simple. For the most part the distribution is dominated by the regular hopanes, maximizing at C3o with the concentration of the extended hopanes above C31 decreasing exponentially, characteristic of the distribution associated with more oxic-type environments. Some of the oils from the Gippsland Basin have been observed to contain high concentrations of the C31 homohopanes (Fig. l l a ; Philp et al. 1981). In those oils, this probably arises from a source-related phenomenon since there are reports in the literature of C3a hopanoid precursors occurring in Recent peat deposits (Quirke et al. 1984) and brown coal deposits. In another unusual example from Gippsland, the Turrum oil was found to have a value for the 22S/22R epimers of the C31 homohopane epimers of approximately 1 : 9 compared to the more commonly observed ratio of 3:2. This anomaly was proposed by Philp & Gilbert (1982) to represent a case of an oil dissolving biomarkers from an immature coal sequence during migration (Fig. llb). Methylhopanes and the various series of norhopanes identified in sample sets from other environments and source materials are generally absent from oils derived from terrigenous sources although ten Haven et al. (1992) did report the occurrence of methylhopanes in coal samples. The presence of a compound referred to as compound X eluting just after the Cz9 hopane was described in an earlier paper (Philp & Gilbert 1986). This compound appeared to be a characteristic feature of oils derived from terrigenous source materials, particularly those from the Gippsland Basin. Although it was tentatively suggested that this compound was source related it was not until recently that compound X was actually identified by Moldowan and co-workers (1991) as a diahopane and found not to be a source-related parameter. Indeed Moldowan et al. (1991) proposed that this compound is formed during diagenesis from rearrangement of regular hopanoid natural products and thus in turn is more of an environmental indicator than a source indicator. It also appears that the relative concentration of this compound increases

OILS D E R I V E D F R O M T E R R I G E N O U S S O U R C E M A T E R I A L S 1E,e4

330-PAR 191 24

t24* 24

e6e

IE~04 .349

344-PAR 191

25

25*

,~,

,,;,

,,'.

. . . . .

~2,,

'

'

"

' ^',-,

'

=E+83 t3. ? 5 ?

358-PAR 191 26

ono

,

le0e

900

i tree

26*

.

.

.

.

I gee

.

.

.

.

i leee

.

,

•

q

~^, 13oo

•

JE*04 ,422

27

372-PAR 191

ooe

! 12oe

.

.

.

i I!oe

.

.

.

.

A,, i t2oo

.

.

.

.

i t3ee

INCREASING RETENTION TIME Fig. 9. MS/MS data showing distributions of sesterterpanes in an oil.

,

,

83

84

R. P. PHILP i

|11111

(1) 1013(H)-des-A-oleanane (R=H,R'=CH3) (3) 1013(H)-des-A-ursane (R'=H, R=CH 3)

/1|11'"

(2) 1013(H)-des-A-lupane

(4) C24-17,21-secohopane

Fig. 10. Tetracyclic terpanes present in oils from terrestrial source materials.

with increasing maturity demonstrating the fact that it is more thermally stable than other members of the hopane series.

N o n - h o p a n o i d terpanes

Non-hopanoid terpanes derived from higher plant sources are far more abundant than the hopanoids in many oils from terrigenous source materials. Higher plants contain a wide variety of triterpenoids and many of their hydrocarbon derivatives can be found in the corresponding oils and source rocks (Whitehead 1974). This paper is not the place to go into great detail about the wide variety of non-hopanoid triterpanes that have been identified in these oils. However, in brief, there are the compounds based on pentacyclic structures such as oleananes, lupanes and ursanes, along with their demethylated analogues (Fig. 12). These compounds are abundant in the oils of New Zealand (Czochanska et al. 1988), Taiwan (Philp & Oung 1991), Beaufort-Mackenzie Basin, Canada (Curiale 1991), and Nigeria (Woolhouse et al. 1992). The other major type of triterpanes is based on the cadalane structures (Fig. 13), derived from precursors present in the dammar

resins, and particularly abundant in oils from Indonesia (van Aarssen et al. 1992). One particular feature to note is that the oils of the Gippsland Basin contain copious quantities of the diterpanes indicative of the higher plant input but, because of their pre-Tertiary origin, contain none of the complex mixtures of non-hopanoid terpanes that the oils from the other regions of the world contain. Clearly, variations in the triterpenoid distributions reflect variations in the nature of the plant material present in the source rocks and in turn the age of the oil itself. Oleananes may be derived from a number of naturally occurring precursors, including taraxer-14-en-3fl-ol and olean-12-en-3fl-ol, which through a series of complex reduction and isomerization reactions can produce two isomers of oleanane (ten Haven & Rullk6tter 1988). Initially it was thought that the oleananes existed as only one isomer in both oils and source rocks. However, with a good high efficiency capillary column, it is possible to show that there are two isomers present in many of these samples, namely the 18a(H) and 18fl(H)-isomers. It has also been shown that the ratio of these compounds will change with increasing maturity until an apparent equilibrium ratio is reached

OILS DERIVED FROM TERRIGENOUS SOURCE MATERIALS

85

lOO%

m / z 191 C31

C30 C29 Tm

J, ' ~ ....... r--'-'r--'--[

~

I

i

(a)

I

t

J

I

i

INCREASING RETENTION TIME - - - >

100%" m/z 191 c

, ''

(b)

'

'

'

I

'

'

'

'

,Jl I

'

'

'

'

I

'

'

2~

It '

'

I

'

'

~

'

I

'~

'

'

~

I

~

'

'

'

I

'

'

'

'

I

'

'

'

'

I

'

'

I

,

INCREASING RETENTION TIME - - - >

Fig. 11. (a) Hopane distribution (m/z 191) in a crude oil dominated by an abundance of Ca1 homohopanes. (b) An unusual 22S/22R Ca1 hopane distribution in the Turrum oil from the Gippsland Basin.

(Riva et al. 1988). It has been proposed that this ratio is particularly useful in the early stages of oil generation. However, whether its potential as a maturity indicator will ever be realized is unclear due to the problems of resolving the two isomers in a reproducible fashion. A variety of bisnorlupanes, norlupanes, nor-

oleananes, 28,30-bisnorhopane, de-A-lupane and dehydroabietane have been recently identified in oils from the Beaufort-Mackenzie region by Curiale (1991; Fig. 14). Peakman et al. (1991) identified 24-nor-urs-12-ene and 24-nor-olean12-ene in a Beaufort-Mackenzie oil as well as 24-nor-lupane and a series of 24-nor-oleananes.

86

R. P. PHILP

-2 23

24

24,27-Dinoroleanane

Oleanane

~hl,

24,28-Dinor-18oc-oleanane

i,,

23 24 Lupane

24-Norlupane

24-Norarborane

(Trendel eta./., 1991 - Egyptian oil)

CH

3

H

24-Nor-urs-12-ene

CH

3

H

24-Nor-olean-12-ene

(Peakman et aL, 1991. Beaufort~Mackenzie Delta Oil)

Fig. 12. Non-hopanoid type triterpanes present in oils from terrestrial source materials.

Trendel et al. (1991) reported the presence of 24-norlupane, 20-noraborane, 24,27-dinoroleanane and 24,28-dinor-18a-oleanane in an Egyptian oil. In both of these cases the presence of the compounds correlates with the contribution of higher plant material in the source rocks for these oils. In a 1983 paper Grantham et al. (1983) tentatively assigned the labels W, X, and T to three prominent compounds in oils from the Far East. Subsequent work by Cox, van Aarssen and others has shown that these compounds are bicadinane isomers derived from precursors that

are present in dammar resins (van Aarssen et al. 1992). Although the predominant members of the series are in the C3o range it has been shown that analogues of these compounds are present in the higher molecular weight region with components up to C60 and C75 and possibly higher. These bicadinane structures have also been reported in samples from Utah, the Messel shale and more recently in oils from New Zealand by Curry et al. (this volume). The presence of the saturated hydrocarbons is often accompanied by 1,6-dimethylnaphthalene and cadalene in the aromatic fraction.

OILS DERIVED FROM TERRIGENOUS SOURCE MATERIALS

87

,IIIIL~ -

=

Compound

T -

=

(trans-trans-trans)

1,6-DMN

=

Compound W - (cis-cis-trans)

Cadalene

Fig. 13. Angiosperm resin terpenoid structures based on the cadalane-type structure (van Aarssen et al. 1992).

Steranes The sterane distributions in most oils derived from terrigenous source materials are very simple and dominated by the C29 steranes. In the situation where there is a mixed input with

higher plant material as well as algal material the problem is more complex. In addition to the C27 and C28 steranes, some of the C29 steranes may also be derived from algal material. The other characteristic feature of the sterane distribution

1OO%-

24-Norlupane 17B(H)-24,28-Bisnorlupane

17a0I)-24,28-Bisnorlupane

m / z 177

Hopane L Oleananes~ll

INCREASING RETENTION TIME

--->

Fig, 14. M / Z 177 chromatogram for a sample from the Canadian Beaufort area (Curiale 1991) containing significant quantities of various demethylated lupane derivatives plus oleanane.

88

R. P. PHILP Table 5. Summary of quantification data for steranes/terpanes in crude oils Sample location

C27"

C2s*

C29"

C3o*

217/191

Offshore Taiwan Marine-sourced oils

8.09 43.43

7.83 30.75

25.33 34.75

1.89 13.36

0.80 3.23

* Expressed in ng//~l using d 2 a s internal standard.

for these types of samples is the presence of diasteranes. It has long been proposed that the relative concentration of the diasteranes reflected the presence of clay minerals and their ability to catalyse sterene rearrangement reactions. However, it has become clear in recent years that the oxicity of the depositional environment provides another clue to the fate of the sterols. Highly anoxic environments will rapidly reduce the sterenes, hence reducing the amount of sterenes available for the rearrangement reaction. However, a more oxic-type environment will leave more of the sterenes unaffected and hence available for rearrangement. It is possible, therefore, that the concentration of the rearranged steranes in these oils more closely reflects the oxicity of environment rather than the presence or absence of the clay minerals (Moldowan et al. 1986). The ratio of hopanes/steranes in oils, based on the m/z 191 and rn/z 217 chromatogram respectively, derived from terrigenous source materials is typically greater than 5 and as large as 10 in the case of Indonesian oils. This, again, is a characteristic of these oils and results from the high level of bacterial activity in the depositional environment and it is not a direct source indicator. The absolute concentrations of steranes in oils derived from terrigenous source materials is also much lower than in oils from marine source materials. A brief summary of results from a quantitation study performed on oils from Taiwan and compared with oils known to be derived from marine source materials is summarized in Table 5. In this summary average values are given from the analysis of several samples but a more comprehensive set of results can be found in the paper by Philp & Oung (1991).

Summary In the preceding sections a number of the important geochemical characteristics of oils derived from terrigenous source materials have been described. It is true to say that not all of the features will be common to all such oils, due to

variations in age and nature of plant types responsible for the organic matter in the source rocks. However, when reviewed collectively, any oil containing a number of these characteristics is probably sourced partially, if not entirely, from abundant higher plant material. It is also important to remember that due to the nature of the environment in which this organic matter is typically deposited, mire or nearshore coastal or fluvial-deltaic, the level of microbial activity will be relatively high due to high levels of oxicity. The contribution of organic matter from the microbial biomass will be significant, therefore, and reflected in terms of the contribution from the hopanes and other classes of terpanes. In the following list the most important geochemical characteristics of oils from terrigenous source materials are summarized along with an indication as to whether they more closely reflect the depositional environment or source input. • High concentration of saturated hydrocarbons relative to aromatic, polars and asphaltenes (Source). • Low, or negligible, S content (Depositional environment). • n-Alkane distributions typically maximize in C2o-C40 region (Source). • Pr/Ph ratios typically greater than 4 (Depositional environment). • Drimanes and e u d e s m a n e s important sesquiterpanes reflect both source and depositional environment. • Diterpanes - reflect source and can be used to differentiate plant types and age of oils. • Sesterpanes - derived from pentacyclic analogues, probably as a result of microbial action, and can be source and environment related. • Hopanes, for the most part, reflect oxic nature of depositional environments generally associated with the source of this type of oils. Concentration of the extended hopanes decrease exponentially with increasing carbon number.

OILS D E R I V E D FROM TERRIGENOUS SOURCE MATERIALS • M e t h y l h o p a n e s and n o r h o p a n e s not comm o n l y associated with these oils. • C o m p o u n d X c o m m o n in m a n y of these oils has n o w b e e n identified as a d i a h o p a n e . • N o n - h o p a n o i d t e r p a n e s associated with these oils include o l e a n a n e s , lupanes, ursanes, p o l y c a d i n a n e s , All reflect inputs of various plant types. U n s a t u r a t e d triterpanes also

89

p r e s e n t in s o m e oils derived f r o m t e r r i g e n o u s source material. • Steranes are d o m i n a t e d by C29 derivatives, truly indicative of higher plant input, in oils d e r i v e d exclusively from h i g h e r plant material. P r e s e n c e of C27 and C28 i n t r o d u c e s ambiguity as to w h e t h e r C29 is h i g h e r plant or algal.

References

VAN AARSSEN, B. G. K., HESSELS, J. K. C., ABBINK, O. A. & DE LEEUW, J. W. 1992. The occurrence of polycyclic sesqui- , tri , and oligoterpenoids derived from a resinous polymeric cadinene in crude oils from southeast Asia. Geochimica et Cosmochimica Acta, 56, 1231-1246. ADAM, P., TRENDEL, J. M. & ALBRECHT, P. 1991. Novel thiophene derived from higher plant triterpenes in sediments. Tetrahedron Letters, 56, 4179-4182. ALEXANDER, G., HAZAI, I., GRIMALT,J. & ALBAIGES, J. 1987. Occurrence and transformation of phyllocladanes in brown coals from Nograd Basin, Hungary. Geochimica et Cosmochimica Acta, 51, 2065-2073. ALEXANDER, R., KAGI, R. & NOBLE, R. 1983. Identification of the bicyclic sesquiterpenes drimane and eudesmane in petroleum. Journal of the

Chemical Society Chemical Communications, 226-228. , , & VOLKMAN, J. K. 1984. Identification of some bicyclic alkanes in petroleum. Organic Geochemistry, 6, 63-70. , LARCHER, A. V., KAGI, R. I. & PRICE, P. L. 1988. The use of plant-derived biomarkers for correlation of oils with source rocks in the Cooper/Eromanga basin system, Australia. Australian Petroleum Exploration Association Journal, 28, 310-324. --, NOBLE, R. A. & KA6I, R. J. 1987. Fossil resin biomarkers and their application in oil to sourcerock correlation, Gippsland basin, Australia. Australian Petroleum Exploration Association Journal, 27, 63-72. BAAS, W. J. 1985. Naturally occurring seco-ringA-triterpenoids and their possible biological significance. Phytochemistry, 24, 1875-1889. --& VAN BERKEL, I. E. M. 1991. 3,4-Secotriterpenoid acids and other constituents of the leaf wax of Hoya Naumanii. Phytochemistry, 30, 1625-1628. --, --, VERSLUIS, C., HEERMA, W. & KREYENBROEK, M. N. 1992. Ring-A fissioned 3,4-seco3-nor-triterpene-2-aldehydes and related pentacyclic triterpenoids from the leaf wax of Hoya Australia. Phytochemistry, 31, 2073-2078. BENDORAITIS, J. G. 1974. Hydrocarbons of biogenic origin in petroleum - aromatic triterpenes and bicyclic sesquiterpenes. In: TIssoT, B. & BIENNER, F. (eds) Advances in Organic Geochemistry 1973. Editions Technip, Paris, 209224.

BROOKS, J. D. & SMITH, J. W. 1969. The diagenesis of plant lipids during the formation of coal, petroleum and natural gas- I I - Coalification and the formation of oil and gas in the Gippsland Basin. Geochimica et Cosmochimica Acta, 33, 1183-1194. BURGOS, J., BUTTERWORTH,P. H. W., HEMMING,F. W. & MORTON,R. A. 1964. The biosynthesis of longchain polyisoprenoid alcohol by Aspergillus fumigatus, Fresenius. The Biochemical Journal, 91. CURIALE, J. 1991. The petroleum geochemistry of Canadian Beaufort Tertiary 'non-marine' oils. Chemical Geology, 93, 21-46. CZOCHANSKA, Z., GILBERT, T. D., PHILP, R. P., SHEPPARD,C. M., WESTON, R. J., WOOD, T. A. & WOOLHOUSE, A. D. 1988. Geochemical application of sterane and triterpane biomarkers to a description of oils from the Taranaki Basin in New Zealand. Organic Geochemistry, 12, 123-135. DEL RIO, J. C. & PHILP, R. P. 1992a. Nature and Geochemistry of High Molecular Weight Hydrocarbons (Above C4o) in Oils and Solid Bitumens. Organic Geochemistry, 18,541-553. -& -1992b. High Molecular Weight Hydrocarbons: A New Frontier in Organic Geochemistry. Trends in Analytical Chemistry, 11, 187-193. -& -1992c. Oligomerization of Fatty Acids as a Possible Source for High Molecular Weight Hydrocarbons and Sulphur-Containing Compounds in Sediments. Organic Geochemistry, 18, 869-880. DIDYK, B. M., SIMONEIT,B. R. T., BRASSELL,S. C. t~ EGLINTON, G. 1978. Organic geochemical indicators of paleoenvironmental conditions of sedimentation. Nature, 271,216-222. FREEMAN, K. H., HAYES, J. M., TRENDEL, J.-M. & ALBRECHT, P. 1989. Evidence from GC-MS carbon-isotopic measurements for multiple origins of sedimentary hydrocarbons. Nature, 353,254-256. GRANTHAM, P. J., POSTHUMA, J. • BAAK, A. 1983. Triterpanes in a number of Far-Eastern crude oils. In: BJOROY, M. et al. (eds) Advances in Organic Geochemistry 1981. J. Wiley and Sons, Chichester, 675-683. TEN HAVEN, H. L., DE LEEUW, J. W., SINNINGHE DAMSTI~, J., SCHENCK, P. A., PALMER, S. E. & ZUMBERCE, J. 1988. Application of biological markers in the recognition of palaeo-hypersaline

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environments. In: FLEET, A. J., KELTS, K. & TALBART, M. R. (eds) Lacustrine Petroleum Source Rocks. Geological Society, London, Special Publication, 40,123-130. , - - , RULLKOTTER,J. & SINNINGHEDAMSTI~,J. S. 1987. Restricted utility of the pristane/phytane ratio as a palaeoenvironmental indicator. Nature, 330, 641-643. , PEAKMAN,T. M. & RULLKOLLTER,J. 1992. Early diagenetic transformation of higher-plant triterpenoids in deep-sea sediments from Baffin Bay. Geochimica et Cosmochimica Acta, 56, 2001-2024. - & RULLKOTrER, J. 1988. The diagenetic fate of taraxer-14-ene and oleanene isomers. Geochimica et Cosmochimica Acta, 52, 2543-2548. HEDBURG, H. D. 1968. Significance of high wax oils with respect to genesis of petroleum. American Association of Petroleum Geologists Bulletin, 52, 736-750. LINGREN, B. O. 1965. Homologous aliphatic Cao-C4s terpenols in birch wood. Acta Chemica Scandinavica, 19, 1317-1326. MCKIRDY, D. M., Cox, R. E., VOLKMAN, J. K. & HOWELL, V. J. 1986. Botryococcane in a new class of Australian nonmarine crude oils. Nature, 320, 57-59. MOLDOWAN, J. M., FAGO, F. J., CARLSON, R. M. K., YOUNG, D. C., VAN DUYNE, G., CLARDY, J., SCHOELL, M., PILLINGER, C. T. & WATT, D. S. 1991. Rearranged hopanes in sediments and petroleum. Geochimica et Cosmochimica Acta, 55, 3333-3353. & SEIFERT, W. K. 1979. Head to head linked isoprenoid hydrocarbons in petroleum. Science, 204, 169-171. , SUNDARARAMAN,P. & SCHOELL,M. 1986. Sensitivity of biomarker properties to depositional environment and/or source input in the Lower Toarcian of SW Germany. In: LEYTHAUSER,D. t~ RULLHOTTER, J. (eds) Advances in Organic Chemistry 1985. Pergamon Press, London, 915-926. NOBLE, R. A., ALEXANDER, R. 8z KAGI, R. J. 1987. Configurational isomerization in sedimentary bicyclic alkanes. Organic Geochemistry, 11, 151-156. --, ., & KNOX, J. 1985b. Tetracyclic diterpenoid hydrocarbons in some Australia coals, sediments and crude oils. Geochimica et Cosmochimica A cta, 49, 2141-2147. - & -1986. Identification of some diterpenoid hydrocarbons in petroleum. Organic Geochemistry, 10, 825-829. ~, KNox, J., ALEXANDER,R. & KAGI, R. I. 1985a. Identification of tetracyclic diterpene hydrocarbons in Australian crude oils and sediments. Journal of the Chemical Society, Chemical Communications, 32-33. PALACAS J. G., ANDERS, D. E. & KING, J. D. 1984. South Florida Basin - A Prime example of carbonate source rocks in petroleum. In: PALACAS, J. G. (ed.) Petroleum Geochemistry and Source Rock Potential of Carbonate Rocks.

PHILP American Association of Petroleum Geologists, Studies in Geology, 18, 71-96. PEAKMAN,T. M., TEN HAVEN, H. L. & RULLKOTTER,J. 1991. Characterisation of 24-nor-triterpenoids occurring in sediments and crude oils by comparison with synthesized standards. Tetrahedron, 47(23), 3779-3786. PHILP, R. P. ~ GILBERT, T. D. 1982. Unusual distribution of biological markers in Australian crude oil. Nature, 229,245-247. --& 1986. Biomarker distributions in Australian oils predominantly derived from terrigenous source material. In: LEYTHAUSER,D. & RULLKOTq'ER, J. (eds) Advances in Organic Geochemistry 1985. Pergamon Press, London, 73-84. --, t~Z FRIEDRICH, J. 1981. Bicyclic sesquiterpenoids and diterpenoids in Australian crude oils. Geochimica et Cosmochimica Acta, 45, 1173-1180. - - & OUNG, J.-N. 1991. Biomarker distribution in crude oils as determined by tandem mass spectrometry. In: MOLDOWAN,J. M., ALBRECHT, P. & PHILP, R. P. (eds) Biological Markers in Sediments and Petroleum. Prentice Hall, Englewood Cliffs, New Jersey, 106-123. POWELL, T. G. 1988. Developments in concepts of hydrocarbon generation from terrestrial organic matter. In: WAGNER, H. C., WAGNER, L. C., WANG, F. F. H. & WONG, F. L. (eds) Petroleum resources of China and related subjects. CircumPacific Council for Energy and Mineral Resources Earth Science Series, 10,807-824. - & McKIRDY, D. M. 1973. Relationship between ratio of pristane to phytane, crude oil composition and geological environment in Australia. Nature, 243, 37-39. QUIRKE, M. M., WARDROPER, A. M. K., WHEATLEY, R. E. & MAXWELL, J. R. 1984. Extended hopanoids in peat environments. Chemical Geology, 42, 25-43. RIVA, A., CACCIALANZA,P. G. & QUAGLIAROLI,C. F. 1988. 18fl(H)-Oleanane in crudes and in Tertiary-Upper Cretaceous sediments. Definition of a new maturity parameters. In: MATTAVELI, L. & NOVELLI, L. (eds) Advances in Organic Geochemistry 1987. Pergamon Press, Oxford. ROWLAND, R. L., LATIMER,P. H. & GILES, J. A. 1956. Flue-cured tobacco I. Isolation of solanesol, an unsaturated alcohol. Journal of the American Chemical Society, 78, 4680-4683. SNOWDON, L. R. & POWELL, T. G. 1982. Immature oil and condensate-Modification of hydrocarbon generation model for terrestrial organic matter. American Association of Petroleum Geologists Bulletin, 66,775-788. TELEGAAR, E. 1990. Resistant biomacromolecules in morphologically characterized constituents of kerogen: A key to the relationship between biomass and fossil fuels. PhD thesis, Technical University of Delft, Delft. THOMAS, B. R. 1969. Kauri resins- modern and fossil. In: EGLINTON, G. & MURPHY, M. T. J. (eds)

OILS DERIVED FROM TERRIGENOUS SOURCE MATERIALS Organic Geochemistry - Methods and Results. Springer-Verlag, Berlin, 599-618. TRENDEL, J. M., ALBRECHT,P., RIVA, A. & GHISELLI, C. 1991. Novel demethylated higher plant triterpanes in petroleum. In: MANNING,D. A. C. (ed.) Organic Geochemistry. Advances and applications in the natural environment. Manchester University Press, Manchester, 212-214. WANG, T-G., SIMONEIT, B. R., PHILP, R. P. & Yu, C. P. 1990. Extended 8fl(H)-drimane and 8,14secohopane series in a Chinese boghead coal. Journal of Energy and Fuels, 4, 177-183. WESTON, R. J., PHILP, R. P., SHEPPARD, C. M. & WOOLHOUSE, A. D. 1989. Sesquiterpanes, diterpanes and other higher terpanes in oils from the Taranaki Basin of New Zealand. Organic Geochemistry, 14, 405--421.

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WHITEHEAD, E. V. 1974. The structure of petroleum pentacyclanes. In: TISSOT,B. & BIENNER,F. (eds) Advances in Organic Geochemistry 1973. Editions Technip, Paris, 225-243. WOOLHOUSE, A. D., OUNG, J-N., PHILP, R. P. & WESarON, R. L 1992. Triterpanes and ring-A degraded triterpanes as biomarkers characteristic of Tertiary oils derived from predominantly higher plant sources. Organic Geochemistry, 18, 23-31. YONGSONG,H., ANSONG,G., Fu, J., SHENG,G., ZHAO, B., CHENG, Y. • LI, M. 1991. A comparative study of biomarker assemblage, oil precursor and depositional environment of Damintun extra high wax oils. In: ECKARDT, C. B., MAXWELL, J. R., LARTER,S. R. & MANNING,D. A. C. (eds) Advances in Organic Geochemistry 1991, Pergamon Press, London, 29-39.

Chemical heterogeneity among adjacent coal microlithotypesimplications for oil generation and primary migration from humic coal S C O T T A. S T O U T Unocal Energy Resources Division, P O B o x 76, Brea, C A 92621, U S A Abstract: Laser radiation focused onto a coal polished perpendicular to bedding has been

used to thermally extract and pyrolyse the organic matter from three adjacent microlithotypes in a Tertiary, autochthonous, hydrogen-rich, sub-bituminous (early catagenesis/ bituminization stage) humic coal from Indonesia. The distribution of hydrocarbons released during laser irradiation are shown to vary on a millimetre scale between adjacent humotelinite-, liptodetrinite-, and resinite-dominated microlithotypes. This variability is not due to varying thermal maturity but rather to (1) the inherent chemical variability of the macerals comprising each microlithotype; and/or (2) the presence of migrated, or nonindigenous, bitumen/oil. Hydrocarbon yields from each microlithotype suggest that primary migration between microlithotypes has occurred. Specifically, long chain n-alkanes and isoprenoids, which were most likely generated in the cutinite-derived liptodetrinitedominated microlithotype (liptoclarite), are much more abundant in the overlying liptinitefree, humotelinite-dominated microlithotype (telite) and in the underlying resinitedominated microlithotype (resinoclarite). These observations suggest that while the type of macerals plays an important role in the generation of oil within coals, it is the physical association between macerals (i.e. the microlithotypes present) which significantly influences the primary migration of oil within, and expulsion of oil from, coal seams. Thus since coals are extremely variable, both chemically and physically, generalizations suggesting all liptinite-rich humic coals can act as oil source rocks may be misleading. Liptinite-rich humic coals with high concentrations of finely-admixed liptinite and huminite macerals (e.g. liptodetrinite in a humodetrinite and mineral matrix, as would occur in microlithotypes with a detrital origin) may permit both oil generation and expulsion. Characteristics of the telite suggest, due to their high absorptive capacities and (micro)porosity throughout most of bituminization/catagenesis, coals which contain an abundance of massive huminite macerals (e.g. humotelinite or gelinite) may tend to trap hydrocarbons generated from nearby or encased liptinites within their networks. Such macerals (the precursors to desmocoUinites in bituminous coals) may become relatively hydrogen rich and often fluoresce under uv light and may not expel hydrocarbons until they are subsequently cracked to gas.

Coal is comprised of heterogeneous mixtures of macerals and lesser amounts of minerals. Coal macerals, however, seldom occur isolated from one another but instead are intimately associated with other macerals. These associations of macerals are termed microlithotypes (Stach et al. 1982) and are considered the 'organic facies' of coals (Jones 1987). When coal is polished perpendicular to its bedding plane and examined under the microscope, microlithotypes can be recognized as individual layers parallel or sub-parallel to the bedding planes. The International Commission for Coal Petrology (ICCP) dictates that these layers be at least 50,um thick before one microlithotype should be distinguished from another. Microlithotypes are classified according to the predominant type of maceral(s) present within each layer (Table 1). The classi-

fication of microlithotypes, thus, is essentially a classification of (1) the type of precursor organic matter; and (2) its degree of early diagenesis experienced in the original mire (Stach et al. 1982). It is well known that the chemical and physical properties of the different microlithotypes play a vital role in determining the technological properties (e.g. coking power) of a coal (Stach et al. 1982). This, in turn, arises from the chemical and physical properties of the individual macerals comprising microlithotypes. Thus, it follows that a coal's potential to generate oil will also be determined by the microlithotypes present. For example, there is general agreement that sapropelic coals, i.e. those with an abundance of hydrogen-rich, liptinite macerals, as would occur in liptites and clarites (Table 1), can generate liquid hydrocarbons (see

From Scott, A. C. & Fleet, A. J. (eds), 1994, Coal and Coal-bearing Strata as Oil-prone Source Rocks? Geological Society Special Publication No. 77, pp. 93-106.

93

94

S. A. STOUT Table 1. Summary of microlithotype classification of bituminous coals modified from Stach et al. (1982) Dominant maceral(s)

Microlithotype

Group name

Collite Telite* Sporite Cutite Resite Algite Liptodetrite Semifusite Fusite Sclerotite Macroite

Vitrite

Monomaceralic

Collinite Telinite Sporinite Cutinite Resinite Alginite Liptodetrinite Semifusinite Fusite Sclerotinite Macrinite

Liptite

Inertite

Bimaceralie

Sporinite/Vitrinite Cutinite/Vitrinite Resinite/Vitrinite Liptodetrinite/Vitrinite Vitrinite/Inertinite Sporinite/Inertinite Cutinite/Inertinite Resinite/Inertinite Liptodetrinite/Inertinite

Sporoclarite Cutinoclarite Resinoclarite* Liptoclarite* Vitrinertite Sporodurite Cutinodurite Resinodurite Liptodetrinodurite

Clarite

Vitrinertite Durite

Trimaeeralie

Vitrinite-dominated mix Liptinite-dominated mix Inertinite-dominated mix

Duroclarite Vitrinertinoliptite Clarodurite

Trimacerite

* Precursors of these microlithotypes were studied herein.

Hunt 1991 and references therein). Sapropelic coals are, however, geologically rare. Alternatively, the geologically much more common humic coals, comprised of predominantly hydrogen-poor vitrite microlithotypes (Table 1), are considered to generate primarily gas (mostly methane and CO2). However, many humic coals, especially those occurring in Tertiary deltaic settings, contain 10-30% liptinites. It is this type of liptinite-rich humic coal that is the main subject of any 'oil-from-coal' debate. It is generally accepted that certain humic coals can generate oil. The primary question remaining surrounds the potential to expel liquid hydrocarbons from the coal network (prior to their being cracked to gas). Does primary migration occur in humic coals (Durand & Paratte 1983; Huc et al. 1986), or does the microporosity and plasticity of the coal network enhance absorption and inhibit primary migration (Saxby & Shibaoka 1986; Landais & Monthioux 1988)? While cracks and fissures in coal are probably important in this regard (Hvoslef et al. 1988), the answer to this question, at least to some degree, must depend on the

physical arrangement of, or association among, macerals (i.e. a coal's 'microtexture'). Recently, this physical property has been suggested to control the primary migration process in certain liptinite-rich humic coals (Bertrand 1989; Mukhopadhyay 1989). Thus in addition to maceral type, the maceral associations, i.e. microlithotypes, are likely to be of utmost importance in determining a coal's potential to generate and expel oil. The objective of this study is to document and compare the petrographic and chemical character of the organic matter within three adjacent microlithotypes in a Tertiary subbituminous, liptinite-rich humic coal from Indonesia. A novel, laser-based technique which permits a collective analysis of the thermal extract and pyrolysate from selected microlithotypes in situ on polished blocks has been employed. Hydrocarbon distributions from the individual microlithotypes are compared to conventional solvent extract and flash pyrolysate from the blended mixture of the three microlithotypes. The results have implications for determining: (1) small-scale variation in organic

COAL MICROLITHOTYPE HETEROGENEITY matter composition within coal seams; (2) the variability in chemistry among different microlithotypes; and (3) the capacity for primary migration in hydrogen-rich humic coals. A subbituminous rank coal was selected over higher or lower ranks as it represents the early stages of bituminization/catagenesis in coals which is generally reported to occur between 0.5 and 1.3% Rm (Stach et al. 1982). S a m p l e description and analytical m e t h o d s

Sample A fresh outcrop sample of a Tertiary, autochthonous, sub-bituminous coal from the Bekoso seam in the Pasir Sub-basin, East Kalimantan (several miles southwest of Balikpapan) was collected. A small (4 cm 3) specimen of unextracted coal was embedded in epoxy resin and polished perpendicular to bedding. Huminite/vitrinite reflectance (random), RockEval pyrolysis yields, and total organic carbon content were determined for an aliquot of the selected coal using standard techniques. These numerical data are shown in Table 2.

Organic petrology Petrographic examination (200 point counts) of the crushed (+ 20 mesh) blended coal revealed an abundance of liptinite macerals (mostly liptodetrinite and resinite) in varying concentrations in a huminite matrix. Inertinite was relatively minor (Table 2). This concentration of liptinite (28%) is usually considered sufficient to generate oil in humic coal (Hunt 1991). Micro-

Table 2. Characteristicsof the blended microlithotypes from the Bekoso coal Maceral composition ( % vol.) Huminite Liptinite Inertinite Huminite reflectance TOC Rock-Eval S1 (mg HC g-1 rock) $2 (rag HC g-1 rock) $3 (mg CO2 g-a rock) Tmax HI (mg HC g-1TOC) OI (mg CO2 g-1TOC) Solvent extract yield (% wt)

68 28 4 0.61 65.8 10.2 209.0 9.5 433 318 14 4.94

95

lithotype analysis of the uncrushed coal polished perpendicular to bedding revealed three petrographically distinct but adjacent microlithotypes selected for this study (Fig. 1). The maceral terminology employed throughout the paper is according to the ICCP (1973) classification for low rank coals. The ICCP has not formally adopted a microlithotype terminology specific to low rank coals. As a result, the terminology employed throughout this paper will be adapted from that used for bituminous coals (Table 1). One might think of the microlithotypes studied as being precursors to those listed in Table 1. For example, the upper microlithotype was dominated by a mixture of ulminite and textinite which was, no doubt, derived from ligno-cellulosic cell wall material (Fig. la). The macerals present would be considered precursors to telinite, thus this microlithotype would be considered a telite precursor, and is thus termed telite herein. Similarly, the middle microlithotype was considered a liptoclarite precursor dominated by a mixture of humodetrinite (attrinite) and liptodetrinite (mostly spore and cuticle fragments; Fig. lb). This microlithotype also contained the highest proportion of mineral matter of the three microlithotypes and could be considered to have a detrital origin. The bottom microlithotype was considered a resinoelarite precursor being dominated by resinite mixed with ulminite (Fig. lc).

Laser extraction and micropyrolysis-GCMS A 4.0 W continuous wave Nd-YAG (CVI Model C-95) near-IR (1064 nm) laser beam was focused through a microscope (with special IR-coated optics) and glass window of a small Teflon sample chamber onto the polished surface of each of the microlithotypes studied. The sample chamber was continually flushed with helium and had a slight vacuum (c. 75 kPa) pulled from the opposite side of the chamber through a heated (290°C) nickel transfer line (Fig. 2). The heat from the laser beam was used to volatilize and pyrolyse the targeted organic matter. The effluent was immediately swept/sucked from the sample chamber into the heated exit tube where it was subsequently trapped using liquid nitrogen (LN2). Quenching and condensation of volatiles on the sample chamber walls or glass window was minimal due to the close proximity of the heated exit tube to the targeted area. Upon release from LN2, the effluent was analysed on-line using gas

96

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n-C2s) which displayed a strong odd-carbon dominance. Collectively considering (1) the similar distribution and prominence of long-chain n-alkanes in the conventional solvent extract (n-alkenes are absent of course, Fig. 4); (2) the lack of a strong

odd-carbon dominance in the extracted coal's pyrolysate (Fig. 3d); and (3) the predominance of n-alkane over n-alkenes released from the telite and resinoclarite (Fig. 3a and c), suggests the telite and resinoclarite contain a significant amount of 'unbound' or extractable n-alkanes. This proposal is further supported by the similarity of the distribution of n-alkenes for all three microlithotype. That is to say that the pyrolysis of the different microlithotypes seems to have produced similar n-alkene distributions and that the differences among the n-aliphatic distributions lie primarily with n-alkane (some of which are produced on pyrolysis and some of which are present in the microlithotypes, especially the telite and resinoctarite, as unbound, or perhaps physically trapped, hydrocarbons or bitumen). Thus, it is clear that the 'unbound' long chain n-aliphatics (such as occur in the solvent extract; Fig. 4) are not evenly distributed in microlithotypes only a few millimetres apart. Long-chain n-hydrocarbons with an oddcarbon dominance are presumably generated from terrestrial plant waxes such as occur in plant cuticles (Nip et al. 1986; Tissot & Welte

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33

35

COAL MICROLITHOTYPE HETEROGENEITY 1984). Long-chain n-hydrocarbons are also thought to be preferentially generated in coals relatively early in bituminization/catagenesis (Clayton et al. 1991). Surprisingly, the liptoclarite (which contained the most 'waxy' macerals; Fig. lb) yielded the least (relative) long-chain n-aliphatics and displayed no odd-carbon dominance. Their relative abundance in the liptinite-free (ligno-cellulose-derived) telite (Fig. la) implies, if one considers 'waxy' macerals (e.g. cutinite and cutinite-derived liptodetrinite) as the primary progenitors to these long-chain n-aliphatics, that these hydrocarbons are not indigenous, i.e. they must have migrated into the telite (perhaps, from the adjacent litoclarite; see below). The results shown in Fig. 3 indicate that the telite, in spite of its huminitic composition and ligno-cellulosic origin, is hydrogen rich (i.e. a perhydrous vitrinite, vitrinite B, or desmocollinite precursor). While the textinite and ulminite comprising the telite did not initially fluoresce when irradiated with uv light, they did exhibit a positive fluorescence alteration to reveal an orange-brown fluorescence after prolonged uv exposure. This fact tends to confirm the hydrogen-rich character of the telite (Teichmuller & Wolf 1977). Horsfield et al. (1988) and Thompson et al. (1985) also observed fluorescing vitrinites in other Tertiary coals from Indonesia. Such vitrinites may form during the original deposition due to incorporation of sub-microscopic liptinites (which invoke the fluorescence; Taylor 1966). While I cannot dismiss the occurrence of an indigenous fluorescing material being present, the results above indicate that hydrogen-rich vitrinites (desmocollinites) might also form during early bituminization/ catagenesis when they become impregnated with migrated fluorescing materials generated from nearby liptinites (rather than due to an original presence of distinct, sub-microscopic liptinites). Admittedly, it is unlikely that the fluorescence of the telite macerals is due to the n-hydrocarbons (which should not fluoresce due to a lack of conjugated double bonds) described above. Rather, it is likely to be due to small aromatic molecules that must also be present in the migrated fraction. In any case, fluorescence microscopy is of considerable importance in better recognizing the hydrogen richness and oil proneness of vitrinite macerals (Teichmiiller & Wolf 1977). The relative abundance of n-alkenes (pyrolysis products) over n-alkanes in the liptoclarite suggests that (unlike in the telite and resinoclarite) relatively few 'unbound' n-alkanes

99

were present therein. However, as mentioned above, since the 'waxy' macerals in the liptoclarite are considered precursors of long-chain n-alkanes in oils (Tissot & Welte 1984), their relative lack (compared to n-alkenes) might suggest either (1) the n-alkanes were not yet generated or, (2) as was suggested above, they were generated and have migrated from the liptoclarite microlithotype. The first explanation seems unlikely considering (1) the abundance of extractable organic matter contained in the other microlithotypes; (2) the maturity (early bituminization/catagenesis) of the sample (VR = 0.61; Table 2); and (3) the occurrence of exsudatinite in some voids within the coal (see below). The second explanation, thus, seems most likely. Considering the aforementioned argument for the presence of allochthonous n-hydrocarbons in the telite and resinoclarite, primary migration out of the liptoclarite into the surrounding microlithotypes is indicated. The distributions and relative amounts of long-chain n-hydrocarbons, as compared to the macerals they are thought to be generated from, also would suggest that primary migration has occurred in this coal. In having established the migration of n-hydrocarbon between microlithotypes, one could speculate that the intimate physical association of the macerals in the liptoclarite (Fig. lb), i.e. liptodetrinite dispersed among humodetrinite (or small bits of oil-prone macerals among small bits of non-oil-prone macerals), may promote the primary migration process. That is to say that the physical association between macerals may be as important to oil expulsion from coals as the type of macerals is to oil generation in coals. Thus, generation and expulsion may be most effective in coals with a high proportion of liptoclarite-like microlithotypes (i.e. abundant liptinite particles among finely divided vitrinite macerals and minerals). These results support the contention by Mukhopadhyay (1989) and Mukhopadhyay et al. (1991) that liptodetrinite/humodetrinite associations would (not only have a sufficient oil proneness but also) have a greater porosity and permeability, and therefore greater explusion capacity, than other more massive macerals. While this association between expulsion and porosity/permeability would intuitively seem correct, it is probably the microporosity of the macerals present (and not the macroporosity) which has the greatest influence on oil expulsion. The results described above also support the intuitive discussion by Bertrand (1989) concerning the importance of coal microtexture on oil expulsion.

100

s . A . STOUT

Any discussion on oil expulsion in coals must include some mention of cleats, cracks and fissures, which would seemingly aid the primary migration and expulsion process (Saxby & Shibaoka 1986; Hvoslef et al. 1988). In this particular coal there were cracks present in each microlithotype. However, the role of the cracks in the primary migration process was not obvious since exsudatinite was only rarely observed. However, the occurrence of any exsudatinite in the coal is testimony to the fact that oil generation and mobilization has occurred within the coal (Stach et al. 1982). This lends further support to the conclusion that primary migration of n-hydrocarbons has occurred between microlithotypes. Since exsudatinite is essentially a polymerized residual oil (solid bitumen), the low concentration of exsudatinite may merely reflect the fact that hydrocarbons which once moved through these cracks and fissures (prior to uplift) have been lost or absorbed into the coal network. In this particular coal, certain macerals, presumably the more massive huminites (i.e. textinites and ulminites, which are the precursor to most vitrinites) in the adjacent telite and resinoclarite microlithotypes (Fig. 1) appear to have trapped n-hydrocarbons which were apparently generated in the liptoclarite. Such 'trapping' would make sense in light of: (1) the tremendous microporosity and absorption capacity which vitrinite precursors normally exhibit at this rank (Thomas & Damberger 1976); and (2) the progressive increase in n-alkane yields from vitrinites between the high volatile b and low volatile bituminous ranks (Allan & Douglas 1977). These phenomena seem to be related since it is currently thought that porosity is reduced through bituminization/ catagenesis as hydrocarbons displace water and fill pores within the vitrinite network (Levine 1991). Thus, while rank and the amount of oil generated relative to the absorptive capacity/ microporosity of the coal are intimately related, oil expulsion from humic coals dominated by massive vitrite-type lithotypes (and only minor liptoclarite-type lithotypes) is probably retarded. This would further support the contention that absorptive sites within humic coals must first become 'saturated' or 'de-activated' before hydrocarbons can be expelled freely (Durand et al. 1987; Horsfield et al. 1988). This particular sub-bituminous, liptinite-rich humic coal, while having initiated generation and primary migration of hydrocarbons, has probably not yet been able to expel beyond the seam due to the high absorptive capacity of the massive huminite macerals (textinite, ulminite,

gelinite) which make up 68% of the coal (Table 2). The unusual abundance of n-Cll_a3 released from the resinoclarite microlithotype (Fig. lc) is interesting and currently unexplained. However, it may be due to a contribution to the rn/z 57 mass chromatogram from other co-eluting compounds (alkyl-naphthalenes?) in this region. Distributions o f acyclic isoprenoids

Figure 5 shows the relative distributions (m/z 113 mass chromatograms) of acyclic isoprenoids released during irradiation of the three microlithotypes. Each produced a series of C15, C16, C18, Ca9 (pristane = Pr) and C2o (phytane = Ph) acyclic isoprenoids (Fig. 5). The Pr/Ph and Pr/ n-C~7 ratios (as calculated from the m/z 113 mass chromatograms) for the three microlithotypes reveal differences in the relative distributions of isoprenoids over only a few millimetres distance. Since Pr/Ph and Pr/n-fa7 ratios are typically calculated from the FID response for solvent extracts, the ratios reported herein are only comparable internally. Nonetheless, the high Pr/Ph ratios distinguish the telite (13.4) and resinoclarite (13.2) from the liptoclarite (5.0). Indonesian non-marine oils usually have Pr/Ph ratios above 5.0 which would be in accordance to those ratios observed herein. The Pr/n-C17 ratios show that the telite (3.7) and resinoclarite (8.2) released more (relative) acyclic isoprenoids than n-alkanes while the opposite was true for the liptoclarite (0.5). Since isoprenoids are generated relatively early in catagenesis (Van Graas et al. 1981), this difference could further indicate that hydrocarbons generated in the liptinite-rich litoclarite have migrated into the surrounding microlithotypes. The insets to Fig. 5 show the m/z 57 mass chromatogram in the vicinity of n-C17_18.As can be seen, the isoprenoid pyrolysis products, prist1-ene and prist-2-ene, were also produced from each microlithotype in similar proportions (i.e. prist-l-ene>>>prist-2-ene). Prist-2-ene is thought to form from the mineral-catalyzed isomerisation of prist-l-ene (Regtop et al. 1986), therefore these compounds are thought to have the same precursor(s). The calculated pristane formation indices (PFI; after Goosens et al. 1988) indicate that the liptoclarite produced a greater proportion of pristene(s), as compared to pristane, than the other microlithotypes. This suggests that a greater proportion of pristane precursor(s) still exist bound to macerals in the liptoclarite than in the telite or resinoclarite. Assuming that all pristane derives from such a precursor(s), the greater relative concentration

101

COAL MICROLITHOTYPE HETEROGENEITY 100 Pr/Ph

Pr

13.4

Pr/nC17

a) TELITE

3.7

looI Lr PFI = 0.90

100

5.0

Pr/Ph

b) LIPTOCLARITE

Pr/nC17 0.5 100~

I-Z LU

Pr

0

IZ LU

18

16

•

1 IrPr-, I

15

PFi = 0 . 3 9

~.~ 100

13.2

Pr/Ph

Pr/nC17

Pr

8.2

C) R E S I N O C L A R I T E

1001

1Pr

16 PFI = 0 . 8 6

TIME

Fig. 5. M/z 113 partial mass chromatograms showing the relative distributions of acyclic isoprenoids released from (a) telite, (b) liptoclarite, and (c) resinoclarite during laser irradiation. Insets show distribution of pristenes determined from m/z 57 mass chromatograms for the same samples. PFI = pristane formation index (see text).

of pristane (over pristene) in the telite and resinoclarite could further indicate that pristane generated in the liptoclarite has also migrated into these surrounding microlithotypes. Thus, these results support those previously described for the n-hydrocarbons. Current views indicate that many isoprenoids, including the pyrolysis pristenes, form from tocopherols (Goosens et al. 1984). Since the difference in relative yields of pristenes cannot be due to differences in thermal maturity, the

fact that there seems to be a greater relative amount of pristenes released from the liptoclarite may indicate a relative abundance of these precursor compounds occurring in or among the liptodetrinite/humodetrinite macerals dominating this microlithotype (Fig. lb). The utility of various isoprenoid ratios and isoprenoid/n-aliphatic ratios to imply the degree of thermal maturation (Van Graas et al. 1981; Curry & Simpler 1988; Goosens et al. 1988)

102

S.A. STOUT 29

would seem to be in question considering the variability observed over a distance of only a few millimetres. Instead the differences observed among these microlithotypes could suggest that (1) the pristane precursor(s) is distributed unequally among the macerals and/or (2) the migration of isoprenoids (specifically, pristane) may accompany that of n-aliphatics (e.g. from the liptoclarite into the other microlithotypes, see above).

a) TELITE

27

3O

ttlz~

I II~°'°~ '

,,

~

'

Distributions of pentacyclic triterpenoids Figure 6 shows the distribution of pentacyclic triterpenoids (via m/z 191) for the microlithotypes studied. These traces represent a mixture of the 'unbound' (or physically-trapped) hopanoids along with hopanoids cleaved from maceral polymers during pyrolysis. Figure 7 shows the distribution (via m/z 191) of solvent extractable hopanoids for the blended microlithotypes. Each trace is dominated by the 17~(H), 21fl(H)30- norhopane (C29) and 17a(H)-22,29,30-trisnorhopane (C27; Figs 6 and 7). The relative distribution of these and the 17a(H),21fl(H) hopane (C3o) are shown in the ternary inset to Fig. 7. The inset shows a slight enrichment of hopane in the solvent extract but an overall similarity among the C27,29,30hopane distributions. Similarly, the distribution of the C3o+ hopanes and moretanes in the telite (Fig. 6a), liptoclarite (Fig. 6b), and the solvent extract (Fig. 7) are comparable. Relatively few hopanoids were released from the resinoclarite as indicated by the poor signal to noise ratio (Fig. 6c). There were six unidentified hopenes (one C27, two C29, two C3o, and one C31) recognized in the telite and liptoclarite traces that were absent in the solvent extract (Fig. 6a, b and Fig. 7). These hopenes are considered to be pyrolysates cleaved from macerals within the telite and liptoclarite. The relatively large C27 hopene has been recognized previously in conventional flash pyrolysates of kerogens (Seifert 1978; Larter 1978; Philp & Gilbert 1984; Van Graas 1986; Li & Johns 1990a) and its yield, relative to the 17a(H) trisnorhopane (17a(H)C27 hopane/ hopene ratio), has been reported to decrease with maturity (Philp & Gilbert 1984, 1985; Van Graas 1986). In this case, the ratios are comparable and when compared to previous studies, the low 17ot(H)C27 hopane/hopene ratios for the telite (1.57) and liptoclarite (1.75) testify to the relatively low maturity of the sample (Table 2). The slight variation among the telite and liptoclarite ratios is probably negligible.

. .-..i........i....,-w-.-i-.

r¸ ,-w ''''w'r''r'r '-- I ........W"' 29 I

" "'11 .¸ ¸1¸¸¸''¸¸¸¸=¸ --' "1 b) LIPTOCLARITE

27

3O r-----n 3 i11/ 1 1

29 100 -

'

r i

1 r 32 1

C) RESINOCLARITE '

27 30

0 ~I,IZ~TIII~T11.],, i rzz,zzzzlz. ,,,, z~T1r~rrrr~.` izzzllzzzzlzzz.l,,,,, ,. ~ .Tl,Z,~1],,,llzzzzl,zzT~1..z~zll,llll.l,,` j "1 l'llll''lz''r' 'Irl

TIME

Fig. 6. M/z 191 partial mass chromatograms showing the relative distributions of pentacyclic triterpenoids released from (a) telite, (b) liptoclarite, and (c) resinoclarite during laser irradiation. Numbers correspond to carbon numbers. Shaded peaks are unidentified hopenes.

Although it has been suggested that hopanoid precursors are likely to be bound to coal macerals via functional groups on the side chain (Li & Johns 1990b), additional work is needed

COAL MICROLITHOTYPE HETEROGENEITY KEY 100

27 '

A - TELITE

f 1T~

103

29

~

B - LIPTOCLARITE

30

C - RESINOCLARITE D - SOLVENT

!

EXTRACT

27

31

r~

s+

29

30

I

I

i

i

39:00

42:00

45:00

48:00

51 ':00

54100

i

i

57:00

1:00:00

TIME

Fig. 7. M/z 191 partial mass chromatogram of the solvent extract of the microlithotype mixture. Inset shows relative distributions of C27, C29, and C30 17a(H),21fl(H) hopanes.

to recognize the position of the double bond for the hopenes shown here. The fact that significant m / z 191 ions are produced suggests the double bond is somewhere on the right side of the molecule (rings C, D, or E). Furthermore, the prominent yield of C27 hopene (over other hopenes; Fig. 6a, b) would seem to suggest a complete loss of the side chain during cleavage from a maceral. Previous workers have used hopanoid ratios (e.g. C22 epimer ratios of the C31_33 hopanes, moretane/hopane ratios, and the presence/ absence of 17fl(H),21/~(H) hopanes) from the conventional pyrolysis of kerogens to imply thermal maturity (Seifert 1978; Seifert & Moldowan 1980; Philp & Gilbert 1984). The 22R/(22R + 22S) homohopane ratios for the telite, liptoclarite and solvent extract are 0.43, 0.42, and 0.40 respectively. This and other ratios testify to the equitable and early catagenesis rank of the coal. Furthermore, these molecular maturity parameters appear to be consistent over very small distances. However, some maturity parameters, for example Ts/Tm, vary considerably between the solvent extract (45.0) and the laser extract/ pyrolysate (5.1-telite and 7.7-1iptoclarite). This particular discrepancy is due to the near absence of 18a(H) trisnorhopane in the solvent extract as compared to the laser extracts/pyrolysates.

The cause for this marked difference is unknown. Since the hopanoids discussed above are derived from prokaryotic bacteria (Mycke et al. 1987) their clear presence in the telite and liptoclarite suggests that: (1) bacteria made direct contributions during the accumulation of the maceral precursors in each microlithotype and/ or (2) hopanoid hydrocarbons migrated into these microlithotypes. Discussions above have suggested that primary migration from the liptoclarite to the other microlithotypes has occurred. However, the relative lack of hopanoids in the resinoclarite (Fig. 6c) would seem to indicate that the former is more likely. After all, if migration of hopanoids accompanied the migration of n-aliphatic and isoprenoids one would expect them to be relatively enriched in the resinoclarite (and depleted in the liptoclarite). Why then are hopanoids depleted in the resinoclarite? One possibility is that bacterial activity was greater in the telite and liptoclarite precursor sediments than it was in the resinoclarite precursor. The fact that plant resins (such as formed the resinite in this microlithotype; Fig. lc) often display bactericidal properties (Sj6strom 1981) would tend to support this contention. This interesting observation requires further investigation. No oleanoids were observed in the mass

104

s . A . STOUT

chromatograms studied. This might be considered unusual in light of the generally high contribution of angiosperms in Tertiary basins. However, gymnosperm vegetation (e.g. Araucaria) may have dominated the coal facies studied.

Other biomarkers None of the microlithotypes yielded discernible quantities of steranes (as detected by m/z 217, 218, 231,253 mass chromatograms). However, steranes were present in small concentration in the solvent extract. Detection of the small concentration of steranes following laser irradiation may be due to the limited dynamic range of the mass spectrometer used in the experiments. However, a similar discrepancy was observed by other workers (Seifert 1978; Van Graas 1986). Van Graas (1986) suggested that sterane precursors may 'degrade' upon cleavage and produce fragments other than rn/z 217. That is, the lack of steranes in the laser extract/ pyrolysate may be due to the mechanism by which steranes are released from macerals and not by their absence. Alternatively, the absence of steranes in the pyrolysate could simply suggest that their precursors were not incorporated into the macerals irradiated. Other products of interest include the similar yield of a series of Cls diaromatic sesquiterpenoids from each microlithotype (e.g. rn/z 198 and 183; not shown). These compounds were dominated by cadalene which was a significant product of each microlithotype. Similarly, a series of resin-derived C~4_16 bicyclic sesquiterpenoids was produced from each microlithotype (m/z 109 and 123). Sesquiterpenoids are reported to be contained in angiosperm fossil resins (Grantham & Douglas 1980), thus their association with the resinite-bearing resinoclarite and liptoclarite microlithotypes (Fig. lb, c) is not unexpected. The presence of these compounds in the resinitebarren telite (Fig. la) could indicate a migration of these compounds and/or that the lignocellulosic tissues which formed the telite originally contained microscopicallyunrecognized resinous material.

Conclusions The complexity of hydrocarbon distributions within coals is only beginning to be understood. While the results from the novel laserbased extraction/pyrolysis technique described herein are only qualitative, the technique provides, for the first time, a geochemical finger-

print of the hydrocarbons generated from, or contained within, microscopically identified maceral associations in situ. This technique can be applied to conventional petroleum source rocks in the same manner and with refinement may be applied to single, selected coal macerals (and shale phytoclasts). This study has shown that the distribution of hydrocarbons in an autochthonous liptinite-rich humic coal varies on a very fine scale (millimetres). The variability between microlithotypes was not due to variable maturity but instead to heterogeneity in the inherent chemistry of the macerals comprising the microlithotypes and the presence/absence of migrated hydrocarbons. The results support the occurrence of primary migration of bitumen between microlithotypes. Specifically, the relative depletion of long-chain n-alkanes and isoprenoids in the liptinite-rich (mostly cutinitederived liptodetrinite in an attrinite matrix) liptoclarite and their relative abundance in the overlying telite (textinite/ulminite) and underlying resinoclarite (ulminite/resinite) suggests that normal and isoprenoid hydrocarbons generated in the liptoclarite have migrated into the adjacent microlithotypes. It is suggested that the intimate physical association of oil-prone, hydrogen-rich macerals (such as liptodetrinite) among fine-grained humodetrinite macerals (e.g. attrinite) will favour both oil generation and primary migration in coals. Thus, while the type of macerals present may dictate the potential to generate oil, the physical association between macerals (i.e. the microlithotypes present or microtexture of the coal) will play an important role in the potential for oil to migrate within, and ultimately expel from, coal. The absorptive capacity and microporosity (which generally decreases with rank) of some huminitic/vitrinitic macerals will also influence the efficiency of the primary migration and expulsion process in coals. Expulsion of oil from liptinite-rich (c. 10-30%) humic coals would seem to be favoured in liptodetrinite/humodetrinite-rich coals (i.e. coals with a high proportion of microlithotypes of a detrital origin) rather than in coals where the liptinites are encased within or bounded by more massive forms of huminites/vitrinites. Thus, in addition to conventional maceral analysis, any source rock assessment on coals could probably benefit from some form of microlithotype analysis. With the exception of several hopenes that are present in the laser extract/pyrolysate, the hopanoid biomarker distributions in each microlithotype are similar to that of the solvent extract from the whole coal. This probably indicates

COAL MICROLITHOTYPE H E T E R O G E N E I T Y

that microbial flora originally present during peat accumulation were generally similar. The relatively low abundance of bacterial hopanoids in the resinite-rich microlithotype could be due to the resin's antibiotic capacity. Using the novel laser-based thermal extraction/pyrolysis technique direct comparison between petrographic maturity parameters (e.g. VR) and molecular maturity parameters can be made on a single, very small sample. Future studies should improve our understanding of the following: (1) primary migration processes in all types of oil source rocks; (2) maturation versus source controls on hydrocarbon and non-hydrocarbon composition; (3) chemical variability a n d source potential a m o n g p e t r o g r a p h i c a l l y similar m a c e r a l s in

105

coals (e.g. different vitrinite types) a n d m o r e c o n v e n t i o n a l source rocks (e.g. amorphous kerogen). W i t h the c u r r e n t apparatus, c o m p o u n d s that occur as ' u n b o u n d ' or free b i t u m e n , physically t r a p p e d within the coal n e t w o r k , and released by t h e r m a l b o n d cleavage during pyrolysis are analysed collectively. F u t u r e configurations will a t t e m p t to regulate the release of these materials so that they m i g h t be analysed in series, i.e. t h e r m a l extraction followed by pyrolysis. The author would like to thank Dr Richard Armin (UNOCAL) for collecting and supplying the sample, Drs John R. Fox, Rui Lin, Joe Curiale and Jeffrey R. Levine for helpful discussions and comments, UNOCAL management for permission to publish, and Dr Andrew C. Scott for his editorial handling of the manuscript.

References ALLAN, J. & DOUGLAS, A. G. 1977. Variations in the content and distribution of n-alkanes in a series of Carboniferous vitrinites and sporinites of bituminous rank. Geochimica et Cosmochimica Acta, 41, 1223-1230. BERTRAND, P. R. 1989. Microfacies and petroleum properties of coals as revealed by a study of North Sea Jurassic coals. International Journal of Coal Geology, 13,575-595. CLAYTON, J. L., RICE, D. D. • MICHAEL,G. E. 1991. Oil-generating coals of the San Juan Basin, New Mexico and Colorado, USA. Organic Geochemistry, 17, 735-742. CURIALE,J. A. 1991. Molecular maturity parameters within a single oil family - A case study from the Sverdrup Basin, Artic Canada. In: MOLDOWAN, J. M., ALBRACHT, P. & PHILP, R. P. (eds) Biological Markers in Sediments and Petroleum. Prentice-Hall, London, 295-300. CURRY,D. J. & SIMPLER,T. K. 1988. Isoprenoid constituents in kerogens as a function of depositional environment and catagenesis. Organic Geochemistry, 13,995-1001. DURAND,B., Hvc, A. V. & OUDIN,J. L. 1987. Oil saturation and primary migration: Observations in shales and coals from the Kerbau wells, Mahakam delta, Indonesia. In: DOLIGEZ, B. (ed.) 2nd IFP Research Conference on Exploration: Migration of Hydrocarbons in Sedimentary Basins, Carcans Maubuisson, 173-195. & PARATTE, M. 1983. Oil potential of coals: A geochemical approach. In: BROOKS,J. (ed.) Petroleum Geochemistry and Exploration of Europe. Blackwell, Boston, 255-265. GOOSENS, H., DE LEEUW, J. W., SCHENCK,P. A. & BRASSELL, S. C. 1984. Tocopherols as likely precursors of pristane in ancient sediments. Nature, 312, 440-442. -

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index, a new molecular maturity parameter. A simple method to assess maturity by pyrolysis/ evaporation-gas chromatography of unextracted samples. Geochimica et Cosmochimica Acta, 52, 1189-1193. GRANTHAM, P. J. & DOUGLAS,A. G. 1980. The nature and origin of sesquiterpenoids in some Tertiary fossil resins. Geochimica et Cosmochimica Acta, 44, 1801-1810. HORSFIELD,B., YORDY, K. L. & CRELLING,J. C. 1988. Determining the petroleum-generating potential of coal using organic geochemistry and organic petrology. Organic Geochemistry, 13, 121-129. Hvc, A. Y., DURAND, B., ROUCACHET, J., VANDERBROUKE,M. t~; PITTION,J. L. 1986. Comparison of three series of organic matter of continental origin. Organic Geochemistry, 10, 65-72. HUNT, J. M. 1991. Generation of gas and oil from coal and other terrestrial organic matter. Organic Geochemistry, 17,673-680. HVOSLEF, S., LARTER, S. R. & LEYTHAEUSER,D. 1988. Aspects of generation and migration of hydrocarbons from coal-bearing strata of the Hitra Fm., Haltenbanken area, offshore Norway. Organic Geochemistry, 13,525-536. INTERNATIONALCOMMITTEEOF COAL PETROLOGY1973. International Handbook of Coal Petrology. Centre National de la Recherche Scientifique, Pads. JONES, R. W. 1987. Organic facies. In: BROOKS, J. & WELTE, D. (eds) Advances in Petroleum Geochemistry. Vol. 2. Academic Press, New York, 5. LANDAIS, P. & MONTHIOUX, M. 1988. Closed system pyrolysis: An efficient technique for simulating natural coal maturation. Fuel Processing Technology, 20, 123-132. LARTER,S. R. 1978. A geochemical study of kerogen

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and related materials. PhD thesis, University of Newcastle-upon-Tyne. LEVINE, J. R. 1991. The impact of oil formed during coalification on coal bed reservoir systems.

Proceedings of the 1991 Coalbed Methane Symposium. University of Alabama, Tuscaloosa, Alabama, 1-9. LI, M. & JOHNS, R. B. 1990a. Thermal desorption as an analytical technique in biomarker analysis of immature coals. Journal Analytical Applied Pyrolysis, 18, 41-58. - - & -1990b. Kerogen extract interrelationships of terpenoid biomarkers from a Jilin brown coal. Organic Geochemistry, 15, 109-121. MUKHOPADHYAY,P. K. 1989. Organic petrography and organic geochemistry of Texas Tertiary coals in relation to depositional environment and hydrocarbon generation. Bureau of Economic

--,

Geology, University of Texas, Austin Report of Investigation, 188. HATCHER,P. G. • CALDER,J. H. 1991. Hydro-

carbon generation from deltaic and intermontane fluviodeltaic coal and coaly shale from the Tertiary of Texas and Carboniferous of Nova Scotia. Organic Geochemistry, 17, 765-783. MYCKE, B., NARJES, F. & MICHAELIS, W. 1987. Bacteriohopanetetrol from chemical degradation of kerogen. Nature, 326, 179-181. NIP, M., TEGELAAR, E. W., BFINKUS, H., DE LEEUW, J. W., SCHENCK,P. A. & HOLLOWAY, P. J. 1986. Analysis of modern and fossil plant cuticles by Curie-point Py-GC and Py-GC,MS: Recognition of a new, highly aliphatic and resistant biopolymer. Organic Geochemistry, 10, 76%778. PHILP, R. P. & GILBERT, T. D. 1984. Characterization of petroleum source rocks and shales by Py-GC-MS multiple ion detection. Organic Geochemistry, 6,489-501. & - 1985. Source rock and asphaltene biomarker characterization by Py-GC-MS multiple ion detection. Geochimica et Cosmochimica Acta, 49, 1421-1432. REGTOP, R. A., CRISP, P. T., ELLIS, J. & FOOKES, C. J. R. 1986. 1-Pristene as a precursor for 2-pristene in pyrolysates of oil shale from Condor, Australia. Organic Geochemistry, 9,233-236. SAXBY, J. D. & SHIBAOKA,M. 1986. Coal and coal macerals as source rocks for oil and gas. Applied Geochemistry, 1, 25-36. SEIFERT,W. K. 1978. Steranes and terpanes in kerogen pyrolysis of correlation of oils and source rocks.

--

& MOLDOWAN,J. M. 1980. The effect of thermal stress on source rock quality as measured by hopane stereochemistry. In: DOUGLAS, A. G. & MAXWELL, J. R. (eds) Advances in Organic Geochemistry. Pergamon Press, Oxford, 591-596. SJOSTROM, E. 1981. Wood Chemistry, Fundamentals and Applications. Academic Press, New York. STACH, E., MACKOWSKY, M.-Th., TEICHMULLER,M., TAYLOR, G. H., CHANDRA,D. & TEICHMULLER, R. 1982. Stach's Textbook of Coal Petrology (3rd ed.) Gebruder Borntraeger, Berlin. STOUT, S. A. 1991. Principal components analysis of quantitative pyrolysis-gas chromatography and organic petrolgraphic data of kerogens. Journal of Analytical and Applied Pyrolysis, 18, 277-292. -& HALL, K. 1991. Laser pyrolysis-gas chromatography/mass spectrometry of two synthetic organic polymers. Journal of Analytical and Applied Pyrolysis, 21,195-205. TAYLOR, G. H. 1966. The electron microscopy of vitrinites. Coal Science, Advanced Chemistry Series, 5 5 . American Chemical Society Publishers, Washington, D.C., 274-283. TEICHMULLER, M. & WOLF, M. 1977. Application of fluorecence microscopy in coal petrology and oil exploration. Journal of Microscopy, 109, 49-73. THOMAS, J. Jr. & DAMBERGER, H. H. 1976. Internal surface area, moisture content and porosity of Illinois coals: Variations with coal rank. Illinois State Geological Survey, Circular, 493. THOMPSON, S., COOPER, B., MORLEY, R. J. & BARNARD, P. C. 1985. Oil-generating coals. In: THOMAS, B. M. et al. (eds) Exploration of the Norwegian Shelf. Graham & Trotman, London, 59-73. TISSOT, B. P. & WELTE, D. H. 1984. Geochemical fossils and their significance in petroleum exploration. In: TISSOT, B. P. & WELTE, D. H. (eds) Petroleum Formation and Occurrence (2nd edn). Springer-Verlag, Berlin, 93-130. VAN GRAAS, G. 1986. Biomarker distributions in asphaltenes and kerogens analyzed by flash Py-GC-MS. Organic Geochemistry, 10, 1127-1135. --, DE LEEUW, J. W., SCHENCK, P. A. & HAVERKAMP, J. 1981. Kerogen in Toarcian shales of the Paris Basin. A study of its maturation by flash pyrolysis techniques. Geochimica et Cosmochimica Acta, 45, 2465-2474.

C o a l - b e a r i n g s t r a t a as s o u r c e r o c k s - a g l o b a l o v e r v i e w DUNCAN

S. M A C G R E G O R

BP Exploration Operating Company, 4/5 Long Walk, Stockley Park, Uxbridge, UK Abstract: Compilation of a global source rock database has shown that coal-bearing sequences are significant oil generators only in very specific and relatively uncommon geological settings. Coals and associated carbonaceous shales are thought to be the primary oil-prone source facies in Australasia and an important secondary source facies in Southeast Asia. In other regions of the world, there is, however, no evidence that they have expelled major quantities of oil. In terms of their contribution to the world's petroleum reserves, coal measures are the origin of relatively minor proportions of oil, but of significant amounts of gas. Coal sequences that are believed to have expelled significant amounts of liquid hydrocarbons seem to be restricted to two palaeoclimatic and palaeobotanical 'fairways'. 1. Tertiary angiosperm assemblages within 20° of the palaeo-equator. 2. Late Jurassic-Eocene gymnosperm assemblages formed on the Australian and associated plates. The reasons for this are not well understood. Multidisciplinary research work is recommended to compare these oil-prone coals with the much greater volumes of apparently gas-prone coals deposited outside these regions.

This paper summarizes the results of an analysis of coal measure source rocks performed on a database of the world's major source rocks. This database was compiled jointly by BP and SimonRobertson, as part of a project aimed at identifying and classifying the world's major productive source rocks. Only source beds deposited in coastal plain, delta top, or marginal lacustrine environments and containing discrete beds of coal are considered here. Source rocks deposited in open-marine environments containing significant amounts of reworked terrigenous kerogen (e.g. Beaufort-Mackenzie) are not covered by this paper. The database was compiled from a variety of sources. Published data, usually the most recent available on any basin, were compared with internal BP analyses to assess the likely origin of hydrocarbons in each basin. In most cases, a consensus was found to exist on the identity of the source rock, though this is less frequently the case in many coal-bearing basins. Where controversy was encountered, the internal BP view is usually preferred (e.g. Haltenbanken - Cohen & D u n n 1987). The accuracy of this study, therefore, relies in turn on the accuracy of the interpretations in the references listed at the end of the paper. The aims of this contribution are to take a wider view of coal measures as source rocks than is possible in most published papers, to outline empirical trends, and to put forward hypotheses for testing by more detailed research. Study on this scale has obvious limitations. Little can be

contributed to some of the more detailed and controversial questions pertaining to coal source rocks, e.g. the debate as to the relative oil contributions from coals and interbedded shales. These questions are not, therefore, addressed in this paper. The compilation covers source rocks that have been tied to at least 50 million barrels of recoverable oil or to at least 3 trillion cubic feet of gas reserves. A number of small d o c u m e n t e d examples of small oil reserves tied to coals are excluded on this basis (e.g. the Surat-Bowen Basin in Australia). Basins that m e e t the criteria are subdivided into those where the overwhelmingly predominant hydrocarbon phase is gas (Table 1), and those in which significant quantities of oil also occur (Table 2). These listings form the basis for the following discussions.

Oils tied to coal-bearing sequences The term 'oil-prone' will be used for convenience for those provinces listed in Table 1 although it should be noted that in many cases, the predominant phase in volumetric terms is gas. It can be seen from the table that the only coal-bearing sequences tied to major oil reserves lie either in Australasia or Southeast Asia. The Kutei and Gippsland Basins are the largest, most fully d o c u m e n t e d and least disputed cases of coal measures-sourced oil provinces. Largely because of the significance of the Gippsland province, some 80% of Australasian

From Scott, A. C. & Fleet, A. J. (eds), 1994, Coaland Coal-bearing Strata as Oil-prone Source Rocks? Geological Society Special Publication No. 77, pp. 107-116.

107

Location

Indonesia Indonesia Indonesia

India Malaysia

Indonesia

Indonesia Vietnam

Venezuela

Kutei NW Java S. Sumatra

Assam Luconia

E. Java

Tarakan Saigon

Maracaibo

Australia Australia China

China Bangladesh

Eromanga Cooper Junggar

Qaidam Surma

Possible (Secy) Possible

Probable Probable Possible (Secy)

Possible Probable

Possible

Probable Possible

Possible

Possible Probable

Probable Prob. (Mixed)* Prob. (Mixed)*

Probable

* Mixed sapropelic coal and lacustrine source.

Egypt New Zealand

W. Desert Taranaki

(b) Oil reserves 5 0 - 2 0 0 M M B O

Australia

Gippsland

(a) Oil reserves > 200 M M B O

Province

Status of interpreted source

Mid-Jurassic Late CretaceousEocene Late Jurassic Permian Early-MidJurassic Mid-Jurassic EoceneOligocene

Late CretaceousEocene Early Miocene Oiigocene OligoceneEarly Miocene Oligocene OligoceneEarly Miocene PalaeoceneEocene Oligocene OligoceneEarly Miocene Eocene

Source age

Table 1. Oil provinces tied to coal-bearing sequence source rocks

< 0.2? < 0.1

0.06 0.04 < 0.1

0.1 0.1

< 1

< 1 150°C). Yet, in contrast to Indonesia, and despite many years of exploration effort, there have been no significant oil discoveries in the Philippines other than those clearly tied to marine source rocks. Regional variations in the oil potential of coals again seems to be the likely explanation. The significance of these two examples is that they demonstrate differing behaviour of coals over relatively small geographical distances. The controls on coals as source rocks may therefore be operating at a variety of scales.

Oil- and gas-prone coals in space and time It has been established that coal-bearing sequences believed to have expelled gas are widespread, whereas those that have expelled oil are not. In order to understand this further, the source rocks listed on Tables 1 and 2 have been plotted on palaeogeographic/palaeotectonic reconstructions. The plate reconstructions used were from BP's 'GLOBE' system. Palaeolatitudes thus obtained are shown on Tables 1 and 2. Figure 1 plots the palaeolatitudes of the identified coal source rocks against the known stratigraphic distribution of coals according to McCabe (1984). It can be seen that gas-expelling coals occur over a wide range of palaeolatitudes, ages and continents. The peak of coal development, maintained throughout most of geological history at around 50°N, is represented by a

111

number of occurrences of gas-expelling coals in the former Soviet Union and in the North Sea. However, the occurrences of coal-bearing sequences tied to oil reserves are far more limited. Two main associations are defined: (a) a Tertiary tropical association, deposited in palaeolatitudes less than 20°. The group is dominated by SE Asian examples. However, there have also been suggestions that Tertiary dispersed terrestial organic matter interbedded with coals may be generating some small proportion of oil in Venezuela (Blaser & White 1984), suggesting the association is not purely confined to Southeast Asia. Coals deposited elsewhere in the tropics in Tertiary times are often thermally immature, and it is not known whether these would produce oil under suitable conditions. A trend towards gas proneness with increasing palaeolatitude is identified. The limits of this association may be marked by the apparent absence of any known oilexpelling coals in the Philippines, in basins which lay at palaeolatitudes around 20° throughout the Tertiary. It should be noted that even in lower palaeolatitudes, there are also many examples of predominantly gasexpelling coals (e.g. Luconia). (b) a late Jurassic-Eocene Australasian association, deposited in high pataeolatitudes (40-60°S) on the Australian and New Zealand Plates, and dominated by the Gippsland Basin. The other members of this association are the more marginal and relatively gas-prone source rocks of the Taranaki and Eromanga basins. Many authors have related the oil-prone nature of the Gippsland and other Australasian coals to the gymnosperm vegetation that existed exclusively in Australasia following its separation from Gondwanaland in the late Jurassic. Floral differences could conceivably explain why such high latitude coals are oil prone in the southern hemisphere, but have no northern hemisphere counterparts. Outside these associations, there are only a few cases of documented oil-prone coals tied to small oil reserves. These comprise Permian coals in the Cooper Basin and mid-Jurassic coals in parts of China and Egypt. In all these pre-Cretaceous examples, the coals concerned were deposited on lacustrine margins and may contain high contents of algal kerogen. Alternatively, it may be interbedded lacustrine shales that are the source rock.

112

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have given rise to many of the coals in the Tertiary sequences of this region (e.g. Thompson et al. 1985). Lacustrine systems have also developed (Katz & Mertani 1989) in more seasonal environments. Both act as oil source rocks (Cole 1987; Robinson 1987), and this is illustrated by the sediments of the South Sumatra and Northwest Java Basins (coaly source rocks active) and the intervening Sunda Sub-basin (lacustrine source rocks active). The location and generalized stratigraphy are presented in Fig. 1. In all three basins, coals of the Talang Akar Formation are frequently rich in fluorescent vitrinite and/or particulate 'liptinite' which is often not specifically identifiable in terms of source. This kerogen exhibits a high Hydrogen Index and (more characteristically) also a very low (1~

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OIL GENERATION FROM COALS AND COALY SEQUENCES Bowland Shales on the flanks of this high have good oil source quality (Fig. 8). It is to be noted that this source rock sequence has clearly been deposited in a marine environment rich in sulphate as evidenced by the iron sulphide present as framboidal pyrite produced by the extensive bacterial degradation of organic matter. The proposed model for transport and enrichment of the land-derived material into the distal marine environment (Fig. 9) involves reworking of plant material from the delta top mire into the marine environment, physical sorting and then flocculation or precipitation into deeper water prior to bacterial degradation and lipid enrichment in the basinal environment. Biomarker and isotope studies have confirmed the correlation between these source rocks and their land plant progenitors (Table 3) and the oils found often in Westphalian age reservoirs in the East Midlands and Lancashire Basins.

135

Comparison and discussion For the purposes of comparison, the carbon isotope ratio data for the oils which have been generated by the source rocks discussed in this paper, are presented in Fig. 10. Set against these data fields are printed the character and lithology of the generative source rocks. From the point of view of source type interpretation, these data appear to show a simpler distribution of carbon isotope ratios than that suggested by Sorer (1984). In addition, for these data and their interpretations the distribution appears to be age independent between Upper Carboniferous and Tertiary. However, different mechanisms for creating isotopically relatively heavy or light kerogens and oils variously involve mixing of kerogen end members, and environmental conditions. The source rock examples discussed in this paper demonstrate that particular types of coal and coaly sequences contain high proportions of

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136

S. THOMPSON ET AL.

h y d r o g e n - r i c h k e r o g e n s , and can g e n e r a t e oil. T h e recognition and prediction of the relevant k e r o g e n facies within coaly s e q u e n c e s can aid the p r e d i c t i o n of source rock o c c u r r e n c e . G i v e n , in addition, the different m e c h a n i s m s p r o p o s e d (but not p r o v e d ) for creating the h y d r o g e n - r i c h coals r e q u i r e d for oil sourcing,

it is a p p a r e n t that t h e r e is m u c h m o r e w o r k r e q u i r e d in the field of b i o g e o c h e m i s t r y b e f o r e the f o r m a t i o n and g e o c h e m i c a l c h a r a c t e r of oilg e n e r a t i n g coals is p r o p e r l y u n d e r s t o o d . The permission of the directors of Simon Petroleum Technology (Exploration Services) to publish this work is gratefully acknowledged.

R e f e r e n c e s

VANAARSSEN,B., HESSELS,J. K. C., ABBINK,O. A. & DE LEEUW, J. W. 1992. The occurrence of polycyclic sesqui, tri-, and oligoterpenoides derived from a resinous polymeric cadinene in crude oils from southeast Asia. Geochimica et Cosmochimica Acta, 56, 1231-1246. AWAD, G. M. 1984. Habitat of oil in Abu Gharadig and Faiyum Basins, Western Desert, Egypt. American Association of Petroleum Geologists Bulletin, 68, 564-573. BAGGE, M. HARDING, R., EL AZHARY, T. & SAID,M. 1988. Generation of oil from coal sequences in the Western Desert, Egypt. Proceedings of the Egyptian General Petroleum Corporation. 9th Exploration and Production Seminar, Cairo, November 1988. Egyptian General Petroleum Corporation, Cairo. BERTRAND, P. 1984. Geochemical and petrographic characterisation of humic coals as possible oil source rocks. Organic Geochemistry, 6, 481-488. BROOKS, P. W. 1986. Unusual biological marker geochemistry of oils and possible source rocks, offshore Beaufort-Mackenzie Delta, Canada. Organic Geochemistry, 10,401-406. BROWN, S. 1989. The 'mangrove model', can it be applied to hydrocarbon exploration in Indonesia? Proceedings of the 18th Annual Convention of the Indonesian Petroleum Association. Indonesian Petroleum Association, p. 385-401. BURNS, B. J., HOGARTH, J. T. C. & MILNER, C. W. D. 1975. Properties of Beaufort Basin Liquid Hydrocarbons. Bulletin of Canadian Petroleum Geology, 23,295-302. COLE, J. M. 1987. Some fresh/brackish water depositional environments in the SE Asian Tertiary with emphasis on coal bearing and lacustrine deposits and their source rock potential. Proceedings of the 16th Annual Convention of the Indonesian Petroleum Association, p. 429-449. Cox, H. C., DE LEEUW, J. W., SCHENCK,P. A., VAN KONONGSVELD, H., JANSEN, J. C., VAN DE GRAAF, B., VAN GEERESTEIN, V. J., KANTERS, J. A., KRUK, C. & JANS, A. W. S. 1986. Bicadinane, a C3o pentacyclic isoprenoid hydrocarbon found in crude oil. Nature, 319,316-318. CURIALE,J. A. 1991. The petroleum geochemistry of Canadian Beaufort Tertiary 'non-marine' oils. Chemical Geology, 93, 21-45. - & LIN, R. 1991. Tertiary deltaic and lacustrine organic facies: comparison of biomarker and

kerogen distributions. Organic Geochemistry, 17,785-803. DUCAZEAUX, J., LE TRAN, K. & NICOLAS, K. 1991. Brent Coal Typing by combined optical and geochemical studies. Bulletin Centre Recherche de Pau- Societe National de Petroliere Aquitaine. 15,369-381. DURAND, B. & PARArrE, M. 1983. Oil potential of coals: a geochemical approach. In: BROOKS, J. (ed.). Petroleum Geochemistry and Exploration of Europe, Blackwell, Oxford, 255-265. FRASER, A. J., NASH, D. R., STEELE, R. P. & EBDON, C. C. 1990. A regional of the intra-Carboniferous play of Northern England. In: BROOKS, J. (ed.) Classic Petroleum Provinces. Geological Society, London, Special Publication, 5, 417-440. GOLDBERG, M. & FRIEDMAN, G. M. 1974. Paleoenvironments and paleogeographic evolution of the Jurassic system in southern Israel. Geological Survey of lsrael Bulletin, 61. GRANTHAM, P. J., POSTHUMA, J. & BAAK, A. 1983. Triterpanes in a number of Far Eastern crude oils. In: BJOROY, M. et al. (eds.) Advances in Organic Geochemistry 1981. Wiley, Chichester, p. 675-683. HORSFIELD,B., YORDV, K. L. & CRELHNG, J. C. 1988. Determining the petroleum-generating potential of coal using organic geochemistry and organic petrology. Organic Geochemistry, 13, 121-129. HUNT, J. M. 1979. Petroleum geochemistry and geology. W. H. Freeman and Company, San Fransisco. - 1991. Generation of gas and oil from coal and other terrestrial organic matter. Organic Geochemistry, 17,673-680. KATZ, B. J. & MERTANI, B. 1989. Central S u m a t r a a geochemical paradox. Proceedings of the 18th Annual Convention of the Indonesian Petroleum Association. Indonesian Petroleum Association, p. 403-425. KHOLEIF,W., WORK, J. G. & SANAD,S. 1986. Meleiha: its history and its significance. Proceedings of the Egyptian General Petroleum Corporation, 8th Exploration Conference, Cairo, 1986. Egyptian General Petroleum Corporation, Cairo. LEEDER, M. R. (~zHARDMAN,M. 1990. Carboniferous geology of the Southern North Sea Basin and controls on hydrocarbon prospectivity. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publication, 55, 87-105.

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137

MAY, R. M. 1991. The Eastern Mediterranean Mesozoic Basin: Evolution and oil habitat.

ROBINSON, K. M. 1987. An overview of source rocks and oils in Indonesia. Proceedings ofl6th Annual

American Association of Petroleum Geologists Bulletin, 75, 1215-1232.

Convention of the Indonesian Petroleum Association. Indonesian Petroleum Association,

MoussA, S. 1986. Evolution of the sedimentary basins of the north Western Desert, Egypt. Proceedings

p. 97-122. ROE, G. D. & POLITO, L. J. 1979. Source rocks for oils in the Ardjuna sub-basin of the Northwest Java Basin, Indonesia. UN/ESCAP, CCOP Technical Publication, 6, 180-194, Bangkok. SOFER, Z. 1984. Stable carbon isotope compositions of crude oils: application to source deposition environments and petroleum alteration.

of the Egyptian General Petroleum Corporation, 8th Exploration Conference, Cairo, 1986. Egyptian General Petroleum Corporation, Cairo. MURCHISON, D. G. 1987. Recent advances in organic petrology and organic geochemistry: an overview with some reference to 'oil from coal'. In: SCOTT, A. C. (ed.) Coal and Coal-bearing Strata: Recent Advances. Geological Society, London, Special Publication, 32,257-303. NOBLE, R. A., ALEXANDER,R., KAGI, R. I. & KNOX, J. 1986. Identification of some diterpenoid hydrocarbons in petroleum. Organic Geochemistry, 10, 825-829. , Wu, C. H. & ATKINSON,C. D. 1991. Petroleum generation and migration from Talang Akar coals and shales offshore NW Java, Indonesia. Organic Geochemistry, 17, 363-374. PHILP, R. P. & GILBERT, T. D. 1986. Biomarker distributions in Australian oils predominantly derived from terrigenous source material. Organic Geochemistry, 10, 73-84. POWELL,J. G., BOREHAM,C. J., SMYTH,M., RUSSELL, N. & COOK, A. C. 1991. Petroleum source rock assessment in non-marine sequences: pyrolysis and petrographic analysis of Australian coals and carbonaceous shales. Organic Geochemistry, 17, 375-394. RIELEY, G., COLLIER, R. J., JONES, D. M. & EGLINGTON, G. 1991. The biogeochemistry of Ellesmere Lake UK-1; source correlation of leaf wax inputs to the sedimentary lipid record. Organic Geochemistry, 17,901-912. RISK, M. J. & RHODES,E. G. 1985. From Mangroves to petroleum precursors: an example from tropical northeast Australia. American Association of Petroleum Geologists Bulletin, 69, 1230-1240. ROBERTSON GROUP, 1987. The petroleum geochemistry

and geology of the Carboniferous of Northern England and adjacent areas. Non-proprietary commercial report. ROBERTSON RESEARCH, 1983. The petroleum geochemistry of Indonesian Basins. Non-proprietary commercial report.

American Association of Petroleum Geologists Bulletin, 68, 31-49. SuTToN, C. 1979. Depositional environments and their relation to chemical composition of Java Sea crude oils. UN/ESCAP, CCOP Technical Publication, 6, 163-179, Bangkok. TAHER, M., SAID,M. & EL-AZHARY,T. 1988. Organic Geochemical Study in Meleiha area, Western Desert, Egypt. Proceedings of Egyptian General

Petroleum Corporation, 9th Exploration and Production Seminar, Cairo, November 1988. Egyptian General Petroleum Corporation, Cairo. TEICHMOLLER, M. & DURAND, B. 1983. Fluorescence microscopical rank studies on liptinites and vitrinites in peat and coals and comparison with results of Rock-Eval pyrolysis. International Journal of Coal Geology, 2, 197-230. THOMAS, B. M. 1982. Land plant source rocks for oil and their significance in Australian basins.

Australian Petroleum Exploration Association Journal, 22,166-178. & BROWN, S. A. 1983. Hydrocarbon generation in the Northern Perth Basin, Australian Petroleum Exploration Association Journal, 23, 64-74. THOMPSON, S., COOPER, B. S., MORLEY, R. J. & BARNARD, P. C. 1985. Oil-generating coals. /n: THOMAS, B. M. e t al. (eds). Petroleum -

-

Geochemistry in Exploration of the Norwegian Shelf. Graham and Trotman, London, 59-74. TISSOT, B. P. & WELTE, D. H. 1978. Petroleum Formation and Occurrence. Springer-Verlag, Berlin. VELD, H. & FERMONT, W. J. J. 1990. The effect of marine transgression on vitrinite reflectance values. Mededelingen rijks geologische dienst, 45, 151-170.

A maturity and palaeoenvironmental assessment of condensates and oils from the North Sumatra Basin, Indonesia C. J. M A T C H E T T E - D O W N E S , 1, A . E. F A L L I C K , 2 K A R M A J A Y A & S. R O W L A N D 3

1

1LEMIGAS Research & Development Centre for Oil & Gas Technology Cipilur Kebayoran Lama, Jakarta, 10002 Indonesia (Present address: Geochem Group, Chester Street, Chester CH4 8RD, UK) 2SURRC, East Kilbride, Glasgow G75 OQU, UK 3petroleum & Environmental Geochemistry Group, Department of Environmental Sciences, University of Plymouth, Drake Circus, Plymouth PL4 8AA, UK Abstract: Five light oils and condensates from the wells drilled in Lower to Upper Miocene reservoir rocks of the North Sumatra Basin were analysed by gas chromatography-mass spectrometry and stable isotope ratio mass spectrometry. In conjunction with data from over 1600 well and outcrop samples the results were used to describe the character of the presumed source rocks in terms of organic matter maturity and palaeoenvironment of deposition. The source rock character was further constrained by the maturity of the drilled sections, geothermal gradient observations and re-evaluation of the geology of the region. Dominant lacustrine with subordinate ombrogenous raised peat bog palaeoenvironments of deposition are indicated. It is envisaged that raised mires fringed large lakes in the area. Tectonic disturbance probably caused periodic flooding of the swamps and ultimately a complete marine incursion occurred. The oils and condensates are mature to extremely mature. Some oils are mixtures of oils of different maturities and discrete terrestrial sources.

The P E R T A M I N A Unit 1 block of the North Sumatra Basin (NSB), Sumatra, Indonesia lies mainly onshore the east coast of Sumatra and is bounded by the Barisan Mountains to t h e w e s t and for the purposes of the present research, between Southern Aceh in the north and Bohorok in the south (Fig. 1). A general stratigraphic column (after Mulhadiono et al. 1978) is shown in Fig. 2. Rocks of Oligocene to Upper Pliocene age have been encountered in outcrop or in well sections; however, the immaturity of the Upper Miocene and younger rocks precludes these as potential sources for the reservoired oils and discussion herein is therefore confined to sediments of Baong Formation (Middle Miocene) age and older. The geological age of the source rocks described in this paper is thought to be Palaeocene or younger.

History of geochemical research P E R T A M I N A Unit 1, NSB, has proved to be a prolific petroliferous basin producing vast quantities of high maturity higher plant-derived condensates and high API gravity oils. The area has been explored for over a century yet no firm

consensus as to the source rocks for these oils has emerged. Modern day geochemical studies mostly post-date the research of Kingstone (1978) who identified the paralic coaly sediments of the Oligocene Bruksah Formation (equivalent to the Parapat Formation, Fig. 2) as viable source rocks, mainly based on lithological considerations. By contrast, Davies (1984) believed the restricted marine rocks of the Oligocene Bampo Formation to be the sources, with: the latter author als0 citing the Lower Baong Formation rocks aS contributors. These inferences were made on t h e basis of Total Organic Carbon (TOC) and pyrolysis data and the great thickness of the mudstones. Subsequently Situmeang & Davies (1986) stated that the oil window was located in t h e Middle to Lower Baong Formation. Their judgements were based largely o n Tma x data. T h e somewhat higher TOC concentrations of these strata compared to other contenders, were als0 used ~to argue for the Baong Formation as source rocks. Kjellgren & Sugiharto (1989) arguedfor sources in the Bampo, Lower Baong a n d Belumai formations. T h e conflicting nature of these studies prompted a detailed Study by L E M I G A S

From Scott, A. C. & Fleet, A. J. (eds), 1994, Coaland Coal-bearingStrataas Oil-prone SourceRocks? Geological Society Special Publication No. 77, pp. 139-148.

139

140

C. J. M A T C H E T T E - D O W N E S E T A L .

!

Muala ~/~ Barat-i

Scale

I0 Miles

Simpang

la la la ai

Sungai u h ~• Liput-i• Sungai

Bul

T a n j u n g Gentin, Pulau Rawa-

Susu

Dalam-2 Dalam-i Dalam-6 Buluh-1

-Pulau S e m b i l a n - i

Selatan-i

Besitang-i •

BRANDAN •

%

Telaga Said Tix Darat

Utara-IA

an~i Pakam Ti Pantai

Pakam- 1

~ai P~kam Timur~

Wampu-5

Batumandi-I

~

MEDAN

Selata~-I

A

P°l°nil- 1 Bohorok-

Tawang-I •

\ Fig. 1. Map of part of the North Sumatra Basin showing the position of the major wells.

and the British Geological Survey (BGS) who reviewed data for over 1500 potential source rock samples (TOC and Rock-Eval analysis) and concluded that the Baong Formation was the most likely source rock (Nicholson & Soekapradja 1990). Most recently Tambunan (1991) compared geochemical data for 69 potential source rocks with those from 8 oils and concluded that no source rock could be identified among the available samples. However, the

Belumai Formation was cited as the most likely originator of the oils. The controversies arising from these previous studies led to the present examination in which a detailed molecular and isotopic analysis of five representative oils was undertaken to obtain maturity and palaeoenvironmental information. This was combined with a a reappraisal of the existing geochemical database of bulk geochemical data for over 1500 well and outcrop

OILS FROM SUMATRA

141

Series Medan

Age

Aru

(Ma)

PLEIST.

Legend 1.7

volcanics

Julu

predominantly arenites

u.i 0.. t~ :3

'"

Keutapang

Fro.

U p p e r Shale Unit lA}

Z

iddle Baong L S a n ~ o n e Unit

LIJ ~J

carbonates

O

'" ._1

--

CI

dolomite

Upper Shale Unit (M)

Baong

-~_ ~ __&~---~-"&

predominantly rudites

Fm.

Lower Shale Unit (A)

Lower Shale~Middle Baong Sandstone Unit Unit (M) _J

~

Fm.

tw

---] predominantly argillites

~

Fro.

Seureula

5.1

~

Rayeu

B e l u ma i

25

Fro.

ampo

i

8

1

Fm

~

low grade metamorphics

~

hiatus

iJ.i (D O L0 J O

NOT DATED

.UY

Basedon Kamiliet and Mulhadionoet

basement'

aL (1976) al. (1978).

Fig. 2. Stratigraphy of North Sumatra Basin (after Mulhadiono et al. 1978).

samples. New well and outcrop data were also included, making a database of over 1600 samples. For a discussion of the broader geological tectonic setting readers are referred to Daly et al. (1991).

Sa m p l i n g and experimental p r o c e d u r e s Oil samples were collected from Lower and Upper Miocene reservoirs in Belumai Member and Keutapang Formation as indicated in Table 1. Samples were collected from the P E R T A M I N A Unit 1 core store in Pangkalen Brandan in October 1991 where they had been stored for 6 years. They were originally obtained in wells in 1985 as Drill Stem Test (DST) samples. Oils/condensates were separated into so-

called aliphatic and aromatic hydrocarbon fractions by now well-established and widely reported techniques (reviewed by Peters & Moldowan 1993). Briefly, oil was dried out into deactivated alumina and placed on a 1 : 3 alumina : silica column. Aliphatic hydrocarbons were eluted through the bed of alumina on silica with pentane whilst the aromatic fraction was first partially eluted with 9 0 : 1 0 pentane : dichloromethane then with 20 : 80 pentane : dichloromethane. The resulting fractions were examined by GC-MS on either a V G TRIO GCMS system (LEMIGAS) or a HP5890 (University of Plymouth) under conditions given in the figure legends. Carbon isotope analyses were performed at SURRC by combustion to CO: followed by MS. Results are reported as parts per thousand deviations from PDB standard (per mil).

C. J. MATCHE'I'TE-DOWNES ET AL.

142

Table 1. Sample details for oils from North Sumatra Basin Sample no.

Well

Depth (m)

NSB 1

Wampu-6

2342-2420

NSB2

Gabang-31

810-1048

NSB3 NSB4 NSB5

Pantai Pakam Timur-44 Telaga Said T-7 Securai-4

Not available 130-140 1790-1825

Formation Belumai Member Lower Miocene Keutapang Formation Upper Miocene Upper Miocene Upper Miocene Upper Miocene

metres U p p e r K e u t a p a n g Mbr. 3 0 m

Reservoirs

0

500 Keutapang

1.000 t o p B a o n g Fm. 1 2 2 4 m

1,500 drilling mud contamination from this depth 2,000 immature

:"default" s o u r c e

rock marine shales t o p B e l u m a i Mbr. 2 5 0 0 m

2,500 i • •

t o p B a m p o Fro. 2 9 1 0 m

oxidised vitrinite ?

3,000

Belumai

deepest well 3 1 5 0 m oil w i n d o w ?

3.500

k,jl 0.2

0.3

0.5

1

I

I

2

3

____t,* Vitrinite Reflectance Ro% ,

I

0 .....

,

I

2

,

I

4

w

6

I

z

8

10

TOC% {minimum threshold for source rock = 1%) ,

0

I

,

I

,

100 2 0 0

I

~

I

,

I

,

I

,

300 4 0 0 500 600 700

Hydrogen Index

P r o p o s e d source rock i n t e r v a l Ro 1 . 0 % +

f

D e p o c e n t r e b a s e m e n t 4 3 0 0 m 4-

Unconformity

Fig. 3, Summary of source rock data for a typical North Sumatra Basin sequence.

Unconformity

OILS FROM SUMATRA Results and discussion Before the molecular characteristics of the oil/ condensate samples are discussed, a brief summary of the possible reasons for the wide diversity of opinion regarding the possible source rocks of these oils is appropriate. Most of these features can be illustrated by reference to Fig. 3 which summarizes source rock data (TOC, Ro%, Hydrogen Index, HI) for a typical well in the study area. Firstly, and perhaps most importantly, as is typical in oil exploration all wells so far have been drilled on structural highs so that the 'kitchen' areas of source rocks on structurally low areas have never been encountered (cf. Telnaes & Cooper 1991). These lows are clearly visible from seismic and geophysical data (Matchette-Downes 1992). Thus, good samples of likely source rocks have probably never been obtained for geochemical characterization, leading to controversy in interpretation of data from immature source rocks. Secondly, the T O C contents of the Baong Formation are generally quite low (0.5-0.97% measured, but see below). Thus successive authors have invoked low minimum T O C thresholds for the region (as low as 0.3%). The vast thicknesses of the relatively lean shales that accumulated as a result of rapid down warping of the Sunda microplate during the Middle Miocene have been used to counter the argument that the Baong mudstones are too lean to be good source rocks (Davies 1984). Most good source rocks have TOC values of at least 1%. Thirdly, some authors may have ignored the fact that virtually all the cuttings samples and some cored material show signs of contamination with drilling fluids (Fig. 3). Some wells were drilled with diesel or other oil-based muds and yet others contained oil-based additives. This was normal practice in the 1980s in sections where overpressured and/or hygroscopic shales occurred. This contamination has probably

143

increased the measured T O C values which probably have an average concentration of nearer 0.5% (Matchette-Downes 1992). HI values suggest that some of the Middle and Lower Baong Formation could be source rocks but little optical geochemistry was used to assess the kerogen type. Such optical examination that has been made has revealed comminuted terrestrial material with, at best, a gas generation potential (Matchette-Downes 1992). The maturity of the sequence, as assessed by the generally accepted parameter of vitrinite reflectance, shows that the organic-rich shales with a sufficient HI value for oil generation are only barely mature (i.e. maximum c. 0.6% R0). In our view such early mature oil would not resemble the non-asphaltic light condensates found in the region.

Geochemical characteristics o f the oils The geochemical data for the five oils are shown in Table 2. All the samples for which data were available can be legitimately considered as condensates since they have API gravities of 47.0 to 55.2 (Table 2). They are low sulphur oils (0.020.03%), and gas chromatography (GC) was consistent with the high API values and revealed only minor proportions of >C25 alkanes. Indeed, the latter feature made the acquisition of GCMS biomarker data for palaeoenvironmental characterization rather more difficult than normal. Nonetheless, such data were obtained by selected ion monitoring of a limited number of ions.

Palaeoen vironment Biomarkers The oil from Timur 44 (NSB3) illustrates GC-MS biomarker features which are typical of all five oils.

Table 2. Summary of geochemical datafor oils Sample no.

API

Wt. % sulphur

613C sats

TNR

MPI

Rc %

NSB1 NSB2 NSB3 NSB4 NSB5

55.2 54.0 nd 48.5 47.0

0.02 0.03 nd nd 0.02

-21.7 - 23.1 - 22.8 - 22.4 -27.8

2.8 1.05 0.93 1.44 1.1

1.92 0.97 0.88 0.89 0.96

1.7 1.2 1.0 0.9 1.3

nd: not detected; API: American Petroleum Institute Gravity (degrees); TNR: trimethylnaphthalene ratio; MPI: methylphenanthrene index (for TNR and MPI see Radke 1987); Rc %: calculated vitrinite reflectance; 613C sats: 13C/~2Cisotope ratio of saturated hydrocarbons (per mil).

144

C. J. MATCHETTE-DOWNES E T AL.

The m / z 191 ion chromaogram (Fig. 4) is routinely used in petroleum geochemistry to illustrate the distribution of pentacyclic triterpanes (particularly hopanes) which are typically found in crude oils (e.g. Peters & Moldowan 1993). In marine oils, hopanes often dominate such profiles whereas a contribution of higher plant-derived organic matter is often revealed by significant proportions of other pentacyclics such as oleanane (e.g. Grantham et al. 1983). In oils from SE Asia and Bangladesh, polycyclic alkanes such as the bicadinanes are also often observed in the m / z 191 profile (e.g. Grantham et al. 1983; Alam & Pearson 1990; van Aarssen et al. 1990), though they are more clearly displayed by other ion chromatograms (e.g. m / z 369, 412). All of the above features (viz. oleanane, bicadinanes, hopanes) were observed in the NSB condensates, clearly suggesting an input of higher plantderived organic matter to the source rocks. The data show similarities to those obtained by others for condensates derived from Tertiary Talang Akar coaly sediments from Indonesia (e.g. Noble et al. 1991), and to oils sourced from the Ardjuna and Tertiary of offshore Sabah and Sarawak (Matchette-Downes 1992). The utility of the m / z 217 ion profiles, normally used to illustrate the distribution of steroidal alkanes (Peters & Moldowan 1993) is limited in the present samples because of the relatively large contributions of m / z 217 fragment ions of non-steroidal (e.g. triterpenoid)

alkanes. The high concentrations of these triterpenoids is consistent with the interpretations above. Also, the high maturity of the samples has probably reduced the relative contribution of C29 steranes compared with the lower C27 homologues, thus distorting the commonly used sterane carbon number distributions (cf. Mackenzie 1984). Interestingly the 6~3C data obtained for the aromatic and aliphatic fractions of the five condensates did not support the biomarker data. For instance, calculation of the Canonical Variable (CV) proposed by Sofer (1984) for the differentiation of higher plant and marine oils suggested that the NSB samples were of marine origin (CV - 5 . 5 0 to -1.26). However, we have observed that isotopically heavy oils from lacustrine environments also exhibit features which are more usually attributed to 'marine' oils. Examples are the lacustrine oils from the algal-rich Pematang Brown Shales of central Sumatra (Longley et al. 1990), and the Sunda oils of offshore North West Java (Pramono et al. 1990). Sorer (1984) also noted that some oils from Sumatra, Java and the Phillipines did not fit his general model well. Figure 5 shows the differentiation of known higher plant-derived oils and known lacustrine oils (Pramono et al. 1990) on the basis of a 7%0 difference in the 613C isotopic signature (Luo Binjie et al. 1988). Clearly four of the five condensates exhibit an isotopic signature which Stable isotopes

m/z 1 9 1

~bund . . . .

0

Time

.

.

.

.

~

32.0"0

,

,

,

341.00 . . . .

,

3 6 . 0I0 . . . .

3 8 . 0I0 . . . .

4 0 . 0l0 . . . .

4 2 . 0l0 . . . .

4 4 . 0~0 . . . .

4 6 .lO0

,

,

,

i

,

,

,

48.00

Fig. 4. GCMS ion chromatogram (rn/z 191) of NSB2. Positions of norhopane (1), oleanane (2) and hopane (3) are indicated.

OILS FROM SUMATRA 10 Area for Ardjuna oils (higher plant) -

1114

5

3

3

2

>Ot-

Area for Sunda oils (lacustrine) 0.5

0.5

0,3

0.3

0.2 -34 -32

-30

-28 -26 -24

-22

-20

-11

0.2

(~130 ppmil. I

Fresh-to-brackish lacustrine

II

Saline lake

Ill

Fluvial-lacustrine-bog

IV

Peat-swamp

V

Marine environment

•

North Sumatra condensates

Fig. 5. Plot (after Luo Binjie et al. 1988) of pristane/ phytane ratio versus isotopic signature for the NSB condensates. Also shown are summarized data for typically higher plant-derived oils (IV) from Ardjuna and lacustrine oils (V) from Sunda, offshore northwest Java (Pramono et al. 1990).

is dominantly lacustrine. The exception is the NSB5 Securai-4 sample. The picture that emerges from these data in conjunction with the biomarker results is that the latter oil is of the Ardjuna higher plant-derived type whilst the others originate from dominant lacustrine material with about 25% higher plant input. An environment of alternating lacustrine (dominant) to limnic coaly to ombrogenous peat swamp is envisaged possibly represented by a series of periodically interconnected shallow basins separated by low hills (viz. somewhat analogous to the Eocene Gippsland Basin of Australia but with a far greater development of lacustrine facies). The reason for the seemingly dominant higher plant) biomarker pattern revealed by GCMS is thought to be the presence of distinctive polycyclics (bicadinanes, oleananes) which, on mixing of oils from lacustrine source materials, may distract attention from the lower concentrations of more commonplace and less distinctive/hopanes, which occur in both higher plant and lacustrinederived organic matter.

145

Maturity

The maturity of source rocks is commonly calculated from the reflectance of vitrinite. Oils, of course, do not contain macerals and a variety of chemical reactions have been investigated as possible alternative measures of thermal maturity. Both aliphatic and aromatic hydrocarbons have been used, the former normally involving measurement of epimers (although the actual mechanism may not be an epimerization (Abbott et al. 1990)), the latter involving measurement of either the aromatization process itself, alkyl-chain cracking of the aromatics and/or alkyl substituent isomerization (see Peters & Moldowan 1993 for a general guide). Use of aliphatic steriodal hydrocarbon distributions (m/z 217) for maturity assessment was precluded in the present study due to the large contribution of m / z 217 ions from the abundant non-steroidal polycyclics. However, the contribution of terrigenous organic matter to the condensates and their high abundance of volatile hydrocarbons made the use of alkylnaphthalenes and alkylphenanthrenes as maturity indices perfectly viable (Alexander et al. 1985; Radke 1987) and calculated reflectance values (Rc %) were obtained from the data (Table 2). Values of the ratios TNR and MPI (Table 2; cf. Alexander et al. 1985; Radke 1987) which essentially indicate the increasing proportion of /3-substituted trimethylnaphthalenes and r-substituted methylphenanthrenes relative to their a-counterparts with increasing maturity, show that the condensates are all mature varying from peak maturity (NSB4 Telaga Said T-7, Rc 0.9%) to post-mature (NSB1 Wampu-6 Rc 1.7%). The salient features of the ion chromatograms are illustrated in Figs 6 & 7, where the dramatic increase in fl/3fl-2,3,6-trimethylnaphthalene and /3-3- and 2-methylphenanthrenes is obvious for NSB1 (Fig. 6) compared with NSB4 (Fig. 7). Additional indications of the high maturities of these oils were evident from the low proportion of C26_28triaromatic steroids in the oils relative to C21 counterparts (cf. Mackenzie 1984); particularly for the postmature sample NSB 1. There is a broad trend of increased maturity with increasing depth throughout the study region (Matchette-Downes 1992), where the least mature oils have been displaced by more mature oils as the sub-basin progressively matured. Between the two maturity end members represented by the oils of the Telaga Said area in the Kentapang Formation reservoirs and post-mature condensates pooled in the Wampu area in the Belumai member reservoirs,

146

ET AL.

C. J. M A T C H E T - I ' E - D O W N E S %bundance

m/z

' ' ,1.00

Pime _>0

~_2'00. ' ' { 3 ' 0 0 ' .

' 14.00

ls.oo

16.00

17.00

18.00

19.00

I i

.

.

£ime _>0 Xbundance

Fime _>0 %bundance

.

.

llJOO

.

A

A:,,. , . '

. 13too.

12100.

j.,_~, . . . . . .

14.00

, .A:._.^.,..A. ~

15.00

16.00

v ' '

17.00

142

~

18.00

m/z

156

'

'~-'="-

19.00

m / z 1 70

.

.

.

.

.

1110o

.

.

.

.

.

,'2 .'oo

.

.

i

~', .'oo

.

14.oo

.

.

.

i

'

lS.OO

'

'

i

.

1~.oo

.

17.oo

.

.

.

.

.

1~.oo

.

.

.

.

19.oo m/z

192

B

(a)

£ime _>0

2~Ioo

nloJ

~Ioo

' ~.41oo. . . .

'

26.00

'

27.oo

•IihI, ~.|mlo{

m Iz 1 42 #

0 Pime -> %bundance

' ' ' 11

oo

' ' ~2Joo

=13.oor'

.^.

, 4~ . ,o b ~ ' -' ' { s- ,. o b 1

,-

~16.oo _ = _ ~ L _ : _ ~ ,17.oo . _. _ ~ _ . . . .18.oo ,

19.o,, m l z 156

16 • O0

19 • O0

B~ ~

h

0 £ime -> kbundance

ii. O0

12 • O0

13 • O0

14. O0

15 • O0

17 • O0

18 • O0

m/z

0 1 ~ime -> %bundance

.

.

.

.

.

.

.

.

111 O0

,

. . . .

12. O0

,

. . . .

13. O0

,

. . . .

14. O0

= '~,

15. O0

,

, ~A¢'~

16. O0

. . . .

17. O0

~

,

18.. O0

, A

,

19. O0

m l z 192 x~

(b)

L

ime ->

17o

o

21. oo

2 2 . oo

23. oo

24. oo

25. oo

26. oo

27. o0

OILS FROM SUMATRA there has been mixing of the hydrocarbons during successive phases of hydrocarbon expulsion and migration. However, it is important to appreciate that the maturity of the oils examined is far too great for them to have been generated from the Baong Formation. The maturity data considerably contrain the possible location of the source rocks and indicate that these are to be found at depth and probably will have passed through the 'condensate' generation window (e.g. Ro 1.7%) in many of the sub-basins.

(4)

(5)

Conclusions Examination of five condensate/oils from the North Sumatra Basin by G C - M S and stable isotope MS has revealed the following: (1) An apparent conflict between the biomarker GCMS data (indicating a higher plant-derived source material) and the isotope data (indicating marine lacustrinederived source materials). (2) The conflict can be resolved in the following way. Both lacustrine and higher plantderived oils have some steranes and hopanes in common. However, higher plant material from the Cretaceous onwards also often contains additional distinctive alkanes such as oleananes and bicadinanes in high concentrations. The presence of relatively small (c. 25%) amounts of higher plant material containing the latter compounds may then dominate the m/z 191 biomarker profiles. (3) A viable interpretation, consistent with all the data, invokes a mixed source environment for four of the five oils (NSB 1-4) with a, not necessarily time-equivalent, minor (c.

(6)

(7) (8)

(9)

147

25%) higher plant signature mixed with a dominant marine/lacustrine input. The regional geology precludes an exclusively marine source at depth. The remaining oil (NSB5) appears to be sourced from a dominant higher plant source material. The facies is interpreted as alternating lacustrine (dominant) to limnic coaly to ombrogenous peat swamp. Assessment of maturity via the distributions of alkylaromatics was enhanced by the terrigenous nature of the source material, whilst use of aliphatics was obviated by the co-occurrence of high concentrations of terrestrially derived polycyclic alkanes with the steroidal alkanes. The oils/condensates ranged from peak maturity (Re 0.9%) to post-maturity (Re 1.7%) in the deeper depocentres. Mixtures of oils with different maturities were probably present in some reservoirs. The data considerably contrain the possible source rock location and, in our view, negate the insufficiently mature Baong Formation as the dominant source. It is thought that the unrecovered source rocks probably now lie at depth with Ro/> 1.7%.

We are extremely grateful to both LEMIGAS, Indonesia and BGS, UK for permission to publish these findings and to LEMIGAS for access to the samples and unpublished data. Colleagues at LEMIGAS and University of Plymouth are acknowledged for help and advice. Especially we would like to thank Marnida Ulibasa (LEMIGAS) for help with the LC separations and GC analyses and to Roger Srodzinski (Plymouth) for help with GCMS. NERC is acknowledged for provision of the latter GCMS facilities.

References VANAARSEN,B. G. K., Cox, H. C., HOOGENDOORN,P. & DE LEEUW, J. W. 1990. A cadinene biolpolymer in fossil and extant dammar resins as a source for cadinanes and bicadinanes in crude oils from South East Asia. Geochimica et Cosmochimica Acta, 54, 3021-3031. ABBOTT,G. D., WANG,G. Y., EGLINTON,T. I., HOME, A. K. & PETCH, G. S. 1990. The kinetics of sterane biological marker release and degrada-

tion processes during the hydrous pyrolysis of vitrinite kerogen. Geochimica et Cosmochimica Acta, 54, 2451-2461. ALAM, M. & PEARSON, M. 1990. Bicadinanes in oils from the Surma Basin, Bangladesh. Organic Geochemistry, 15,461-464. ALEXANDER, R., KAGI, R. J., ROWLAND, S. J., SHEPPARD, P. N. & CHIRILA, T. V. 1985. The effects of thermal maturity on distributions of

Fig. 6 (a) & (b). GC-MS ion chromatograms (m/z 142,156,170,192) illustrating, respectively, the distributions of mono-, di- and trimethylnaphthalenes and methylphenanthrenes in a peak maturity condensate (NSB4) and a post-mature condensate (NSB 1). Annotated peaks show the increase in r-substituted aromatics with increasing maturity. GCMS conditions: Hewlett-Packard 5890 GCMS (University of Plymouth). 12 m HP-1 capillary GC column 60-300°C @ 5°C min. -1 Selected ion monitoring.

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dimethylnaphthalenes and trimethylnephthalenes in some ancient sediments and petroleums. Geochimica et Cosmochimica Acta, 49, 385-395. DALY, M. C., COOPER, M. A., WILSON, I., SMITH, D. G. ,~gHODPER,B. G. D. 1991. Cenozoic plate tectonics and basin evolution in Indonesia. Marine and Petroleum Geology, 8, 2-21. DAVIES, P. R. 1984. Tertiary structural evolution and related hydrocarbon occurrences, North Sumatra Basin. In: Proceedings of the 13th annual convention of the Indonesian Petroleum Association, Jakarta. Indonesian Petroleum Association, Jakarta, 19-49. GRANTHAM, P. J., POSTHUMA, J. ,~z BAAK, A. 1983. Triterpanes in a number of Far-Eastern crude oils. In: BJOROY,M., ALBRECHT,P., CORNEORTH, C., DE GROOT,K., EGLINGTON,G., GALIMOV,E., LEYTHAEUSER, D., PELET, R., RULLKOTFER,J. ,~ SPEERS, G. (eds) Advances in Organic Geochemistry, 1981. John Wiley, Chichester, 675683. KINGSTONE, J. 1978. Oil and gas generation, migration and accumulation in the North Sumatra Basin. In; Proceedings of the 7th annual convention of the Indonesian Petroleum Association, Jakarta. Indonesian Petroleum Association, Jakarta, 75-104. KJELLGREN, G. M. ,~ SUGIHARTO,H. 1989. Oil geochemistry: a clue to the hydrocarbon history and prospectivity of the south eastern North Sumatra Basin, Indonesia. In: Proceedings of the 18th annual convention of the Indonesian Petroleum Association, Jakarta. Indonesian Petroleum Association, Jakarta, 362-384. LONGLEY, I. M., BARRACLOUGH,R., BRIDDEN,M. A. & BROWN, S. 1990. Pematang lacustrine petroleum source rocks from the Malacca Strait PSC, Central Sumatra, Indonesia. In: Proceedings of the 19th annual convention of the Indonesian Petroleum Association, Jakarta. Indonesian Petroleum Association, Jakarta, 279-297. Luo BINJIE, YANG XINGHUA, LIN HEJIE ,~ ZHENG GUODONG. 1988. Characteristics of Mesozoic and Cenozoic non-marine source rocks in north-west China. In: FLEET, A. J., KELTS, K. ,~: TALBOT, M. R. (eds) Lacustrine Petroleum Source Rocks. Geological Society, London, Special Publication, 40,291-298. MACKENZIE, A. S. 1984. Applications of biological markers in petroleum geochemistry. In: BROOKS, J. t~ WELTE, D. (eds) Advances in Petroleum

Geochemistry, Volume 1. Academic, London, 115-214. MATCHETrE-DOWNES, C. 1992. Petroleum geochemistry of the North Sumatra Basin, Part I. LEMIGAS, Jakarta. MULHADIONO., HARTOYO, P. & SOEDALDJO, P. A. 1978. The Middle Baong Sandstone units as one of the most prospective units in the Aru area, North Sumatra. In: Proceedings of the 7th annual convention of the Indonesian Petroleum Association, Jakarta. Indonesian Petroleum Association, Jakarta, 75-104. NICHOLSON, R. A. & SOEKAPRADJA,S. 1990. Organic geochemical studies in the North Sumatra Basin. In: Scientific Contribution on petroleum science and technology. Special Publication LEMIGAS, Jakarta, 45-67. NOBLE, R. A., Wu, C. H. & ATKINSON, C. D. 1991. Petroleum generation and migration from Talang Akar coals and Shales offshore N.W. Java, Indonesia. Organic Geochemistry, 17,363374. PETERS, K. & MOLDOWAN,J. M. 1993. The Biomarker Guide: Interpreting Molecular Fossils in Petroleum and Ancient Sediments. Prentice Hall, New Jersey, USA. PRAMONO,H., Wu, C. H. &NOBLE, R. A. 1990. A n e w oil kitchen and petroleum bearing subbasin in the offshore Northwest Java Basin. In: Proceedings of the Indonesian Petroleum Association, Jakarta, 19,253-278. RADKE, M. 1987. Organic geochemistry of aromatic hydrocarbons. In: BROOKS,J. & WELTE,D. (eds) Advances in Petroleum Geochemistry, Volume 2. Academic Press, London, 141-207. SITUMEANG,S. ~ DAVIES,P. R. 1986. A geochemical study of Asamera's block 'A' production sharing contract area, North Sumatra Basin. In: Proceedings of the 15th annual convention of the Indonesian Petroleum Association, Jakarta. Indonesian Petroleum Association, Jakarta, 321-340. SOFER, Z. 1984. Stable carbon isotope compositions of crude oils: application to source depositional environments and petroleum alteration. American Association of Petroleum Geologists Bulletin, 68, 31-49. TAMBUNAN, L. 1991. Biomarker applications in the North Sumatra Basin. MPhil. thesis, University of Newcastle, UK. TELNAES, N. • COOPER, B. S. 1991. Oil-source rock correlation using biological markers, Norwegian continental shelf. Marine and Petroleum Geology, 8,302-310.

Geochemistry of aliphatic-rich coals in the Cooper Basin, Australia and Taranaki Basin, New Zealand: implications for the occurrence of potentially oil-generative coals DAVID

J. C U R R Y 1, J O H N

K. E M M E T T 2 & J O H N

W. H U N T 2'3

aExxon Production Research Company, PO Box 2189, Houston, Texas 77252, USA 2Esso Australia Ltd, G P O Box 400, Melbourne 3001, Australia aPresent address: Groundwater Technology Australia Pty Ltd, 17 Forrester St, Kingsgrove, N S W 2208, Australia Abstract: Although the concentration of long-chain aliphatic constituents is a primary

determinant of the oil generation potential of coals, the factors which govern their occurrence in different coals are poorly understood. In this study, Permian coals from the Cooper Basin, Australia, and the Eocene coals from the Taranaki Basin, New Zealand, were compared to determine these factors. The Taranaki Basin coals were deposited in temperate, fluvial-deltaic environments. HI values range from 236-365. Extracts have high pristane/phytane ratios and variable abundances of oleanane and other non-hopanoid terpanes. The extracts and pyrolysates contain high relative concentrations of aliphatic groups > n-C20. These data imply that much of this aliphatic carbon is derived directly from higher plant material. The Cooper Basin coals were deposited in high latitude bogs and contain 40-70% inertinite. The coals have been severel~¢degraded. Pristane/phytane ratios are low (2.15-6), but His are moderate (up to 243 mg g- OC). The extracts and pyrolysates both contain high relative concentrations of aliphatic groups; however, the distributions are different from higher plant-derived material. These data imply the bulk of the aliphatic carbon in these coals is derived from microbial biomass (both bacterial and fungal degradation products and algal input). These results show that long-chain aliphatic groups in coals can be derived directly from the higher plant material, from microbial activity in the depositional environment, or from a combination of the two.

The potential of terrestrially derived coals to generate and expel oil has been the subject of an increasing amount of interest in the last several years, and the concept that some coals can act as oil sources has gained a significant measure of acceptance, especially for coals from Australia (e.g. Powell et al. 1991), New Zealand (Johnston et al. 1991), and Indonesia (e.g. Durand & Paratte 1983; Huc et al. 1986). However, there are still questions associated with this concept. For example, although many coals have been shown to generate abundant high molecular weight species such as normal alkanes (e.g. Powell et al. 1991), their ability to efficiently expel these components has been questioned. Observational data (Powell & Boreham 1991) and laboratory measurements (Sandvik et al. 1992) indicate relatively high expulsion efficiencies; however, hydrous pyrolysis data (e.g. Teerman & Hwang 1989) indicate low expulsion efficiencies of oil-like material. In addition, the relationship of maceral compositions to oil

generation potential (Bertrand et al. 1986) and to expulsion mechanisms (Horsfield et al. 1988) are still incompletely understood. There is also considerable uncertainty over which types of coals can be oil-generative and where, geographically and stratigraphically, they can occur. Oils generated from terrestrially derived organic matter characteristically contain very high concentrations of normal alkanes, especially in the higher molecular weight ranges. Consequently, in order for a coal to be oil generative, it must, as a first criterion, contain sufficient concentrations of long-chain weight normal aliphatic groups (i.e. ~>n-C12+) to generate the normal alkanes occurring in the oils (Curry 1985; Smith et al. 1987; Powell et al. 1991). As a result, the ecological, depositional, and diagenetic factors which control the occurrences and concentrations of long-chain aliphatic groups in coals will have a critical influence on their capability to generate oil. These factors are still incompletely understood,

From Scott, A. C. & Fleet, A. J. (eds), 1994, Coal and Coal-bearing Strata as Oil-prone Source Rocks? Geological Society Special Publication No. 77, pp. 149-182.

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especially since coals are very heterogeneous in character and there is a high degree of variability in the composition of coals from different ages and depositional environments. The objectives of this study, therefore, were to delineate the factors which control the occurrences of long-chain aliphatic groups in coals and to determine how these factors affect the occurrences of potentially oil-prone coals. In order to delineate these factors, coals from the Taranaki Basin, New Zealand, and Cooper Basin, Australia were compared. Although coals from both these areas are terrestrially derived, relatively aliphatic rich, and associated with known oil production, they are of different ages, derived from very different palaeofloras, and were deposited under very different conditions. As a result, comparison of the geological and geochemical data for these dissimilar coals can provide insight into the processes by which some coals are enriched in aliphatic carbon.

Methods All samples were taken from cores. Elemental analyses were performed by Huffman Laboratories, Golden, CO. Vitrinite reflectance and maceral counts were done by Dr Alan Cook of Keiraville Konsultants, Keiraville, NSW. Total organic carbon analyses (for the shales) were carried out using a LECO analyser. Bitumen extraction used a 9:1 mixture of dichloromethane : methanol in Tecator extraction apparatus; chromatographic separations were carried out by HPLC. Gas chromatography of the total extracts, saturate fractions, and aromatic fractions were carried out using Hewlett Packard 5890 gas chromatographs fitted with 30 m DB-5 capillary columns. Saturate and aromatic fractions were analysed with hydrogen carrier gas. GC/MS analyses in the SIM mode were carried out using a Hewlett Packard 5890 gas chromatograph fitted with a 30 m DB-5 capillary column and interfaced to a Varian INCOS 50 quadrupole mass spectrometer. Full scan gc/ms analyses utilized a Hewlett Packard 5890 gas chromatograph fitted with a 30 m DB-5 capillary column, interfaced to a Hewlett Packard 5970 Mass Selective Detector. Pyrolysis-gc/ms analyses were carried out on a custom-built system consisting of a CDS pyroprobe unit fitted to a Hewlett Packard 5890 gas chromatograph with a 30m DB-5 capillary column and a Hewlett Packard 5970 Mass Selective Detector operating in the full scan mode.

Taranaki Basin

Geological setting and sample description The Taranaki Basin is a Cretaceous-Tertiary, clastic-dominated basin located on the western side of the North Island of New Zealand. The basin is divided into the offshore Western Platform region and the offshore-onshore Taranaki Graben (Pilaar & Wakefield 1978). Basin fill ranges from terrestrial and paralic to deep-water marine sediments. For more complete discussions of Taranaki Basin geology see Pilaar & Wakefield (1978, 1984) and King & Robinson (1988). The coals and shales in this study are from the Eocene Kapuni Group and were deposited in an upper to lower coastal plain setting (King & Robinson 1988). The palaeoclimate was temperate to sub-tropical with abundant rainfall (Pocknall 1990). The coals and shales analysed in this study are from cores from the Mangahewa-1 and Kapuni-8 wells in the onshore area of the Taranaki Graben. A summary of sample numbers, depths and lithology is contained in Table 1 in the Appendix at the end of this paper.

Geochemical characterization The coals and kerogens from both wells are incipiently mature. The Rv(ma,,) values from the Kapuni-8 well range from 0.56-0.70%, with an average maturity of Rv(max) of 0.64% for the coals. The Rv(max)values for the samples from the Mangahewa-1 well range from 0.64-0.77%, with an average Rv(max)of 0.73% for the coals. Neither set of samples appears to have generated significant amounts of hydrocarbons. The maceral compositions of the coals and kerogens are characteristic of higher plantderived coals, containing mainly vitrinite (Appendix: Table 2; Fig. 1). Cutinite, resinite, and some sporinite are the main liptinitic macerals. The coals from the Kapuni-8 well tend to have higher liptinite contents than do those from the Mangahewa-1 well, while shales with TOC less than 20%, generally have higher concentrations of liptinite than the interbedded coals. Inertinite concentrations are low in all samples. Although the high concentrations of vitrinite are typical of higher plant-derived coals, the Taranaki Basin samples are more hydrogen rich than many other terrestrially derived coals of similar maturity, with H/C ratios ranging from 0.81-1.01 (Appendix: Table 3; Fig. 2). In contrast, the O/C ratios are somewhat lower than those of many humic coals at these maturities.

ALIPHATIC-RICH COALS FROM AUSTRALIA AND NEW ZEALAND 100 INERTINITE

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D. J. CURRY E T A L .

As expected, Rock-Eval $2 values are very high for the coals (Table 3). Hydrogen Index (HI) values range from 236-361mgg -1 OC. These values are within the range of hydrogenrich terrestrial organic matter from areas such as the Gippsland Basin, Australia (Powell et al. 1991) and the Mahakam Delta of Kalimantan (Huc et al. 1986). Conversely, the $3 and Oxygen Index (OI) values are very low for terrestrial organic matter at this level of maturity. The pristane/phytane ratios for the bitumen extracts of the coals range from 6.46-12.29, with most values greater than 8.0 (Appendix: Table 4a). These values are significantly higher than the ratio of 4.0 considered characteristic of higher plant-derived organic matter (Tissot & Welte 1984). In addition, the pristane/n-C17 alkane ratios for the coals are generally greater than 4.0, which is also characteristic of immature, higher plant-derived material. The most abundant individual consituents of the bitumen extracts are pristane and C1-, C2-, and C3-substituted naphthalenes (e.g. Fig. 3), which appears to be a characteristic of Tertiary higher plant derived-organic matter from this region. However, the total extract gas chromatograms also contain large abundances of high molecular weight n-alkanes, especially

the n-C25,/'/-C27, and n-C29 alkanes. The H-C27/ n-C17 ratios are generally greater than 1.0 and frequently greater than 3.0. In addition, the sum of the n-C2s to n-C34 alkanes is usually greater than 50% of the total Cls+ n-alkanes (Table 4a). The sterane and triterpane biomarker constituents also indicate a predominantly higher plant origin. Hopane/sterane ratios are very high and there are no systematic differences between the coals and the shales. The sterane fractions are dominated by the C29 regular and rearranged steranes, with C29 sterane/total sterane ratios as high as 0.92 for some coals (Table 4a, Figs 4a, b). There are no significant concentrations of 4-methyl C30 sterane homologues. Significantly, these coals contain relatively high concentrations of diasteranes (Table 4a; Figs 4a, b). The concentrations of diasteranes in the coals (expressed as parts per million of the saturate fractions) are equivalent to the diasterane concentrations in the interbedded shales. Since these are low-ash coals, the formation of the diasteranes by clay-catalysed rearrangements is unlikely. The diasteranes were instead probably formed by rearrangements catalysed by the very acidic conditions frequently prevalent in peat swamps (mires). Similar high abundances of diasteranes can be observed in the sterane fractions of other coals,

f

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ALIPHATIC-RICH COALS FROM AUSTRALIA AND NEW ZEALAND for example, coals from the Sakoa coalfield in Madagascar (Ramanampisoa et al. 1989), coals from the Cooper Basin (see below), and Westphalian coals from the Midlands of the UK (Curry, unpublished data). The occurrence of significant amounts of diasteranes in these low ash coals implies that the occurrence of diasteranes as indicators of clastic-rich source rocks may be of limited usefulness in terrestrial organic facies. The triterpane fractions of the coals and shales contain varying abundances of 18-a oleanane, with oleanane/C3o hopane ratios ranging from 0.02 to 0.52. Although the coals and shales from the Mangahewa-1 well generally have lower oleanane/hopane ratios than those in the Kapuni-8 well, there is a considerable degree of variation within each well. More significantly, however, the coal extracts contain relatively high absolute concentrations of oleanane. As shown in Table 4a, the concentration of oleanane in the coals varies from 56ngmg - 1 saturate fraction to 430ngmg -1 saturate fraction, with the Kapuni-8 coals generally having higher concentrations of oleanane than the Mangahewa-1 coals. The coals and shales also contain several other triterpane constituents, including two components indicated as W and T in Table 4a and Figs 5a and 5b. These constituents were initially identified as bicadinane isomers W and T by comparison of relative retention times and mass spectra with published data (Grantham et al. 1983; van Aaarsen et al. 1992). However, the occurrence of bicadinanes in pre-Oligocene sediments and oils is rare, and recent work has shown that these constituents instead may possibly be C30 triterpanes similar to oleanane, but in which the A-ring is contracted to a fivemembered ring (ten Haven, pers. comm.). However, there is no correlation between the concentration of oleanane and triterpane isomer W. (Triterpane isomer T could not be quantified because of partial co-elution with the C27 Tm hopane.) The variability in the concentrations of these compounds over short intervals implies a high frequency of variation in the precursor plant assemblage, especially in the abundance of angiosperms. In addition, the lack of correlation between the abundances of oleanane and triterpane isomer W indicates that their precursors are not genetically related to a straightforward manner. The relative distributions of most triterpanes (except the C27 Tm hopanes, see below) are generally uniform for the samples from each well, and most of the compound ratios (e.g. C29/C30) are equivalent for the coals and shales

153

(Table 4a). However, the absolute concentrations of the triterpane constituents are significantly higher in the coals and carbonaceous shales (i.e. T O C > 2 5 % ) than in the adjacent lower TOC shales (Appendix: Table 5a). In addition, the concentrations of triterpanes tend to be higher in the Mangahewa-1 well than in the Kapuni-8 well (Table 5a). As noted above, the abundances of the C27 Tm hopanes appear to be anomalous. Although the abundances of these constituents could not be reliably quantified due to co-elution of triterpane T and another unidentified triterpane, qualitative assessment of full scan mass spectra indicate that the coals and carbonaceous shales contain significantly higher concentrations of C27 Tm than the lower-TOC shales. Consequently, Ts/Tm ratios are significantly lower in the coals as compared to the shales. This effect is also noted in the coals and shales from the Cooper Basin (see below) and in other areas (Curry, in prep.). These data show that these coals are of terrestrial (higher plant) origin, and were deposited in a clastic-poor, highly acidic, oxidizing peat swamp (mire) with little degradation. The data also show there is a difference in organic facies between the coals and shales in the Mangahewa-1 and Kapuni-8 wells. The differences in the HI values, liptinite content, oleanane and triterpane concentrations, hopane concentrations, and proportion of high molecular weight n-alkanes in the extracts indicate that the organic facies in these wells, while both predominantly terrestrial in character, are not identical. In particular, the increased concentrations of oleanane in the coal bitumens imply that the coals in the Kapuni-8 well had a higher proportion of angiosperm precursors than the Mangahewa-1 coals.

Aliphatic carbon content

These coals and kerogens contain high relative concentrations of long-chain aliphatic groups in the pyrolysates (e.g. Figs 6a, b). In both wells, the relative concentrations of higher molecular weight (n-C2o+) aliphatic groups are high compared to the lower molecular weight aliphatic groups, even when the differences in mass spectrometer response factors are taken into account. This can be seen in, for example, Figs 7a and b, which show the alkyl constituents (as the sum of the m / z 69 + 70 + 71 ions) of the pyrolysates. However, the coal pyrolysates also contain high concentrations of phenol and methylated phenol constituents ('P' in Figs

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D. J. CURRY ET AL.

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156

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6a, b), methylated benzenes ('A') and methylated naphthalenes ('Me-N'), characteristic of terrestrially derived organic matter. Also evident in Figs 7a and b is the difference in the distributions of long-chain aliphatic

groups in the coal pyrolysates between the two wells. The coals from the Kapuni-8 well (e.g. Figs 6a, 7a) generally contain higher relative concentrations of n-C25÷ components than do coals from the Mangahewa-1 well (e.g. Figs

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6b, 7b). These differences in the distributions of aliphatic groups in the pyrolysates parallel the differences in the n-alkane compositions of the bitumens (Table 4a) and further reflect the difference in organic facies between the wells.

The aliphatic character of the coal and kerogen pyrolysates is consistent with the other geochemical data. For example, the gas chromatographic-amenable fractions of the total extracts of the coals are dominated by long-chain

158

D. J. CURRY E T A L .

normal alkanes (e.g. Fig. 3), which indicates a significant aliphatic component for the coals. The H/C ratios are higher than those observed in many other coals and terrestrial kerogens and imply there is an aliphatic-rich component with a high H/C ratio and a low O/C ratio in the Taranaki coals which may not occur in coals of the same maturity with lower H/C and higher O/C ratios. The occurrence of relatively high concentrations of long-chain aliphatic groups in these coals is supported by CP/MAS 13C-NMR analyses of Eocene coals from the Taranaki Basin (Collen et al. 1988). Although CP/MAS aaC-NMR data do not show chain length, they can give a quantitative estimate of the types of carbon present. These data show that coals from the Kapuni Group contain significant concentrations of polymethylene carbon (i.e. (-CH2)x, x > 4 ) , as well as of branched and terminal methyl groups.

Taranaki Basin: discussion The geological and geochemical data indicate that these coals and kerogens are of predominantly higher plant origin, with little or no algal or bacterial contributions. Consequently, the long-chain aliphatic groups which occur in them are also of higher plant origin. The most probable sources of these long-chain aliphatic groups are the highly aliphatic biopolymers which occur in cuticular and protective tissues of several species of higher plants (Nip et al. 1986, 1987; Tegelaar et al. 1989; see also Collinson et al., this volume). These highly aliphatic biopolymers are characterized by high concentrations of long-chain normal aliphatic groups organized in insoluble structures within the cuticular or protective tissues. The role of cuticular-derived biopolymers are precursors to the aliphatic carbon groups in the Taranaki Basin coals is indicated by several factors, most particularly the pyrolysis-gas chromatography results. The molecular weight distributions of the long-chain aliphatic groups in these coals are very similar to those of the highly aliphatic biopolymer constituents of cuticular material. For example, the distributions of normal alkenealkane pairs in the coal pyrolysates (e.g. Figs 7a, 7b) are very similar to the distributions in the pyrolysates of highly aliphatic biopolymers in cutin isolated from cuticular material from a number of modern and fossil sources, including A g a v e a m e r i c a n a (Nip et al. 1986, 1987; Tegelaar et al. 1989). In these pyrolysates, the relative concentrations of the n-alkenes and n-alkanes are generally uniform from approximately n-C14

to n-C27, above which they decrease rapidly. This uniformity implies that relatively long aliphatic chains are present in the coals and biopolymers which are being cracked essentially at random sites along the carbon chain during pyrolysis. The rapid decrease in the relative concentrations of the n-alkenes and n-alkanes above C27 implies that the aliphatic chains incorporated in the coals and biopolymers are approximately of that chain length. The variations in organic facies between the Kapuni-8 and Mangahewa-1 coals indicate that there are probably several different palaeofloral assemblages which can give rise to aliphatic-rich coals. In addition, the relatively small angiosperm content in some of the coals (indicated by the low concentrations of oleanane) implies that the precursor palaeofloras of these coals probably contain a significant gymnosperm input. This is consistent with the work of Thomas (1982) for Australian coals and Shanmugam (1985) for New Zealand coals. As demonstrated by Nip et al. (1986) and Tegelaar et al. (1989), not all higher plants contain highly aliphatic biopolymers. The restricted occurrence of the higher plant-derived highly aliphatic biopolymers implies that not all coals contain these materials and that occurrences of the palaeoflora which can give rise to high concentrations of aliphatic groups in coals are controlled by evolutionary trends and palaeoecology. These factors, in turn, will restrict the occurrence of these types of aliphatic-rich coals both geographically and temporally. This is consistent with extensive published data (e.g. Tissot & Welte 1984), which indicate that many coals and terrestrially derived kerogens, especially from the Palaeozoic of the United States and northwestern Europe, contain very low concentrations of long-chain aliphatic groups and are not capable of generating oil. In addition, cutin and cuticular-like material may not be the only source of highly aliphatic biopolymers in terrestrial (higher) plants. Recent work by Khorasani & Michelsen (1991) on Jurassic coals from Svalbard has demonstrated the oil-generation potnetial of suberinite and subereous components. Their pyrolysis-gas chromatographic and hydrous pyrolysis data, however, indicate that the distributions of aliphatic groups in these constituents (which are also highly aliphatic biopolymers) are different from those observed in the cuticularderived biopolymers, with abundant aliphatic groups extending only to the range of n-C13 , rather than n-C27. The available data indicate that coals containing high concentrations of highly aliphatic

ALIPHATIC-RICH COALS FROM AUSTRALIA AND NEW ZEALAND biopolymers related to the cutin-derived material studied by Nip et al. (1986, 1987), and Tegelaar et al. (1989) appear to occur mostly in Cretaceous and younger sediments, chiefly in the Southern Hemisphere, while potentially oilgenerative coals containing suberinite-like material can occur in sediments as old as the Jurassic (Curry, in prep.).

Cooper Basin Regional geology and sample description The Cooper Basin is a Permo-Triassic intracratonic basin located in south-central Australia. The Cooper Basin is unconformably overlain by the Jurassic Eromanga Basin. During the Permian the basin was filled by a series of lacustrine and fluvial deposits. For a more complete discussion of the basin see Heath (1989). The samples in this study are from the Lower Permian Patchawarra Formation, except for one coal from the Upper Permian Toolachee Formation. The Lower Patchawarra Formation has been divided sequence stratigraphically into a series of four units designated (from top to bottom): Brown, Yellow, Blue, and Red, which represent successive basin-filling events. The coals occur both at the top of and within the sequences. The Patchawarra coals were deposited in cold weather, ombrotrophic, blanket peat bogs dominated by primitive, lowlying vegetation. The bogs were subjected to repeated flooding and desiccation as the water levels rose and fell. More detailed discussions of the origins of the coals in the Cooper Basin are contained in Hunt (1989) and Hunt & Smyth (1989). The samples used in this study are from cores taken from the Gidgealpa-5 and Gidgealpa-6 wells. A list of samples, depths, and stratigraphic units is contained in Table 1.

Geochemical characterization The coals from these wells appear to be early mature. The levels of maturity are difficult to determine, however, since measured Rv(max) values vary from 0.83-0.98% over a narrow depth interval (Table 2). This variation is probably due in part to the extensive alteration and degradation of the primary organic matter (see below). The Cooper Basin coals are characterized by high concentrations of inertinite, which can be common in Permian Gondwanaland coals. The

159

concentration of inertinite ranges from 38% to almost 70% while the concentration of the liptinites is very low (Table 2; Fig. 1). High concentrations of inertinite are usually indicative of severe degradation, including subaerial exposure and desiccation. Although these coals contain high concentrations of inertinite, their elemental compositions are similar to those of many other humic coals and Type III kerogens (Table 2; Fig. 2) (Durand & Espitalie 1976). As with the Taranaki Basin coals, the Cooper Basin coals cover a broad range on the Van Krevelen diagram (Fig. 2). Since inertinites generally have low hydrogen concentrations, these values imply that the non-inertinitic fractions of the coals are relatively hydrogen rich. Although, as noted by Powell et al. (1991), correlation of maceral compositions with geochemical parameters such as I-I/C ratios is generally difficult, there appears to be an approximate inverse correlation of the H/C ratios with the inertinite trend for these coals (Fig. 8a). Extrapolation of the H / C inertinite correlation (Fig. 8a) indicates that these inertinites have a nominal IMC ratio of roughly 0.5 while the non-inertinitic material has a nominal H/C ratio of approximately 1.0. The Rock-Eval HI values for the coals range from 116 to 243mgg -a OC, which is high for inertinite-rich material. Similarly high values for Cooper Basin coals and shales were also noted by Powell & Boreham (1991) and Powell et al. (1991). More significantly, there is also an approximate inverse correlation of HI values with the inertinite concentration (Fig. 8b). Extrapolation of this correlation indicates that the inertinite has a nominal HI value of approximately 35mgg -~ OC, while the non-inertinite has a nominal HI value of approximately 350mgg - 1 0 C . In addition, the Rv(max) values generally tend to decrease with increasing HI (Fig. 8c) and decreasing inertinite content. The bitumen total extracts are all very similar and all contain some unusual characteristics (e.g. Fig. 9). For example, although the extracts contain fairly high concentrations of n-alkanes, they are not waxy, having relatively low concentrations of n-C2s+ components (Table 4b). The distributions of normal alkanes in the extracts of these coals more closely resemble the normal alkane distributions in microbial (i.e. algal and/or bacterial) organic matter than in terrestrially derived organic matter (e.g. Tissot & Welte 1984). The coal extracts also have a wide range of pristane/phytane ratios, ranging from 2.04 to 5.35 (Table 4b). The values below 3.0 are very low for humic coals in general and could also be indicative of a significant algal

160

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contribution to the source of the labile (noninertinitic) organic matter. The bitumens also contain abundant aromatic components (e.g. Fig. 9). Although the distributions of aromatic constituents relative to one another do not vary significantly among the samples, the concentrations of the aromatic constituents relative to the aliphatic constituents tend to be higher in the lower-HI coals. Methylated naphthalene homologues are the largest individual components in the coal extracts, which also contain high concentrations of phenanthrene and methyl phenanthrenes. Interestingly, the coal extracts also contain fairly high amounts of fluorene, substituted fluorenes, and other aromatic species (Fig. 9). The compositions of the triterpane biomarkers are very uniform for the Cooper Basin coals, both qualitatively and quantitatively (Appendix: Tables 4b, 5b; Fig. 10a). The abundances of the extended hopanes (especially the C32+ homologues) are low compared to the C30 hopane, characteristic of non-marine deposition. No occurrence of 25,28,30-trisnorhopane, 25,28,30-trisnormoretane, 28,30-bisnorhopane, and 28,30-bisnormoretane were

observed in the coals (Jenkins 1989). The occurrence of the C30 rearranged hopane (diahopane, also known as Compound X) at these relatively low levels of maturity implies an oxidizing depositional environment (Moldowan et al. 1991). As in the Taranaki coals, the C27 Ts/Tm hopane ratios and the absolute concentrations of triterpanes are significantly higher in the coals than in the clastic-rich intervals (Tables 4b, 5b). The compositions of the sterane biomarkers are also very uniform among the coals (Tables 4b, 5b; Fig. 10b). Although the C29 steranes are the dominant homologues, indicating nonmarine organic matter, there are also moderate concentrations of C27 steranes, indicating the possible occurrence of algal-derived organic matter. These coals also contain relatively high concentrations of diasteranes (Table 5b; Fig. 10b). As with the Taranaki Basin coals, the sterane rearrangement reactions were probably catalysed by highly acidic peat swamp conditions. The hopane/sterane ratios for the Cooper Basin coals (Table 4b) range from 0.96 to 7.51, with most of the values in the vicinity of 3 to 5.

Fig. 8. Cooper Basin geochemical correlations (see Table I for explanation of stratigraphic symbols). (a) H/C ratios versus % inertinite; (b) HI versus % inertinite; (c) HI versus Rv(max).

162

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There are no obvious correlations of these ratios with other indicators of organic facies such as pristane/phytane ratios, inertinite concentrations, or sterane distributions. While the hopane/sterane ratios of the Cooper Basin coals

are generally in the range of those characteristic of non-marine organic matter, they are significantly less than the hopane/sterane ratios of the Taranaki Basin coals (Table 4a) and other terrestrial organic facies (Isaksen 1991).

164

D . J . CURRY ET AL.

A l i p h a t i c ca r b o n content

Pyrolysis-gc/ms analyses show that long-chain aliphatic groups (>n-C12) constitute a significant portion of the thermally labile components of the Cooper Basin coals (e.g. Figs l l a , b). Powell et al. (1991) reported that the concentrations of aliphatic carbon in the Patchawarra coals are at the low end of the range of coals and kerogens from the Permian through the Tertiary in Australia. However, since those concentrations are normalized to the total organic carbon content of the coals and shales, they do not take into account the presence of high abundances of inertinite. Since high concentrations of inertinitic components tend to dilute the TOC-normalized concentrations of thermally labile material, comparison of TOC-normalized yields of thermally labile constituents from lowversus high-inertinite coals and kerogens may be somewhat deceptive. The effects of dilution of organic carbon by inertinitic material may be one of the reasons that it has been difficult to determine the minimum yields of aliphatic carbon necessary for a coal (or kerogen) to be oil generative (Powell & Boreham, this volume). The relative compositions of the aliphatic constituents by molecular weight are very similar for all the coals, regardless of sequence stratigraphic unit, HI values, or inertinite content. For example, the distributions of longchain aliphatic groups are similar for a high-HI coal from the Yellow sequence (Fig. 12a) and a low-HI coal from the Blue sequence (Fig. 12b). In the Cooper Basin coals, the relative concentrations of the long-chain aliphatic groups decrease rapidly with increasing molecular weight, so that the abundances of the n-C2o+ constituents are much lower than those of the lower molecular weight aliphatic groups. Similar molecular weight distributions of aliphatic constituents in pyrolysates of high-inertinite Patchawarra coals were noted in Powell et al. (1991). However, the distributions by molecular weight of the aliphatic components in the pyrolysates of the Cooper Basin coals are significantly different from those observed in the Taranaki Basin. These differences in the distributions of the long-chain aliphatic groups can be observed in the alkyl fraction mass chromatograms (Figs 7a and b compared to Figs 12a and b). In addition, the distributions of aliphatic constituents in the Cooper Basin coal pyrolysates are also different from those of other aliphaticrich coals, such as the cutinite-rich, Carboniferous Indiana paper coal (Nip et al. 1989; see also Collinson et al., this volume) or coal from the Sydney Basin (Curry, in prep.).

The pyrolysis data are consistent with the other data indicating a fairly high abundance of aliphatic carbon despite the high inertinite concentration. As discussed, the relation of H/C ratios and HI values for the Patchawarra and Toolachee coals to the inertinite concentrations indicates that these coals contain a relatively hydrogen-rich, aliphatic-rich component. The compositions of the aliphatic constituents in the Cooper Basin pyrolysates are also consistent with the n-alkane distributions in the bitumen extracts. As noted above, the bitumen extracts from these coals are also relatively alkane rich but with relatively alkane rich but with relatively low abundances of n-C20+components.

N o n - a l i p h a t i c constituents

The similarity among the pyrolysate compositions is also observed for the non-aliphatic constituents. The pyrolysates contain the same relative concentrations of substituted benzenes, phenols, and substituted naphthalanes (Figs 11a, b). In addition to these constituents, the pryolysates also contain anomalously high amounts of more unusual species, including abundant trimethyl phenols, methyl phenanthrene and methyl anthracene isomers (usually present only in small concentrations in pyrolysates), biphenyls, fluorine and substituted fluorenes, as well as other aromatic, naphthenoaromatic, and polar compounds (see below).

Cooper Basin: discussion D e g r a d a t i o n a n d alteration

The geological data (Hunt 1989; Hunt & Smyth 1989) indicate that higher plant-derived organic matter was probably the major source of the primary organic deposition. Many of the geochemical parameters, including the petrographic data, also indicate a mainly terrestrial origin for the primary orgnaic matter in the coals. However, the occurrence of moderate amounts of C27steranes, the relatively low pristane/phytane ratios in some of the coals, and the lower hopane/sterane ratios, imply the co-deposition of algal-derived organic material. However, many of the geochemical parameters indicate that much of the primary organic matter has been extensively altered by the effects of oxidation and bacterial/fungal action. The most significant indicator of these processes is the occurrence of high concentrations of

165

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inertinite in all the coals, which is generally characteristic of severe subaerial exposure and oxidation. The compositions of the pyrolysates also appear to indicate severe subaerial oxidation and degradation. The relative concen-

trations of aromatic constituents such as phenanthrene and methyl phenanthrenes in the pyrolysates of these coals are generally much higher than observed in pyrolysates of most coals (e.g. Figs 6a, b). In addition, as noted, the

166

D . J . CURRY E T A L .

pyrolysates also contain, as major components, unusual constituents which are not normally observed in significant amounts in coal bitumens. These compounds include significant amounts of fluorene, methyl fluorenes, a set of isomeric compounds tentatively indentified (on the basis of retention time and mass spectra) as hydroxy-fluorenes (component F1 in Figs l l a , b; see Fig. 13 for the mass spectrum of one of these isomers) and possibly substituted chrysenes. Similar concentrations of these constituents, which generally occur only in low abundances in most coal and kerogen pyrolysates, have also been observed in pyrolysates of high-inertinite coals from the Haltenbanken area of the North Sea (Curry, in prep.). The occurrence of these components, especially the bridged aromatic compounds, in such high relative concentrations may possibly be due to formation by oxidative coupling and crosslinking. The composition of the extractable organic matter from the coals are very similar to that of the pyrolysates and also suggests extensive degradation. The bitumens also contain high relative concentrations of phenanthrene, methyl phenanthrenes, and many of the uncommon higher molecular weight aromatic compounds observed in the pyrolysates (Fig. 9). Even though these compounds are generally present in low abundances in oils and extracts, elevated concentrations of fluorenes have been observed

in severely biodegraded oils and tar mats from the North Sea (S. Larter, pers. comm.). In addition, as noted above, the presence of appreciable concentrations of the C30 rearranged hopane at these relatively low levels of maturity is consistent with an oxidizing depositional environment. The maceral distributions and the compositions of both the pyrolysates and the bitumens imply that the organic matter which formed the Cooper Basin coals was severely oxidized and degraded. The inverse relationships of the H/C ratios and HI values with the concentrations of inertinite (Figs 8a, b) suggest that the values of these parameters were significantly influenced by the same processes which led to the formation of inertinite. In addition, the wide range of Rv(max) values, together with the trend of decrease in measured Rv(max)with increasing HI (Fig. 8c), suggest that the optical properties of the coals were also affected by the same depositional processes which influenced the H/C and HI values. In addition, the abundances of the aromatic species discussed above, especially phenanthrene, methyl phenanthrenes, and fluorene species, decrease relative to the abundances of the normal aliphatic groups with increasing HI values and increasing H/C ratios. However, the co-variation of various parameters such as H/C ratios, maceral composition, Rv(max) values, and HI values is not normally observed in coals (e.g. Powell &

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ALIPHATIC-RICH COALS FROM AUSTRALIA AND NEW ZEALAND Boreham 1991). Together, the interrelationships of these parameters indicate that the oxidation and degradation processes which led to the formation of the inertinite have also been the major control on the abundances and compositions of the thermally labile organic matter in these coals. These parameters all have fairly broad ranges, which implies considerable variability in the degree of alteration among these coals. However, coals in the Yellow sequence generally have the highest H/C ratios and HI values and lowest Rv(max)values, while the coals in the Blue sequence have the lowest H/C and HI values and highest Rv(max)values (Figs 8a, b, c). In addition, in general, the Yellow sequence coals have the lowest, and the Blue sequence coals have the highest, abundances of fluorenes and other unusual aromatic components relative to the normal aliphatic groups in the pyrolysates (Figs l l a , b). These distributions suggest that the extent of oxidation and degradation was the least severe in the Yellow sequence and most severe in the Blue sequence. This differentiation in the severity of degradation implies that the extent of the degradation was in part controlled by sequence-related variations in depositional environments. In this regard, the approximate correlation trends in Figs 8a, b and c are also plots of the severity of degradation of these coals.

Origin o f aliphatic carbon The long-chain aliphatic groups which occur in the pyrolysates and extracts of these coals were probably not part of the primary (i.e. originally deposited) terrestrial organic matter. As noted above, the severe degree of degradation indicates that the primary organic matter has been extensively altered. In addition, the relative compositions of the aliphatic constituents of the pyrolysates and extracts are very different from those of other aliphatic-rich terrestrial organic matter, such as the Taranaki Basin coals, Carboniferous paper coals from Indiana (Nip et al. 1989) or Jurassic coals from Svalbard (Khorasani & Michelsen 1991), and in fact more closely resemble the aliphatic distributions observed in microbially derived organic matter. The aliphatic groups in the Cooper Basin coals instead very possibly originated from deposition of lipid-enriched biomass resulting from the extensive alteration and degradation of the coal precursors by microbial action. Bacterial and fungal attack of sedimented organic matter has been demonstrated to significantly increase the

167

lipid-rich biomass in sediments. For example, Fogel et al. (1989) showed that bacterial and fungal action significantly alters the composition of sedimented fragments of Spartina grass in the top 50-100cm of sediment in a Georgia salt marsh. Of special interest was the large increase in the abundance of n-C13 to n-C19 aliphatic groups in the pyrolysates of the Spartina fragments relative to the abundances of aromatic and phenolic compounds and n-C22 to n-C27 aliphatic groups with increasing burial. This distribution is very similar to the distribution of constituents in pyrolysates of the Cooper Basin coals (Figs 12a, b). Other analytical data are consistent with the occurrence of aliphatic carbon derived from microbial activity. For example, the H/C ratios and HI values are much higher than would be expected for inertiniterich, liptinite-poor coals, suggesting the occurrence of a hydrogen-rich constituent in the coals which is apparently too small and too finely dispersed to be readily visible by optical methods, but which may ba a source of labile organic matter. This concept is supported by data from Taylor & Liu (1987), Taylor et al. (1988) and Liu & Taylor (1991). From the results of transmission electron microscopy, they suggest Cooper Basin coals contain a substantial amount (5-15%) of 'alginite and bacterially altered alginite' that is too small to be observed by conventional microscopy. The exact mode of association of this finely divided material (i.e. micro-liptinite) with the other macerals is unclear. Although the association of the micro-liptinite with the inertinite has been suggested (Taylor et al. 1988), this is as yet equivocal. As noted, the decrease in HI values, H/C ratios, and apparent aliphatic content with increasing inertinite content indicates that the inertinite is not particularly enriched in aliphatic groups. Instead, aliphatic-rich micro-liptinite may be dispersed throughout the coal, either as discrete particles too small to be observed by conventional microscopy, as material filling pores in the inertinite, or as thin films and coatings in and on the conventional macerals. Primary algal material co-deposited with the terrestrial organic matter is probably not as significant a source of longer-chain aliphatic groups in these coals. The relatively high pristane/phytane ratios and C29 sterane concentrations imply that there was probably only a limited amount of primary aquatic input. In addition, because aquatic organic matter is more diagenetically labile than terrestrial organic matter, it is unlikely that it would be preserved preferentially during degradation.

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From these data it appears that the aliphatic groups in the Cooper Basin coals originated in the main from biomass generated during the bacterial/fungal degradation of the precursor organic matter of these coals. During the initial stages of degradation, the addition of bacterial biomass would increase the aliphaticity in the coals, but probably not severely affect parameters such as pristane/phytane ratios and Rv(max). However, as the severity of degradation and alteration increased, not only would the secondary aliphaticity be reduced, leading to the observed decrease in aliphatic versus aromatic concentrations in the pyrolysates, but many other indicators of the primary organic input would also be affected. The preservation of the micro-liptinite may be a consequence of the high-latitude, peri-glacial depositional environments. As suggested by Taylor et al. (1989), the cold weather environments may have initially retarded the degradation of the organic matter when the peat was subaerially exposed, and so acted to partially preserve the secondary biomass created during the original degradation process. This model is supported by the data which show that the severity of degradation is qualitatively related to the different depositional sequences. That is, the lesser extent of degradation in the Yellow as compared to the Blue sequence implies that conditions were less harsh during deposition of the Yellow sequence coals. The extent of microbial alteration will depend to a large degree on depositional conditions such as water movement and drainage patterns, vegetation, pH, ell, and fluctuations in the water table, which are generally localized in extent. As a result, the formation of this type of aliphatic-enriched organic matter will probably be controlled more by local than by regional or temporal factors. This type of organic matter can occur in a wide range of geographical settings and ages. However, because the conditions favourable for their formation are localized, the areal and stratigraphic extent of deposits of this type of aliphatic-enriched coal and kerogen will generally be smaller and more discontinuous than those of cuticular or maceral-specific aliphatic-rich coals. In addition, the composition of this type of coal and terrestrial kerogen can vary significantly over very short intervals.

Conclusions (1) The long-chain aliphatic groups in coals and terrestrial kerogens can originate from primary constituents of the precursor plant material and can be incorporated directly

(2)

into the kerogen/coal matrix during early diagenesis. The long-chain aliphatic groups probably occur primarily in liptinitic material, especially cuticular or suberinitic material. The variability in the geochemical parameters such as H/C ratios and HI values is probably in part the result of the incorporation of varying proportions of aliphaticpoor (woody) and aliphatic-rich (cuticular or suberinitic) higher plant fragments. Since the deposition of these coals depends on the occurrence of specific higher plant precursors, their distribution will be restricted by evolutionary and palaeoecological factors. However, because these controlling factors generally operate over wide areas, when they do occur, these types of aliphaticrich coals will tend to have a fairly broad regional or basin-wide distribution. Available data indicate that this type of aliphaticrich coal is generally rare prior to the Mesozoic and occurs most commonly (although by no means exclusively) in southeastern Asia, Australia, and New Zealand. It is proposed to term this type of organic matter 'Type IIIC' (for cuticular and cork). This classification term is similar to the terminology proposed by Horsfield (1984), although the proposed mechanism for the incorporation of long-chain aliphatic groups into the coals and kerogens is substantially different from the mechanism suggested there. The long-chain aliphatic groups in coals can also originate from lipid-rich, microbially derived organic matter. As shown by the Cooper Basin coals, long-chain aliphatic groups derived from bacterial biomass can originate as secondary products during the early stages of diagenesis and have little relation to the primary organic input. Longchain aliphatic groups can also be the result of primary co-deposition of aquatic organic matter concomitant with the deposition of the terrestrial material. Since the formation of this type of aliphatic-enriched coal is controlled mainly by localized depositional conditions, these coals can occur in a wide variety of geographical and stratigraphical settings. However, their occurrences within an area will be more localized than Type IIIC coals due to the specialized conditions required for their deposition and preservation. In addition, because of the transitory character of their depositional environments, the compositions of these coals will tend to be much more variable than Type IIIC coals. It is proposed to term this type

ALIPHATIC-RICH COALS FROM A U S T R A L I A AND NEW Z E A L A N D o f o r g a n i c m a t t e r ' T y p e I I I M ' (for microbial origin). (3) In a d d i t i o n , b o t h t h e s e processes ( i . e . deposition of aliphatic-enriched macerals a n d o f lipid-rich microbial biomass) can o c c u r s i m u l t a n e o u s l y in the s a m e d e p o s i t i o n a l setting. (4) T h e r e l a t i o n s h i p of aliphatic c o m p o s i t i o n to specific p r e c u r s o r s a n d / o r specific d e p o sitional c o n d i t i o n s also implies t h a t m a n y coals will n o t c o n t a i n high c o n c e n t r a t i o n s o f long-chain aliphatic groups and will n o t be oil p r o n e .

169

We would like to thank Steve Oliveri, Jill Kerr, and Norma Booher for their technical support. Lisa Hering and Jan Herbst provided computer support and assistance with drafting. Tom Loutit obtained the samples of the Taranaki Basin coals and shales from the New Zealand Geological Survey. We thank Brian Burns of Esso Australia and Erik Sandvik of EPR who provided valuable discussions and suggestions. We would also like to thank Brian Horsfield and an anonymous reviewer for their helpful critiques of an earlier version of this work. We thank Exxon Production Research Company, Esso Australia Ltd, and Delhi Petroleum Company and their partners for permission to publish this work.

Appendix Table 1.

Sample identification and stratigraphy

Taranaki Basin

Cooper Basin

Well

Sample no.

Depth (ft)

Lith.

Well

Sample no.

Depth (ft)

Lith.

Unit

Symbol

Mangahewa-1

112255A 112255B 112255C 112255D 112255E 112255F 112255G 112255H 1122551 112255J 112255K 112255L 112255M

11802 11803.8 11804.5 11805.5 11806.5 11807.5 11808 11808.5 11809.5 11810 11811 11811.85 11812

S S C C C S C C C C C S S

Gidgealpa-5

131384A 131384B 131384C 131384D 131384E 131384F 131384G 131384H 1313841

7061 7064.67 7103 7113 7129.67 7134.67 7137.92 7171.5 7192.33

C C C S CS C SS CS C

Yellow Yellow Intra-Yel YelSilt Blue Blue Blue Sand Intrablue Red

Y Y iY Yd B B Bs iB R

Gidgealpa-6

112266A 112266B 112266C 112266D 112266E 112266F 112266G 112266H 1122661 112266J 112266K 112266L 112266M 112266N 1122660

13261.5 13269.25 13271.5 13272.5 13273.5 13275.3 13276.5 13280.5 13283.5 13289 13292.8 13293.8 13294.5 13302.68 13305

S C S CS C S CS S S S S C C S S

131395A 131395B 131395C 131395D 131395E 131395F 131395G 131395H 1313951 131395J 131395K 131395L 131395M

7176 7380.25 7421.83 7429 7440.67 7464.75 7482.5 7489 7515 7516 7529.5 7535.5 7543

C C C C C C C C S S S C C

Toolachee Intrabrown Intrabrown Intrabrown Yellow Intra-Yel Blue Blue Blue Sand Blue Silt Blue Sand Red Red

T iE iE iE Y iY B B Bs Bd Bs R R

Kapuni

Lithology - C: Coal (TOC > 50%); CS: Carbonaceous shale (25 < TOC < 50%); S: Shale (TOC < 25%); SS: Sandstone.

13261.5 13269.25 13271.5 13272.5 13273.5 13275.3 13276.5 13280.5 13283.5 13289 13292.8 13293.8 13294.5 13302.68 13305

Kap-1

S C S CS C S CS S S S S C C S S

S S C C C S C C C C C S S

Lith.

52.6 71.0 86.2 89.8 72.2

0.59 0.58 0.53 0.57 0.63

0.56 0.59

84.7

0.66

0.70

85.0 89.4 86.9 83.2

66.7 66.7 87.0 89.7 91.7 92.1 88.8 90.5 92.4 87.2 91.1

% Vitr

0.57 0.60 0.63 0.66

0.56 0.55 0.60 0.70 0.70 0.72 0.70 0.74 0.73 0.70 0.63

Total

0.59 0.62 0.65 0.69

0.64 0.74 0.73 0.75 0.73 0.77 0.75 0.71 0.65

Telovitr

R~(%)

46.8 19.4 12.1 10.0 16.7

12.0

12.1 10.0 12.5 16.6

28.6 22.2 12.1 5.4 4.7 4.7 7.0 5.4 4.1 7.7 7.7

% Lipt

0.6 9.7 1.7 0.3 11.1

3.3

2.8 0.6 0.6 0.2

4.8 11.1 1.0 4.9 3.6 3.2 4.2 4.1 3.5 5.1 1.1

% Inert 7061 7064.67 7103 7113 7129.67 7134.67 7137.92 7171.5 7192.33 7176 7380.25 7421.83 7429 7440.67 7464.75 7482.5 7489 7515 7516 7529.5 7535.5 7543

Gid-6

Depth (ft)

Gid-5

Well

Cooper Basin

Note: Maceral compositions normalized to 100% ; vitrinite reflectance measured as Rv (max).

11802 11803.8 11804.5 11805.5 11806.5 11807.5 11808 11808.5 11809.5 11810 11811 11811.75 11812

Man-1

Well

Depth (ft)

Taranaki Basin

Table 2. Vitrinite reflectance and maceral composition

C C C S CS C SS CS C

Lith.

0.98 0.97

0.96 37.0 35.3

38.1 34.2 38.7 33.8 34.3 59.0 46.2 24.3

39.9 31.1

0.91 0.89 0.85 0.83 0.87 0.88 0.89 0.83 0.86 0.96

11.1 3.5

29.3 41.9

2.6 5.3

3.8 5.3 6.2 4.3 3.8 5.8 5.1 6.6

8.5 18.3

8.8 8.1 7.2

% Lipt

41.1 39.7 50.4

% Vitr

0.83 0.86 0.82 0.85 0.85 0.90

Rv(%)

60.5 59.4

58.1 60.5 55.2 61.9 61.9 35.2 48.7 69.1

51.6 50.6

59.6 54.7

50.1 52.2 42.4

% Inert

171

A L I P H A T I C - R I C H COALS F R O M A U S T R A L I A A N D N E W Z E A L A N D

Table 3. Elemental composition and Rock-Eval data Rock-Eval

Elemental data Well

Depth (ft)

Taranaki Basin Man-1 11802 11803.8 11804.5 11805.5 11806.5 11807.5 11808 11808.5 11809.5 11810 11811 11811.75 11812 Kap-1

13261.5 13269.25 13271.5 13272.5 13273.5 13275.3 13276.5 13280.5 13283.5 13289 13292.8 13293.8 13294.5 13302.68 13305

%C

3.12 3.64 68.68 79.56 80.19 21.46 80.11 80.19 78.98 78.77 73.56 5.10 2.66 1.67 64.67 14.11 42.53 77.62 2.41 43.37 1.02 1.44 12.45 3.86 74.66 59.59 5.21 4.31

H/C

O/C

0.964 0.849 0.813

0.104 0.095 0.113

0.824 0.813 0.820 0.842 0.896

0.106 0.094 0.101 0.097 0.112

0.991

0.109

1.061 0.826

0.161 0.000

1.010

0.146

0.993 0.942

0.125 0.157

Cooper basin 7061 Gid-5 7064.67 7103 7113 7129.67 7134.67 7137.92 7171.5 7192.33

62.91 77.65 78.36 8.54 48.74 62.77 0.63 47.58 57.20

0.757 0.756 0.775 1.335 0.726 0.715

0.112 0.102 0.100 0.536 0.103 0.122

0.797 0.789

0.126 0.114

7176 7380.25 7421.83 7429 7440.67 7464.75 7482.5 7489 7515 7516 7529.5 7535.5 7543

68.79 75.75 69.47 65.98 75.24 51.38 74.30 52.17 0.50 1.94 1.03 68.40 75.36

0.727 0.700 0.725 0.773 0.601 0.827 0.738 0.665

0.139 0.096 0.104 0.108 0.109 0.173 0.078 0.128

0.674 0.645

0.124 0.103

Gid-6

Tma x

S1

$2

$3

HI

438 439 437 433 436 434 436 433 434 434 434 433 434

0.52 0.49 16.87 10.34 10.20 4.14 11.11 9.23 9.64 9.65 11.02 1.00 0.61

7.58 8.53 204.10 190.84 191.11 46.86 198.38 185.17 186.66 174.12 212.27 15.82 5.28

0.11 0.19 3.84 4.22 5.75 1.43 5.45 6.09 6.25 6.81 4.71 0.35 0.34

243 234 319 250 254 218 256 242 247 236 304 310 198

425 430 437 435 432 434 431 438 434 431 431 430 426 433 430

0.24 19.01 2.01 6.82 10.94 0.27 5.88 0.11 0.19 2.08 0.68 14.07 10.00 0.65 0.54

2.89 212.24 51.44 129.61 240.54 4.13 115.78 1.28 1.97 43.22 10.80 271.84 177.21 14.50 9.55

0.49 3.60 0.83 2.45 4.05 0.28 2.96 0.37 0.46 0.43 0.30 3.61 3.13 0.53 0.80

173 361 365 320 331 171 292 125 137 347 280 362 302 278 222

437 439 439 440 439 441 450 441 440

11.3 19.7 18.9 1.44 9.63 13.8 0.14 8.48 14.4

127.50 144.10 165.80 7.13 61.37 100.30 0.21 63.15 112.80

3.74 5.29 4.60 0.33 2.01 3.73 0.01 2.18 2.75

195 189 221 86 116 154 33 125 199

440 442 440 441 442 442 441 444 443 451 356 447 445

12.4 14.8 15.2 12.5 9.62 9.61 10.1 8.62 0.69 0.23 0.23 9.71 10.00

89.65 98.40 112.50 106.60 117.60 152.00 110.50 78.13 0.30 0.65 0.06 79.33 97.67

4.01 4.06 4.54 5.04 5.55 6.19 5.98 2.64 0.04 0.01 0.01 2.95 0.01

132 134 170 159 157 243 154 130 60 34 6 130 133

11802 11803.8 11804.5 11805.5 11806.5 11807.5 11808 11808.5 11809.5 11810 11811 11811.75 11812

13261.5 13269.25 13271.5 13272.5 13273.5 13275.3 13276.5 13280.5 13283.5 13289 13292.8 13293.8 13294.5 13302.68

Kap-1

Depth (ft)

Man-1

Well

GC data

S C S CS C S CS S S S S C C S

S S C C C S C C C C C S S

Lith.

8.19 6.29 8.11 11.01 11.51 9.54 9.62 7.63 9.79 9.17 8.50 9.87 10.38 9.94

7.90 7.82 10.25 12.70 12.29 8.70 10.83 11.24 11.03 11.18 11.01 6.46 4.17

Pris/phy

7.77 2.91 4.03 4.99 6.13 9.46 8.69 6.97 4.06 5.57 6.52 7.65 7.29 6.58

3.31 3.13 3.01 5.73 4.63 2.95 5.65 7.48 8.03 8.2 9.97 3.81 2.00

Pris/C17

1.11 0.68 0.66 0.57 0.66 1.00 1.12 0.91 0.5 0.72 0.98 0.97 0.74 0.74

0.41 0.39 0.33 0.45 0.37 0.37 0.5 0.65 0.66 0.67 0.82 0.5 0.36

Phy/Cla

Table 4a. Taranaki Basin coals and shales GC and biomarker ratios

1.59 1.59 1.57 1.60 1.61 1.68 1.6 1.56 1.44 1.66 1.75 1.54 1.61 1.54

1.29 1.39 1.83 1.63 1.52 1.59 1.36 1.58 1.43 1.42 1.66 1.46 1.31

CPI

2.50 1.48 2.44 3.77 3.85 3.23 3.14 2.44 2.45 2.77 1.93 3.33 3.13 2.69

2.32 2.01 1.51 1.73 2.43 0.72 2.09 2.01 2.78 2.62 2.35 2.33 1.84

C27/C17

0.735 0.569 0.608 0.679 0.671 0.673 0.692 0.653 0.625 0.660 0.608 0.704 0.690 0.689

0.621 0.547 0.438 0.455 0.549 0.374 0.524 0.546 0.546 0.542 0.538 0.617 0.527

% nC25_34alkanes

to

12.809 8.220 8.408 8.558 9.962 11.330 11.608 13.434 6.989 13.541 14.829 3.239 3.704

3.135 3.608

11802 11803.8 11804.5 11805.5 11806.5 11807.5 11808 11808.5 11809.5 11810 11811 11811.75 11812

13261.5 13269,25 13271.5 13272.5 13273.5 13275.3 13276.5 13280.5 13283.5 13289 13292.8 13293.8 13294.5 13302.68

Man-1

Kap-1

4.523 6.452 3.309 7.322 3.910 5.578

6.202 10.788 6.688 6.918

5.159

Hopanes/ steranes

Well

Depth (ft)

Biomarker ratios

0.251 0.522 0.117 0.161 0.116 0.101 0.045 0.133 0.091 0.147 0.127 0.274 0.054

1.101 0.992 0.846 0.826 0.759 1.052

0.052 0.075 0.073 0.062 0.027 0.026 0.027 0.023 0.042 0.035 0.054 0.275 0.177

0.750 0.831 0.803 0.817 0.841 1.298 0.851

0.967 0.994 0.916 0.891 0.885 0.9o3 0.816 0.877 0.769 0.763 0.852 0.898 0.845

C29/C3o Cao

Olean/

0.379 0.395 0.373 0.397 0.414 0.372

0.351 0.447 0.411 0.429 0.437 0.380 0,444

0.222 0.243 0.232 0.307 0.331 0.320 0.285 0.350 0.314 0.307 0.315 0,303 0.313

CaoM/ C3oH

1.043 1.355 0.938 2.162 1.676 1.035

0.942 0.995 1.089 1.676 1.825 0.818 1.771

0.987 1.097 1.134 1.099 1.235 1.295 1.339 1.693 2.180 2.284 2.302 1.249 1.372

C31S+ R/ C3o

Triterpanes (M/Z 191)

0.518 0.474 0.600 0.340 0.398 0.579

0.580 0.627 0.514 0.412 0.396 0.706 0.391

0.577 0.547 0.523 0.574 0.523 0.501 0.490 0.410 0.336 0.327 0.325 0.475 0.426

C3oH/ ext'd hop

0.422 0.428 0.363 0.544 0.497 0.361

0.416 0.348 0.437 0.455 0.472 0.290 0.478

0.449 0.451 0.494 0.433 0.443 0.473 0.509 0.510 0.613 0.612 0.601 0.469 0.499

Ext'd/total hopanes

0.863 0.944 0.918 0.878 1.000 1.000

0.960 0.893 0.908 0.802 0.788 0.895 0.880

1.000 0.924 0.868 0.851 0.894 0.899 0.922 0.880 0.910 0.898 0.910 1.000 0.919

0.29o 0.505 0.382 0.392 0.475 0.474

0.405 0.473 0.408 0.521 0.790 0.457 0.401

0.669 0.397 0,433 0,451 0.463 0.443 0.380 0.504 0.412 0.488 0.425 0.435 0.588

C29/total C290(0/0t5/ C29o(o~og5-t- R

steranes

o.596 0.702 0.614 0.649 0.517 0.571

0.492 0.589 0.665 0.725 0.561 0.634 0.667

0.440 0.684 0.623 0.653 0.649 0.685 0.640 0.656 0.666 0.653 0.669 0.540 0.421

total C29

C290/0t0/8+ R/

Steranes (M/Z 217)

o.566 0.604 0.486 0.609 0.596 0.515

0.450 0.578 0.585 0.584 0.463 0.537 0.600

0.812 0.589 0.660 0.667 0.679 0.725 0.699 0.715 0.792 0.848 0.643 0.553 0.497

C29 regl/ reg + dia

-.a

7061 7064.67 7103 7113 7129.67 7134.67 7137.92 7171 7192

7176 7380.25 7421.83 7429 7440.67 7464.75 7482.5 7489 7515 7516 7529.5 7535.5 7543

Gid-5

Gid-6

Well

Depth (ft)

C C C C C C C C S S S C C

C C C S CS C SS CS C

Lith.

3.97 4.16 3.61 4.81 4.06 5.35 2.85 2.43 . 0.82 . 2.04 2.84

4.27 4.81 3.58 2.15 2.75 4.83 1.42 4.09 4.62

Pris/phy

.

.

0.38 0.46

0.40

0.65 0.50 0.56 0.68 0.71 1.00 0.30 0.51

0.66 0.46 0.39 0.37 0.52 0.85 0.48 1.30 0.66

.

.

Pris/C17

0.17 0.13 0.18 0.15 0.19 0.19 0.11 0.21 . 0.45 . 0.20 0.18

0.16 0.10 0.11 0.19 0.20 0.19 0.33 0.33 0.15

Phy/Cla

.

.

Table 4b. Cooper Basin coals and shales GC and biomarker ratios

GC data

1.09 1.07

1.10

1.07 1.08 1.12 1.16 1.03 1.09 1.08 1.09

1.14 1.16 1.09 1.11 1.06 1.07 1.02 1.10 1.11

.

.

CP- 1

0.269 0.151

0.242

0.317 0.322 0.213 0.305 0.304 0.364 0.205 0.237

0.334 0.169 0.255 0.203 0.284 0.325 0.463 0.345 0.319

C27/C17

nC25_34alkanes

0.169 0.120

0.221

0.196 0.212 0.160 0.174 0.192 0.208 0.138 0.158

0.196 0.118 0.170 0.155 0.187 0.197 0.296 0.203 0.179

%

4~

7061 7064.67 7103 7113 7129.67 7134.67 7137.92 7171.5 7192.33

7176 7380.25 7421.83 7429 7440.67 7464.75 7482.5 7489 7515 7516 7529,5 7535.5 7543

Gid-6

Depth (ft)

Gid-5

Well

Biomarker ratios

4.306 3.741 4.007 3.857 3.895 3.822 4.712 4.493 1.613 1.697 2.093 0.956 7.510

4.620 3.878 4.302 3.986 5.947 3.722 2.242 4.170 5.513

Hopanes/ steranes

0.034 0.052 0.054 0.052 0.053 0.080 0.084 0.073 0.326 0.656 0.096

0.049 0.059 0.152 0.127 0.096 0.083 0.502 0.063 0.396

C27Ts/C27TM

0.673 0.626 0.642 0.638 0,590 0.535 0.572 0.658 0.497 0.832 0.614 0.540 0.626

0.741 0.655 0.545 0.786 0.607 0.610 1.124 0.663 0.482

C29I~C30H

0.065 0.083 0.060 0.056 0.055 0.054 0.093 0.064 0.000 0.074 0.073 0.000 0.063

0.072 0.063 0.050 0.070 0.054 0.055 0.062 0.074 0,070

C3oM/C3oH

Triterpanes (M/Z 191)

0.991 0.943 1.012 0.960 0.885 0.756 0.824 0.844 0.690 0.762 0.680 1.118 0.819

1.040 0.883 0.680 0.782 0.675 0.838 0.861 0.850 0.453

C31S + R/ C3o H

0.461 0.440 0.464 0.456 0.443 0.427 0.434 0.417 0.414 0.367 0.389 0.731 0.437

0.444 0.423 0.410 0.397 0.360 0.433 0.411 0.425 0.333

Ext'd hop/ tot. hop

0.402 0.419 0.450 0.421 0.422 0.491 0.475 0.464 0.676 0.417 0.524 0.490 1.000

0.439 0.458 0.467 0.463 0.404 0.455 0.441 0.455 0.535

C29aotaS/ S+ R

0.876 0.792 0.784 0.861 0.910 0.816 0.842 0.666 3.378 1.185 1.788 0.927 0.647

0.790 0.614 1.395 0.718 0.760 0.801 0.898 0.843 0.696

C29t~ott~Sdia/ reg steranes

Steranes (M/Z 217)

0.497 0.506 0.486 0.476 0514 0.475 0.445 0.449 0.280 0.435 0.356 0.517 0.418

0.484 0.501 0.412 0.466 0.526 0.482 0.473 0.469 0.528

Total C29/ total ster

-,,,,I

Lith.

S S C C C S C C C C C S S

S C S CS C S CS S S S S C C S

11802 11803.8 11804.5 11805.5 11806.5 11807.5 11808 11808.5 11809.5 11810 11811 11811.75 11812

13261.5 13269.25 13271.5 13272.5 13273.5 13275.3 13276.5 13280.5 13283.5 13289 13292.8 13293.8 13294.5 13302.68

Man-1

Kap-1

Well

Depth (ft)

0 178 77 0 67 454 141 1618 0 0 358 0 15

5670 10745 10528 13133 4157 6380

0 50 170 1261 227 251 0 193 0 0 217 0 0

?W*

6865 3778 9123 8077 10287 7072 15002

1727 4865 13653 19650 11072 14719 25893 11674 19725 24575 21506 2360 2013

Total hopanes

Triterpanes (ppm saturate fraction): M/Z 191

1022 2107 2951 2212 740 1717

1318 1057 1927 2002 2326 1870 3314

290 1001 2445 4546 2588 2920 4424 2196 2672 3149 3008 461 399

C27H + ? T ?

261 252 586 591 357 101

604 659 329 374 351 236 211

0 73 374 440 72 106 112 65 88 100 202 131 73

R

Table 5a. Taranaki Basin coals and shales quantitative biomarker data

870 356 725 505 645 729 884

1242 684 1645 1240 1619 1875 2388

417 1012 954 805 390 466

130 188 418 740 455 578 1189 528 550 1136 672 161 113

432 1191 3231 4350 2272 3145 5268 2142 3127 3749 3578 472 362

1366 2163 1941 2004 623 1401

C29M

C29H

165 198 337 309 225 73

416 430 239 244 223 147 125

23 90 259 301 70 89 177 56 172 173 226 144 76

Olean

1241 2180 2295 2428 821 1332

1657 823 2048 1517 1925 1445 2806

447 1199 3526 4883 2567 3484 6453 2443 4067 4913 4198 525 428

C3o H

471 860 857 964 340 496

582 368 842 651 841 550 1246

99 291 820 1500 849 1116 1840 855 1276 1508 1322 159 134

C3o M

1295 2955 2151 5247 1376 1378

1560 819 2231 2542 35130 1182 4968

441 1316 3999 5368 3171 4512 8644 4137 8864 11223 9666 656 587

C31 (S + R)

Ext'd

2395 4603 3825 7148 2065 2301

2854 1313 3983 3678 4856 2048 7169

775 2194 6740 8514 4909 6959 13172 5954 12100 15034 12927 1107 1005

triterp

13261.5 13269.25 1327.5 13272.5 13273.5 13275.3 13276.5 13280.5 13283.5 13289 13292.8 13293.8 13294.5 13302.68

Kap-1

471 124 226 110 87 133 294

161 103 395 170 106 187

1254 1665 3181 1794 1063 1144

0 53 108 203 111 57 57 35 97 0 57 131 87

D29

2190 1047 1768 1302 954 1058 2169

135 592 1624 2296 1111 1299 2231 869 2822 1815 1450 729 543

Total steranes

102 97 307 140 82 178

212 118 171 110 61 83 157

25 36 93 0 17 49 106 40 221 0 127 83 62

D29

106 337 333 244 156 159

189 151 255 231 154 147 306

32 87 251 384 203 256 349 181 558 441 241 95 61

29aaaS

247 283 548 336 306 253

481 222 315 168 153 186 382

61 102 350 452 237 267 517 188 679 480 280 186 144

29aflflR + S

259 330 539 379 172 177

277 168 370 212 41 175 458

16 133 329 467 235 323 571 178 797 461 326 123 43

612 950 1420 959 634 589

946 541 939 610 348 509 1146

109 322 930 1303 675 846 1437 547 2034 1382 848 403 248

C29oto~o~R C29reg/total

*, t U n k n o w n C3o pentacyclic triterpanes (possible ring-contracted oleananes) - (see text).

11802 11803.8 11804.5 11805.5 11806.5 11807.5 11808 11808.5 11809.5 11810 11811 11811.75 11812

Depth (ft)

Man-1

Well

Steranes (ppm saturate fraction): M/Z 217

470 622 1500 616 430 555

1157 394 666 434 404 438 763

25 225 479 651 319 321 620 218 534 248 472 326 251

C29 dias

1082 1572 2920 1575 1063 1144

2103 935 1606 1045 751 947 1908

135 547 1409 1953 993 1167 2057 765 2568 1631 1319 729 500

C29 reg + dias

7061 7064.67 7103 7113 7129.67 7134.67 7137.92 7171.5 7192.33

7176 7380 7421.83 7429 7440.67 7464.75 7482.5 7489 7515 7516 7529.5 7535.5 7543

Gid-6

Depth (ft)

Gid-5

Well

C C C C C C C C S S S C C

C C C S CS C SS CS C

Lith.

22750 9010 25948 18085 23663 27924 16673 22330 664 2006 2295 2447 12160

20191 13782 23620 9980 17999 13566 3343 13772 9630

Total

76 52 134 87 123 200 125 175 0 64 109 0 126

103 82 291 136 205 111 118 86 267

C27 Ts

2211 994 2359 1677 2296 2492 1478 2405 0 197 167 0 1310

2120 1390 1911 1072 2136 1331 234 1372 674

C27 TM

3530 1343 3904 2810 3540 4157 2494 3694 129 397 378 231 2008

3334 2183 3715 1867 3099 2133 795 2323 1599

C29 H

Table 5b Cooper Basin coals and shales quantitative biomarker distributions

Triterpanes (ppm saturate fraction): M / Z 191

221 113 372 242 287 502 261 387 96 44 101 97 227

223 155 387 132 230 234 22 254 224

C3o D

342 178 364 345 331 418 407 357 0 35 45 0 202

324 212 341 166 278 193 44 259 234

C29M

5245 2145 6083 4401 6000 7767 4358 5613 260 476 615 428 3206

4502 3332 6820 2375 5104 3497 707 3504 3317

C3o H

868 334 965 621 891 962 572 773 0 101 88 0 0

843 756 865 398 702 423 71 376 330

C3o M

10479 3965 12038 8243 10482 11928 7240 9312 275 735 892 1788 5309

8966 5828 9676 3966 6475 5878 1373 5852 3211

Ext'd hopanes

7061 7064.67 7103 7113 7129.67 7134.67 7137.92 7171.5 7192.33

7176 7380.25 7421.83 7429 7440.67 7464.75 7482.5 7489 7515 7516 7529 7535.5 7543

Gid-6

Depth (ft)

Gid-5

Well

5283 2409 6475 4688 6075 7306 3538 4969 412 1182 1096 2560 1619

4370 3554 5491 2504 3026 3645 1491 3302 1747

Total

2623 1219 3145 2231 3125 3468 1576 2232 115 514 390 1324 676

2117 1782 2263 1166 1591 1756 705 1548 992

Total C29

Steranes (ppm saturate fraction): M/Z 217

570 232 627 482 689 782 449 487 121 135 204 342 243

450 312 921 225 300 380 161 366 219

C29 dias

530 229 613 436 539 645 369 561 38 108 130 278 200

428 317 710 191 241 409 137 377 166

C29 dias

585 264 816 524 637 933 522 540 69 61 120 194 0

403 338 506 318 440 388 0 338 159

C29 dias

650 293 800 560 757 959 533 732 36 114 114 369 375

570 508 661 314 394 475 179 434 314

29aaa-S

609 302 749 531 1331 824 453 655 39 241 172 571 301

499 373 501 440 355 405 179 333 335 397 218 620 369 0 692 0 0 23 0 0 0 0

319 298 348 49 262 309 120 260 0

29a/3/3-R 29aflfl-S

967 406 977 771 1037 994 589 846 17 159 104 384 0

729 602 753 364 581 568 227 520 273

29aoea-R

180

D. J. CURRY ET AL.

Table 6. Explanation of symbols

Symbol

Explanation

Symbol

I. Total extract and saturate fraction chromatograms n-Cx normal alkane or alkene with x carbon atoms PR pristane PH phytane Me-Naph methylated naphthalene homologues C1-NAPH methyl naphthalene C2-NAPH dimethyl naphthalenes PHEN phenanthrene C1-PHEN methyl phenanthrenes II. Steranes (mlz 217 mass fragmentograms) STD internal standard C29D C29diasterane isomers T triterpane T (see text) C29 C29 regular sterane isomers C29H C29 regular hopane

Explanation

III. Triterpanes (m/z 191 mass fragmentograms) Cx regular hopane with x carbon atoms OL oleanane T triterpane T (see text) R C3o triterpane X C30 diahopane ('Compound X') IV. Pyrolysis-gc/ms total ion current and selected ion chromatograms X n-alkene/alkane pair with x carbon atoms A aromatic constituent P polar constituent 1-Pr 1-pristene Me-N methylated naphthalene homologues F1 bridged aromatic species (see text)

References VAN AARSEN, B. G. K., HESSELS, J. K. C., ABBINK, O. A. DE LEEUW,J. W. 1992. The occurrence of polycyclic sesqui-, tri- and oligoterpenoids derived from a resinous polymeric cadinene in crude oils from southeast Asia. Geochimica et Cosmochimica Acta, 56, 1231-1246. BERTRAND, P., BEHAR~ F. & DURAND, B. 1986. Composition of potential oil from humic coals in relation to their petrographic nature. Organic Geochemistry, 10,601-608. COLLEN, J. D., JOHNSTON, J. H., DUNN, P. J. & NEWMAN, R. H. 1988. 13C NMR spectra from Upper Cretaceous and Lower Tertiary coal measures, Taranaki Basin, New Zealand. Geology Board of Studies Special Publication No. 2, Research School of Earth Sciences, Victoria University of Wellington. CURRY, D. J. 1985. Organic geochemistry and oil generation potential of Tertiary coals from the West Natuna Basin, South China Sea. In: Abstracts of the 12th International Meeting on Organic Geochemistry, Julich, Germany. in prep. Geographic and temporal controls on the distribution of potentially oil generative coals. DURAND, B. • ESPITALIE, J. 1976. Geochemical studies on the organic matter from the Doula Basin (Cameroon). If. Evolution of kerogen. Geochimica et Cosmochimica Acta, 40,801-808. & PARATTE, M. 1983. Oil generation potential of coals: a geochemical approach. In: BROOKS, J. (ed.) Petroleum Geochemistry and the Exploration of Europe. Geological Society, London, Special Publication, 12,212-222. FOGEL, M. L., SPRAGUE, E. K., GIZE, A. P. & FREY, R. W. 1989. Diagenesis of matter in Georgia salt marshes. Estuarine, Coastal, and Shelf Sciences, 28,211-230. GRANTHAM, P. J., POSTHUMA, J. & BAAK, A. 1983.

Triterpanes in a number of Far-Eastern crude oils. In: BJOROY, M. et al. (eds) Advances in Organic Geochemistry 1981. John Wiley & Sons, London, 675-683. HEATH, R. 1989. Exploration in the Cooper Basin. Australian Petroleum Exploration Association Journal, 29,366-378. HORSFIELD, B. 1984. Pyrolysis studies and petroleum exploration. In. BROOKS, J. & WELTE, D. H. (eds). Advances in Petroleum Geochemistry (Volume 1). Academic Press, London, 247-298. --, YORDY, K. L. & CRELLING, J. C. 1988. Determining the petroleum-generating potential of coal using organic geochemistry and organic petrology. Organic Geochemistry, 13, 121-129. HUC, A. Y., DURAND, B., ROUCACHET,J., VANDENBROUCKE,M. & PIWrION,J. L. 1986. Comparison of three series of organic matter of continental origin. Organic Geochemistry, 10, 65-72. HUNT, J. W. 1989. Permian coals of eastern Australia: geological control of petrographic variation. International Journal of Coal Geology, 12, 589634. -& SM'crH, M. 1989. Origin of inertinite-rich coals of Australian cratonic basins. International Journal of Coal Geology, 11, 23-46. ISAKSEN, G. H. 1991. Molecular indicators of lacustrine freshwater environments. In: MANNING, D. (ed.) Organic Geochemistry: Advances and Applications in Energy and the Natural Environment (15th Meeting of the European Association of Organic Geochemists Poster Abstracts). Manchester Press, Manchester, 361-364. JENKINS,C. C. 1989. Geochemical correlation of rocks and crude oils from the Cooper and Eromanga Basins. In: O'NEILL, B. J. (ed.) The Cooper and Eromanga Basins. Proceedings of Petroleum

A L I P H A T I C - R I C H COALS F R O M A U S T R A L I A AND NEW Z E A L A N D Exploration Society of Australia, Society of Petroleum Engineers, Australian Society of Exploration Geophysicists (SA Branches), Adelaide, 525-540. JOHNSTON, J. H., COLLIER, R. J. & MAIDMENT,A. I. 1991. Coals as source rocks for hydrocarbon generation in the Taranaki Basin, New Zealand: a geochemical biomarker study. Journal of Southeast Asian Earth Sciences, 5,283-289. KHORASANI, G. K. & MICHELSEN, J. K. 1991. Geological and laboratory evidence for early generation of large amounts of liquid hydrocarbons from suberinite and suberous components. Organic Geochemistry, 17,849-863. KING, P. R. & ROBINSON, P. H. 1988. An overview of Taranaki region geology, New Zealand. Energy Exploration and Exploitation, 6, 213-232. LIu, S. Y. & TAYLOR, G. H. 1991. TEM observations on Type III kerogen, with special reference to coal as a source rock. Journal of Southeast Asian Earth Sciences, 5, 43-52. MOLDOWAN, J. M., FAGO, F. J., CARLSON, R. M. K., YOUNG, D. C., DUYNE, G. V., CLARDY, J., SCHOEL, M. , PILLINGER, C. T. & WATT, D. S. 1991. Rearranged hopanes in sediments and petroleum. Geochimica et Cosmochimica Acta, 3333-3353. NIP, M., DE LEEUW, J. W., HOLLOWAY,P. J., JENSEN, J. P. T., SPRENKELS,J. C. M., DE POOTER, M. & SLEECKX, J. J. M. 1987. Comparison of flash YcrOlysis, differential scanning calorimetry, NMR and IR spectroscopy in the analysis of a highly aliphatic biopolymer from plant cuticles. Journal of Analytical and Applied Pyrolysis, 11, 287-295. - - , SCHENK,P. A., WINDtG, W., MEUZELAAR, 'H. L. C. & CRELLING, J. C. 1989. A flash pyrolysis and petrographic study of cutinite from the Indiana paper coal. Geochimica et Cosmochimica Acta, 53,671-683. , TEGELAAR, E. W., BRINKHUIS,H., DE LEEUW, J. W., SCHENK,P. A. t~ HOLLOWAY,P. J. 1986. Analysis of modern and fossil plant cuticle by Curie point pyrolysis gc and Curie point pyrolysis gc/ms: Recognition a new, highly aliphatic and resistant biopolymer. Organic Geochemistry, 10, 769-778. PILAAR,W. H. F. & WAKEFIELD,L. L. 1978. Structural and stratigraphic evolution of the Taranaki Basin, offshore North Island, New Zealand. Australian Petroleum Exploration Journal, 18, 93-101. & ~ 1984. Hydrocarbon generation in the Taranaki Basin, New Zealand. In: DEMAISON,G. & MURRIS, R. J. (eds) Petroleum Geochemistry and Basin Evaluation American Association of Petroleum Geologists, Memoir 35,405-423. POCKNALL, D. T. 1990. Palynological evidence for early to middle Eocene vegetation and climate 55,

-

-

181

history of New Zealand. Review of Paleobotany and Palynology, 65, 57-69. POWELL, T. J. • BOREHAM, C. J. 1991. Petroleum generation and source rock assessment in terrigenous sequences: an update. Australian Petroleum Exploration Association Journal, 31, 297-311. - - , SMYTH,M., RUSSELL,N. & COOK, A. C. '1991. Petroleum source rock assessment in nonmarine sequences: pyrolysis and petrographic analysis of Australian coals and carbonaceous shales. Organic Geochemistry, 17,375-394. RAMANAMPISOA, L., RADKE, M., SCHAEFER, R. G., LITKE, R., RULLKOTTER, J. & HORSFIELD, B. 1989. Organic-geochemical characterisation of sediments from the Sakoa coalfield, Madagascar. Organic Geochemistry, 16, 235-246. SANDVIK,E. I., YOUNG,W. A. & CURRY,D. J. 1992. Expulsion from hydrocarbon sources: the role of organic absorbtion. Organic Geochemistry, 19, 77-88. SHANMUGAM,G. 1985. Significance of coniferous rain forests and related organic matter in generating commercial quantities of oil, Gippsland Basin, Australia. American Association of Petroleum Geologists Bulletin, 69, 1241-1254. SMITH, J. W., GILBERT, T. D. & BATTS, B. D. 1987. A quest for a new parameter in petroleum exploration geochemistry. Australian Petroleum Exploration Journal, 27, 98-105. TAYLOR, G. H. & LIU, S. Y. 1987. Biodegradation in coals and other organic-rich rocks. Fuel 66, 1269-1273. & DIESSEL, C. F. K. 1989. The cold climate origin of inertinite-rich Gondwana coals. International Journal of Coal Geology, 11, 1-22. & SMVTH,M. 1988. New light on the origin of Cooper Basin oil. Australian Petroleum Exploration Association Journal, 28,303-309. TEERMAN, S. C. & HWANG, R. J. 1989. Evaluation of the source rock potential of Sumatran coals by artificial maturation. Proceedings of the 18th -

-

-

-

Indonesian Petroleum Association Convention. Indonesian Petroleum Association, Jakarta, 469-489. TEGELAAR, E. W., DE LEEUW, J. W., LARGEAU,C., DERENNE, S., SCHULTEN, H.-R., MULLER, R., BOON, J., NIP, M. & SPRENKELS,J. C. M. 1989. Scope and limitations of several pyrolysis methods in the structural elucidation of a macromolecular plant constituent in the leaf cuticle of

Agave americana L. Journal of Analytical and Applied Pyrolysis, 15, 29-54. THOMAS, B. M. 1982. Land plant source rocks for oil and their significance in Australian basins.

Australian Petroleum Exploration Association Journal, 22,164-176. TISSOT, B. P. & WELTE, D. H. 1984. Petroleum Formation and Occurrence. Springer Verlag, Berlin.

The oil potential of Mid-Jurassic coals in northern Egypt MARK

A. BAGGE

& MARTIN

L. K E E L E Y

Intera Information Technologies Ltd, Highlands Farm, Greys Road, Henley-on-Thames, Oxfordshire R G 9 4PS, UK

Abstract: Geochemical analysis of selected coals indicates that some of the Jurassic coals in Egypt have oil-generating potential. Other coals have just gas potential, but may have already generated oils as they are now post-mature for oil generation. Petrographic analysis of the coals reveals a composition dominated by vitrinite, but with variable liptinite contents and the occurrence of fluorescent vitrinite in some coals. It is not clear which components of the coal are responsible for the oil potential; it is probable that liptinite, hydrogen-rich vitrinites and a fine-grained groundmass of algal origin all contribute. A combination of Rock-Eval Hydrogen Indices and pyrolysis-gc P2 fingerprints provides the best method for determination of the oil- or gas-prone nature of the coals. Attempts at correlating oils to source rock extracts illustrate the problem of oil-source correlations involving a rapidly varying source rock environment. The bitumen extracts from the coals reveal variable characteristics which reflect facies variations in the coals. Several of the coals have unusual saturated hydrocarbon and biological marker distributions that are atypical of humic coals and give a poor correlation to the waxy oils from the Meleiha field. The best oil-source rock correlation is with a carbonaceous shale, not a coal, but it is likely the oils were derived from large volumes of source rock including coals and carbonaceous shales. As the coals have unusual extract characteristics, any oils derived from a more localized environment in the coal swamp may show very unusual geochemical characteristics, and would not be recognized immediately as being derived from terrestrial coals.

Jurassic coals in Egypt were first recognized by Barthoux & Douvill6 (1913) at outcrop in the northern Sinai Peninsula, within the Gebel el Maghara d o m e (Fig. 1). The subsurface of this region has since been thoroughly explored, and coal is now being mined. Khatatba-1, the second oil well in Egypt outside of the Gulf of Suez, drilled by Standard Oil in 1944-45 encountered Jurassic coals. This well became the type well for subsequent reference to mid-Jurassic clastics, even though all the original cuttings have long since been consumed, and no electric logs were obtained. In the western part of the Western Desert of Egypt, several oil fields including Meleiha, Umbarka, Khalda and Salam produce distinctively waxy paraffinic oils, quite unlike those in the Abu Gharadiq and Gulf of Suez basins to the east. Several attempts were m a d e in the 1980s to ascertain the origin of these oils without definitive results (Abu E1 Naga 1984). The uncertainty arose in part because the only significant concentrations of organic matter present in the Mesozoic/Cenozoic section are the Jurassic coals, but it was assumed that because these coals are dominated by humic kerogens, they are only gas prone. Pyrolysis analyses may have gone some way to support this interpretation but were misleading due to the high maturity of

the Jurassic section in many wells. However, subsequent studies have shown that the Jurassic coal sequence is indeed the source for these oils (Bagge et al. 1988; Keeley et al. 1990). The data presented in this paper illustrate the characteristics of selected mid-Jurassic coals in northern Egypt and the oils derived from the coal sequences. The data also illustrate the difficulties in recognizing oil-prone coals from geochemical data, and establishing whether it is in fact the coals or associated carbonaceous shales that are responsible for generating the associated oils.

Geological setting and stratigraphy Jurassic coals in Egypt are restricted to the area north of 29°30"N. They are found as minor associates along with sandstones and lesser volumes of interbedded siltstone and organicrich mudstones. This association of lithotypes comprises the Safa M e m b e r of the Khatatba Formation, which is entirely of Bathonian age (Keeley et al. 1990) (Fig. 2). In the central and eastern sectors, a distinctive carbonate interval, the Kabrit Member, separates the Safa sands, shales and coals into U p p e r and Lower Members. A continuous Lower Jurassic succes-

From Scott, A. C. & Fleet, A. J. (eds), 1994, Coal and Coal-bearingStrataas Oil-prone Source Rocks? Geological Society Special Publication No. 77, pp. 183-200.

183

184

M. A. BAGGE & M. L. KEELEY

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sion lies beneath, beginning in the Pliensbachian. By contrast, in the western sector, the Sara Member lies at the base of the Jurassic succession, locally overlying and interbedded with volcanics (Keeley et al. 1990). Beneath these Jurassic rocks lie undated red clastics, presumably of Late Triassic age. The onset of Jurassic deposition in this western sector, during a regressive phase, indicates the importance of local tectonics, rather than sea-level changes, to depositional character. The age of onset of a continuous phase of deposition during the Early-Mid-Jurassic on the southern margin of Tethys youngs westwards. This is attributed by Keeley & Wallis (1991) to the propagation of rifting along the northern Egyptian continental margin, originating in Palestine during the Triassic. Sara Member sedimentation took place within this active tectonic setting, along a fluctuating coastline, characterized by a strong northward sediment flux, but in the absence of deltaic outbuilding.

As a consequence, coast-linear shoreface, beach bar and swamp deposits are found alternatively stacked. The coals deposited in this coastal environment were first reported as gas-prone Type III source rocks (Parker 1982). Type II/III source rocks, capable of oil and gas generation were recognized in areas of the coal swamp where hydrogen-rich liptinitic material has been washed into and concentrated in stagnant areas. The liptinitic material comprises cuticle, spores, pollen, resin and algae (Parker 1982). These oilprone source rock facies are locally developed, and were deposited in a lower swamp environment. This environment was characterized by low relief and marine influences, allowing stagnant environments to develop (Figs 3 & 4). In the upper swamp environment to the south, relief was greater, and stagnant conditions did not develop. This environment was more oxic, resulting in the accumulation of humic coals comprising gas/condensate-prone and inert organic matter.

OIL POTENTIAL OF MID-JURASSIC COALS IN N. EGYPT

185

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Evidence for coaly source rocks from oil characteristics The Western Desert oils are high gravity, low sulphur, waxy crudes and are very paraffinic. Gas chromatography of whole oils and Cls+ saturated hydrocarbons indicates large amounts of normal alkanes > C2s with an odd-carbon preference. These compounds are often referred to as 'terrestrial waxes'. A chromatogram of a typical oil from Meleiha is shown in Fig. 5. The odd-carbon preference and the high pristane/ phytane (Pr/Ph) ratios of the oils are characteristic of oils sourced from terrestrial organic precursors. Biological marker distributions are also diag-

nostic of terrestrial organic matter. Fragmentograms of steranes (m/z 217) from the Meleiha oil (Fig. 6) are dominated by C29 regular steranes and diasteranes. The predominance of C29 steranes over C28 and Cz7 steranes is consistent with a terrestrial source for the oils. Terpanes (m/z 191 fragmentogram, Fig. 7) are present in much greater amounts than steranes, a feature usually observed when terrestrial organic matter is the main organic precursor. The hopanes are the dominant series of terpanes and tricyclic terpanes are present in only minor amounts. Two unidentified terpanes that have been described previously in the literature as 'terrestrial indictors' are also present. Most

186

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OIL POTENTIAL OF MID-JURASSIC COALS IN N. EGYPT 100

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Fig. 7. Meleiha oil: Terpane (m/z 191) distribution.

important of these is compound X which elutes just after the C29 norhopane. Philp & Gilbert (1986) observed this compound in many oils sourced from terrestrial organic matter in Australia and tentatively identify it as a C3o pentacyclic terpane. A second 'terrestrial marker', compound Y is present in the Meleiha oils which was also identified in the Australian oils by Philp & Gilbert (1986). This compound elutes just before the 17o~(H)-trisnorhopane (Tm) and is an unidentified C27 terpane. Despite the strong influence of land plant material, 18a(H)-oleanane is absent from the terpane distributions of the Meleiha oils. This compound is often reported to be a terrestrial indicator and has been found in rock extracts from Miocene strata in the Gulf of Suez. 18a(H)-oleanane is derived from angiosperm precursors and has only been reported in Late Cretaceous and Tertiary sediments and their derived oils (Philp & Gilbert 1986; Moldowan et al. 1991). 18a(H)-oleanane is absent in the Meleiha oils as the source rocks are preCretaceous. Data from a second Meleiha oil, produced from a deeper reservoir, are presented in Fig. 8

Initial inspection of the gas chromatogram and terpane distribution suggests the oil is different from the first oil, but all differences can be explained by the higher level of maturity for this second oil. Like the oil from the shallower reservoir, the pristane/phytane ratio is high (>3), and high molecular weight alkanes are present, but in lower quantities than the less mature oil, perhaps as a result of cracking. If the effects of maturity are allowed for, the terpane distribution confirms the relationship with the less mature oil; compounds X and Y are also present, apparently in greater abundance than in the less mature oil. The abundance of X and Y relative to the hopanes appears to be maturity dependent, with X and Y more resistant to breakdown at high temperature. The gc and gc-ms data clearly indicate that the two Meleiha oils were generated from source rocks containing significant amounts of terrestrial organic matter. The two oils initially appear distinct, but all differences can be explained by the effects of maturity. The oils were either generated from source rocks at different levels of maturity, or the oils in deeper reservoirs have suffered in-situ cracking.

189

OIL P O T E N T I A L OF M I D - J U R A S S I C C O A L S IN N. E G Y P T

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Fig. 8. Meleiha oi| from deep reservoir: (a) Cas+ gas chromatogram and (b) terDane (m/z 191) distribution.

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190

M. A. BAGGE & M. L. KEELEY

Recognition of oil potential in Jurassic coals Coals are often overlooked as possible oil source rocks in geochemical sampling programmes. Evaluation of generating potential of the coal is usually based on petrographic data, where high liptinite contents are taken to indicate the possibility of oil-generating potential. Typical humic, vitrinite-rich coals are dismissed as being simply gas prone. As part of this study, Jurassic coals and a carbonaceous shale from well and outcrop were submitted for a wide range of source rock analyses to establish if the coals do have oilgenerating potential and, if so, which analytical technique best determines this potential. Data are presented from coals and carbonaceous shales from an outcrop section at Gebel el Maghara, northern Sinai, and from a well in the Meleiha area in the Western Desert (Bagge et al. 1988). Well names and depths cannot be quoted because the information is confidential. The oil potential of the coals and carbonaceous shales were evaluated using chemical, petrographic analyses and bitumen extract characterization.

Chemical analyses The most commonly acquired geochemical data from well cuttings and cores are Total Organic Carbon (TOC) and Rock-Eval Pyrolysis data. These allow the quantity and quality of organic matter in sediments to be determined, and potential source rock horizons delineated. The analyses are usually applied to argillaceous sequences to allow quantification of the amount and hydrocarbon generating potential of the dispersed organic matter ('kerogen') in the sediments, and can also be used to characterize the hydrocarbon-generating potential of coals. The Rock-Eval Hydrogen Index (S2*100/TOC) is used to describe organic matter quality and its oil- or gas-prone nature. Source rocks containing oil-prone Type I or Type II organic matter typically have Hydrogen Indices of 400 of greater, whereas humic, Type III, gas-prone material has Hydrogen Indices of 150 or less. Inert, Type IV organic matter often has Hydrogen Indices of 10 or less. Although TOC contents and pyrolysis $2 yields give a good estimation of the present-day hydrocarbon-generating potential of a coal, caution should be exercised when using Hydrogen Indices to indicate whether a coal is oil or gas prone. High Hydrogen Indices are usually associated with boghead or cannel coals and do indicate oil potential; however, when humic coals contain a small but significant proportion of oil-prone material, the oil poten-

tial can go unrecognized as the Hydrogen Index averages the potential of inert, gas- and oilprone macerals. It is, therefore, crucial to interpret Hydrogen Index data with supporting analyses such as combined pyrolysis-gc and maceral typing. The geochemical characteristics of the coals and carbonaceous shales are summarized in Table 1. The Gebel el Maghara coals have Hydrogen Indices of 408-484 mg HC g-1 rock which clearly indicate oil-prone organic matter. The coals are obviously more hydrogen rich than the associated carbonaceous shales which have Hydrogen Indices of 201-212. The Meleiha well coals have lower Hydrogen Indices (167-210), which suggests gas-generating potential. These samples are past the main stage of oil generation, however (R0 1.20-1.22%), and the pyrolysis yields therefore represent their residual gas potential. The oil potential of the Gebel el Maghara coal and gas potential of the Meleiha coal are confirmed by the pyrolysis-gc P2 (pyrolysate- chromatograms (Fig. 9) which show an extended series of alkane/alkene doublets in just the Gebel el Maghara coal.

Petrographic analysis Petrographic analysis is particularly valuable in coals as the macerals can be identified easily. It is generally accepted that the liptinitic macerals derived from algae or hydrogen-rich plant material such as spores, pollen, resin and cuticle are responsible for oil potential. The macerals form a large part of the organic matter in boghead or cannel coals, but can also be present in humic coals. Vitrinite, which forms the bulk of humic coals is usually considered gas prone, but some hydrogen-rich forms of vitrinite may also have oil-generating potential (See Collinson et al. this volume). The maceral content of the Gebel el Maghara coals and shales and Meleiha well coals are described in the point count data shown in Table 2. The Gebel el Maghara coals are composed primarily of vitrinite (76.4-79.0%), but with significant amounts of liptinite macerals: cutinite, sporinite, resinite and liptodetrinite (total 21.0-22.8%). Despite being of much lower hydrogen content (lower Hydrogen Index), the Gebel el Maghara carbonaceous shales also have moderate liptinite contents (8.0-20.0%). From liptinite content alone, therefore, it would not have been possible to identify the Gebel el Maghara coals as being more hydrogen rich, and hence more oil prone than the carbonaceous shales. The Meleiha well coals have higher vitrinite contents (85.6-

Sample type

61.60 59.40 2.26 5.33 39.73 60.00 6.35

TOC (wt %) 251.05 287.50 4.80 10.69 83.57 100.30 12.63

$2 (mg g-a) 408 484 212 201 210 167 199

HI (rag HC g-1TOC) 5 5 25 31 3 1 6

OI (mg CO2 g-1TOC)

* No vitrinite reflectance performed. Maturity approximately equivalent to Meleiha well coals.

Gebel Maghara coal i Outcrop Gebel Maghara coal 2 Outcrop Gebel Maghara shale 1 Outcrop GebelMagharashale2 Outcrop Meleiha well coal 1 Well cuttings Meleiha well coal 2 Well core Meleiha well shale Well cuttings

Sample ID

Source rock evaluation

26.49 26.36 0.76 0.97 9.95 13.81 2.39

S1 (mg g-1) 0.10 0.08 0.14 0.08 0.11 0.12 0.16

PI S 1/S 1 + $2

Free hydrocarbons

Table 1. Geochemical analysis of Jurassic coals and carbonaceous shales from Egypt (data from Bagge et al. 1988)

418 417 436 426 454 456 450

Tmax (°C)

No. of readings 50 5O 5O 50 100 100

% Ro 0.43 0.39 0.43 0.44 1.22 1.20

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94.4%) and lower liptinite contents (0.8-1.6%). The dominant form of vitrinite is desmocollinite (a more hydrogen-rich vitrinite) which, together with the fine-grained matrix, is fluorescent in one of the Meleiha coals. Based on the high vitrinite content, these coals would traditionally be interpreted to be gas-prone Type III humic

coals, but the fluorescence of the ground mass and also the vitrinite type suggests the coals may have had some oil potential. Fluorescence is often used as an indicator of oil potential in source rocks and the fluorescence of some forms of vitrinite, particularly desmocollinite may be important in the consideration

% Maceral

90.0 Pyrite 8.0 Other minerals 0.0

76.4 Pyrite 22.8 Other minerals 0.0

94.4 Pyrite 0.8 Other minerals 4.0 (absolute count)

Fusinite Semifusinite Sclerotinite Macrinite Micrinite Inertodetrinite

Fusinite Semifusinite Sclerotinite Macrinite Micrinite Inertodetrinite

Fusinite Semifusinite Sclerotinite Macrinite Micrinite Inertodetrinite

0.0 Bitumen 67.0*(Exudatinite)

0.0 tr 0.4 0.0 0.4

0.0 Bitumen 0.0 (Exudatinite)

2.0 6.0 5.2 2.4 7.2

0.0 Bitumen 0.0 (Exudatinite)

0.0 4.0 2.0 0.0 2.0

% Maceral

0.8

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%

% Maceral

80.0 Pyrite 20.0 Other minerals 0.0

79.0 Pyrite 21.0 Other minerals 0.0

Total vitrinites Totalliptinites Total inerts

85.6 Pyrite 1.6 Other minerals 12.8

Sample: Meleiha well coal 2 Telocollinite 17.2 Cutinite Corpocollnite 0.4 Sporinite Desmocollinite 67.6 Resinite TeUinite 0.0 Alginite Pseudovitrinite 0.0 Liptodetrinite Vitrodetrinite 0.4

Total vitrinites Total liptinites Total inerts

Sample: Gebel Maghara coal 2 Telocollinite 28.0 Cutinite Corpocollnite 1.0 Sporinite Desmocollinite 50.0 Resinite Tellinite 0.0 Alginite Pseudovitrinite 0.0 Liptodetrinite Vitrodetrinite 0.0

Totalvitrinites Total liptinites Total inerts

Sample: Gebel Maghara shale 2 Telocollinite 0.0 Cutinite Corpocollnite 0.0 Sporinite Desmocollinite 80.0 Resinite Tellinite 0.0 Alginite Pseudovitrinite 0.0 Liptodetrinite Vitrodetrinite 0.0

Maceral

* Fine-grained groundmas of mineral mixed with an amorphous fluorescing material. Not counted in maceral percentages.

Total vitrinites Total liptinites Totalinerts

Sample: Meleiha well coal 1 Telocollinite 17.2 Cutinite Corpocollnite 0.0 Sporinite Desmocollinite 75.6 Resinite Tellinite 0.0 Alginite Pseudovitrinite 0.0 Liptodetrinite Vitrodetrinite 1.6

Total vitrinites Total liptinites Total inerts

Sample: Gebei Maghara coal 1 Telocollinite 41.2 Cutinite Corpocollnite 1.2 Sporinite Desmocollinite 34.0 Resinite Tellinite 0.0 Alginite Pseudovitrinite 0.0 Liptodetrinite Vitrodetrinite 0.0

Totalvitrinites Total liptinites Total inerts

Sample: Gebel Maghara shale I Telocollinite 50.0 Cutinite Corpocollnite 0.0 Sporinite Desmocollinite 40.0 Resinite Tellinite 0,0 Alginite Pseudovitrinite 0.0 Liptodetrinite Vitrodetrinite 0.0

Maceral

Fusinite Semifusinite Sclerorinite Macrinite Micrinite Inertodetrinite

Fusinite Semifusinite Sclerorinite Macrinite Micrinite Inertodetrinite

Fusinite Semifusinite Sclerorinite Macrinite Micrinite Inertodetrinite 0.0 Bitumen 28.0 (Exudatinite)

0.0 0.0 0.8 0.0 0.8

0.0 Bitumen 0.0 (Exudatinite)

3.0 4.0 6.5 3.0 4.5

0.0 Bitumen 0.0 (Exudatinite)

5.0 5.0 3.0 2,0 5.0

% Maceral

Table 2. Petrographic analysis of Jurassic coals and carbonaceous shales (maceral composition by point count), Egypt (data from Bagge et al. 1988)

0.0

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194

M. A. BAGGE & M. L. KEELEY

of humic coals as possible sources for oil. Bertrand (1984) reached the conclusion that some vitrinites may have oil-generating potential in a study of 68 coals worldwide. In his study, no correlation was found between exinite content and oil-generating potential, raising the possibility that hydrogen-rich vitrinites are partly responsible for oil-generating potential in some Type III source rocks. Use of petrographic analysis is, therefore, not definitive in evaluating the oil potential of Jurassic coals of the Western Desert. There is no doubt that large amounts of liptinitic material results in high oil potential; however, the Gebel el Maghara coals and carbonaceous shales have similar liptinite contents but very different oil potentials. Liptinite maceral content alone cannot be used to establish oil potential, and it is likely that hydrogen-rich vitrinites and the finegrained groundmass are responsible for oil potential in some coals. These coals are likely to have been overlooked as potential oil sources in traditional interpretation schemes.

Extract characterization Extract characterization was used to provide information on the organic matter in the coals and also to allow correlations with the oils. Soluble bitumen extracted from the rocks was separated by liquid chromatography into saturated and aromatic hydrocarbons, NSO compounds and asphaltenes (Table 3). The saturated hydrocarbon fraction was analysed by Cas÷ gas chromatography and combined gas chromatography-mass spectrometry (gc-ms). Extract characteristics of the Western Desert coals vary widely between individual coal samples, reflecting facies changes in the depositional environment of the coals. An appreciation of these variations is essential when correlating oils to source rock extracts. The Cas÷ gas chromatogram of the Gebel el Maghara coal shown in Fig. 10 is rather unusual and is dominated by several unidentified compounds. The Meleiha well coals (Fig. 11) show a more usual suite of normal alkanes with no oddcarbon preference. The dominance of low molecular weight n-alkanes is probably a result of the high maturity of these coals (1.2-1.22%

Ro). Perhaps the most unusual aspect of the Meleiha coal extracts is the relative abundance of acyclic isoprenoids. In one extract, acyclic isoprenoids are virtually absent, whereas in the other, phytane is more abundant than pristane. The low concentration of isoprenoids relative to n-alkanes is probably related to the high level of

maturity of the coals, but this cannot explain the Pr/Ph ratio of less than unity. This Pr/Ph ratio (0.72) is atypical for coal, which usually has ratios of 3.0 or greater, and is more typical of a marine or lacustrine oil source rock deposited in a strongly reducing environment. This coal has a fluorescent fine-grained groundmass and unusual sterane and terpane distributions, and is thought to contain algal material, too fine grained to identify positively microscopically. The sterane and terpane biological marker compounds (Fig. 12) are unusual for humic coals and are thought to be derived from algal precursors. Readers are referred to a review of sterane and triterpane biological markers such as Waples & Machihara (1990) for an account of more typical fingerprints for different types of source rock. The m/z 217 fragmentogram of one Meleiha coal shows that C27 regular steranes and diasteranes, and C28 regular steranes are almost as abundant as the C29 steranes and diasteranes. This is in contrast to the Meleiha oils, which have C29 regular steranes and diasteranes dominant. Terpanes are also unusual for coal extracts, in that tricyclics are present in significant amounts relative to the pentacyclic terpanes, and C3s homohopanes are more abundant than C34 homohopanes. The terrestrial markers X and Y are absent. These sterane and terpane distributions are more akin to algal marine source rocks than humic coals. These coal extracts obviously give a poor correlation to the Meleiha oils presented here. The best oil-source rock correlation is with a highly carbonaceous shale interbedded with the coals (Fig. 13). This shale has modest presentday gas source potential (Table 1), but is postmature for oil generation. However, it may have had oil-generating potential in the past. This source rock displays the two terpane biological markers X and Y, and gives a fairly good correlation with the more mature of the two Meleiha oils presented here. This shale cannot be described as a 'good' source rock by normal geochemical criteria and would be overlooked in most geochemical analysis programmes.

Conclusions Mid-Jurassic coal sequences in the northern Western Desert of Egypt are believed to be responsible for generating the waxy, paraffinic oils in the area, including those from the Meleiha field. The coals are contained in the Sara Member of the Khatatba Formation. Recognition of oil potential of the coals and associated carbonaceous shales is problematic,

34232 8025 4642 3803

Sample ID

Gebel Maghara coal 2 Meleiha well coal 1 Meleiha well coal 2 Meleiha well shale

5.76 2.01 0.78 10.45

Extract/TOC (%) 3.4 19.4 10.5 15.5

Sats (%)

* Non-eluted components and material lost through evaporation of solvent.

Total extract (ppm) 18.9 33.9 34.9 28.9

Arom (%) 51.5 24.1 29.5 36.3

Asph (%) 25 15.7 9.5 6.8

NSO (%)

Extract composition

Table 3. Bitumen extract data, Jurassic coals and carbonaceous shales, Egypt (data from Bagge et al. 1988)

1.1 6.8 15.5 12.5

Bal (%)*

1.1

1.07

1.14

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1.78

0.72

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Pr/Ph

196

M. A. BAGGE & M. L. KEELEY 100 -

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Fig. 10. Gebel el Maghara coal: Cts+ gas chromatogram of saturated hydrocarbons.

and it is unclear which components (macerals) are responsible for the oil-prone nature of coals. The coals from outcrop at Gebel el Maghara in northern Sinai appear to be oil prone and are more hydrogen rich than the associated carbonaceous shales. Petrographic analysis would not, however, have distinguished the coals as more oil prone than the shales but Rock-Eval Hydrogen Indices and pyrolysis-gc pyrolysate fingerprints identify the coals as having oil potential. The Meleiha well coals are post-mature for oil generation (Ro 1.2%) but have high gas potential. These coals are unusual as they contain fluorescent vitrinite and a fluorescent finegrained groundmass; the low pristane/phytane ratio and biological marker distributions suggest this groundmass is derived from algae. These coals have probably generated oil in the past, but because they appear to contain primarily vitrinite, would not have been identified as potential oil source rocks. The Meleiha oils were generated from source rocks rich in terrestrial organic precursors. They contain two triterpane compounds, X and Y, which have been observed in Australian coals, but the terrestrial biological marker oleanane is

absent as the Jurassic source rocks pre-date the angiosperm precursors of this compound. The two oils are related but the deeper oil has suffered cracking, either in the source rock or in the reservoir. The oils correlate poorly to the unusual Meleiha coals, but give a possible correlation to a carbonaceous shale interbedded with the coals. This shale has only moderate generating potential, and is likely to be overlooked as a potential source rock in normal geochemical analysis programmes on exploration wells. The coals and carbonaceous shales accumulated in a swamp environment where facies variations were rapid. The dominant organic matter type is humic Type III plant material, but localized development of coals rich in liptinitic material, either terrestrial or algal, has occurred, probably in stagnant areas. Oils generated from this source rock environment are bound to show the average characteristics of a great volume of source rock and will correlate poorly to unusual, locally developed coal facies. Small oil accumulations or oil stains may, however, show very unusual characteristics if they are derived from a particular oil-prone coal facies.

197

OIL P O T E N T I A L OF MID-JURASSIC COALS IN N. EGYPT

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198

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