Org. Geochem. Vol. 17, No. 2, pp. 211-222, 1991 0146-6380/91 $3.00 + 0.00 Printed in Great Britain PergamonPresspie Classification of oil shales, coals and other organic-rich rocks A. C. COOKand N. R. SHERWOOD Keiraville Konsultants, 7 Dallas St, Keiraville, N.S.W. 2500, Australia (Received 25 January 1990; accepted 15 July 1990) Abstract--Oil shales are a complex group of rocks which were deposited in a wide range of sedimentary environments and have a wide range of largely alginite-dominated maceral assemblages. A system of classifying oil shales and sapropelic coals is based on relative abundances of macerals. Classification of oil shales has applications to the commercial development of oil shale deposits and to the classification of petroleum source rocks. Key words---oil shale, cannel coal, sapropelic coal, kukersite, tasmanite, torbanite INTRODUCTION Canneloid coals and other oil shales were the first sources of large quantities of liquid hydrocarbons developed during the industrial revolution. They were soon replaced by flow oil as the major source of petroleum products, but small oil shale industries survived in various parts of the world until after the Second World War. Interest in oil shales was revived by the second oil crisis of the 1970s and a flurry of activity occurred from 1979. By 1984 most of the major projects had either been abandoned, greatly scaled down, or placed on a "care and maintenance" basis. The burst of interest has, however, led to a much better understanding of oil shales both in relation to their organic petrology and their organic geochemistry. In the late 1970s, existing terms were not adequate for the characterization of organic matter in some types of oil shale. A number of different types of oil shale could, however, be distinguished on the basis of the nature of the organic matter present. To make these distinctions either existing terms could be used for components which did not fit the original descrip- tions or some new terms could be developed. In taking the second course, existing terminology was used wherever possible both for macerals and for rock types. Agu Kantsler and Adrian Hutton were associated with the earlier part of this work (see Hutton et aL, 1980). Hutton contributed further to this work and has presented different but related schemes for classification of oil shales (Hutton, 1982, 1987). MACERAL TERMINOLOGY Tertiary oil shales from eastern Queensland, Australia (e.g. the Rundle deposit) contain small amounts of Botryococcus-related material referable to the existing term alginite, but the majority of organic matter present (in the Rundle deposit alone this is of the order of 400 million t of organic matter) has fluorescence properties and form differing markedly from Botryococcus-related alginite. The term alginite was divided by Hutton et al. (1980) into two groups: alginite A and alginite B. These terms have been changed to telalginite and lamalginite, respectively. Definitions of these subdivisions of alginite are given in the Australian Standard AS 2856, and draft definitions are currently being considered by the International Committee for Coal Petrology (ICCP). Lamalginite has a finely lamellar form [Plate l(a)], whereas telalginite has a lensoidal, flattened spheroidal or fan-shaped form [Plate l(b)]. Differ- ences also exist in fluorescence intensities and colours; lamalginite typically has less intense fluorescence with more of a red shift than most telalginite. Hutton (1982) listed some algal genera which contribute to the lamalginite in Queensland oil shales and concluded that Pediastrum is an abundant form. Sherwood et al. (1984) noted that Pediastrum-derived lamalginite is present in oil shales of similar age from Thailand. Strongly fluorescing liptinites in Green River Formation (U.S.A.) oil shales have a lamellar form [Plate l(c)] and may be similar to Rundle lamalginite but their fluorescence is typically much stronger than that of Pediastrum-derived lamalginite. Dinoflagellate and acritarch cysts in some marine oil shales and other potential source rocks have lamellar form similar to Pediastrum-derived lamalginite. In sections parallel with bedding, well- preserved botanical structures are evident in many dinoflagellate and acritarch cysts [Plate l(d)]. For simplicity, "lamalginite" is applied to these entities because they are observed as thin lamellae in sections perpendicular to bedding. Dinoflagellate- and acritarch-derived lamalginite, however, encom- pass a wide range of optical properties at any one level of rank. 211 doc: 2.17.gxyf
Transcript
Org. Geochem. Vol. 17, No. 2, pp. 211-222, 1991 0146-6380/91 $3.00 + 0.00 Printed in Great Britain Pergamon Press pie
Classification of oil shales, coals and other organic-rich rocks
A. C. COOK and N. R. SHERWOOD Keiraville Konsultants, 7 Dallas St, Keiraville, N.S.W. 2500, Australia
(Received 25 January 1990; accepted 15 July 1990)
Abstract--Oil shales are a complex group of rocks which were deposited in a wide range of sedimentary environments and have a wide range of largely alginite-dominated maceral assemblages. A system of classifying oil shales and sapropelic coals is based on relative abundances of macerals. Classification of oil shales has applications to the commercial development of oil shale deposits and to the classification of petroleum source rocks.
Canneloid coals and other oil shales were the first sources of large quantities of liquid hydrocarbons developed during the industrial revolution. They were soon replaced by flow oil as the major source of petroleum products, but small oil shale industries survived in various parts of the world until after the Second World War. Interest in oil shales was revived by the second oil crisis of the 1970s and a flurry of activity occurred from 1979. By 1984 most of the major projects had either been abandoned, greatly scaled down, or placed on a "care and maintenance" basis. The burst of interest has, however, led to a much better understanding of oil shales both in relation to their organic petrology and their organic geochemistry.
In the late 1970s, existing terms were not adequate for the characterization of organic matter in some types of oil shale. A number of different types of oil shale could, however, be distinguished on the basis of the nature of the organic matter present. To make these distinctions either existing terms could be used for components which did not fit the original descrip- tions or some new terms could be developed. In taking the second course, existing terminology was used wherever possible both for macerals and for rock types. Agu Kantsler and Adrian Hutton were associated with the earlier part of this work (see Hutton et aL, 1980). Hutton contributed further to this work and has presented different but related schemes for classification of oil shales (Hutton, 1982, 1987).
MACERAL TERMINOLOGY
Tertiary oil shales from eastern Queensland, Australia (e.g. the Rundle deposit) contain small amounts of Botryococcus-related material referable to the existing term alginite, but the majority of
organic matter present (in the Rundle deposit alone this is of the order of 400 million t of organic matter) has fluorescence properties and form differing markedly from Botryococcus-related alginite. The term alginite was divided by Hutton et al. (1980) into two groups: alginite A and alginite B. These terms have been changed to telalginite and lamalginite, respectively. Definitions of these subdivisions of alginite are given in the Australian Standard AS 2856, and draft definitions are currently being considered by the International Committee for Coal Petrology (ICCP). Lamalginite has a finely lamellar form [Plate l(a)], whereas telalginite has a lensoidal, flattened spheroidal or fan-shaped form [Plate l(b)]. Differ- ences also exist in fluorescence intensities and colours; lamalginite typically has less intense fluorescence with more of a red shift than most telalginite. Hutton (1982) listed some algal genera which contribute to the lamalginite in Queensland oil shales and concluded that Pediastrum is an abundant form. Sherwood et al. (1984) noted that Pediastrum-derived lamalginite is present in oil shales of similar age from Thailand. Strongly fluorescing liptinites in Green River Formation (U.S.A.) oil shales have a lamellar form [Plate l(c)] and may be similar to Rundle lamalginite but their fluorescence is typically much stronger than that of Pediastrum-derived lamalginite.
Dinoflagellate and acritarch cysts in some marine oil shales and other potential source rocks have lamellar form similar to Pediastrum-derived lamalginite. In sections parallel with bedding, well- preserved botanical structures are evident in many dinoflagellate and acritarch cysts [Plate l(d)]. For simplicity, "lamalginite" is applied to these entities because they are observed as thin lamellae in sections perpendicular to bedding. Dinoflagellate- and acritarch-derived lamalginite, however, encom- pass a wide range of optical properties at any one level of rank.
211
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212 A.C. COOK and N. R SI-mRWOOD
Abundant bituminite (defined in a set of sheets currently being finalized for publication by the ICCP), commonly in association with micrinite [Plate l(e)] is a distinctive feature of many marine oil shales. The properties of bituminite are intermediate in many ways between those of liptinite macerals such as sporinite and those of vitrinite, but bituminite was defined by Teichmiiller (1974) as a liptinite maceral and this designation has been accepted by the ICCP at its 1988 meeting. In the present study, bituminite is referred to as "liptinitic" in the classification diagrams but because its H/C ratio is much lower than that of alginite, bituminite has not been counted as liptinite in the analyses of oil shales presented in some of the figures.
Bitumens are present in some oil shales such as the Green River Formation of the U.S.A. and the Irati Formation of Brazil. The bitumens can impregnate and may partially replace some macerals. This influ- ences the optical and chemical properties of the host organic matter. Thus, the high H/C ratio of organic matter concentrates from the Green River Formation may be due in part to the presence of bitumens. Care must be taken in distinguishing bitumens (migrabitu- men) from bituminite; bituminite is not a bitumen and has properties which are markedly different from those of most bitumens.
SUBDIVISION OF ORGANIC-RICH ROCKS
Within oil shales as a class, a number of distinctive rock types have in the past been given specific names (e.g. torbanite, cannel and tasmanite). In terms of the maceral content of the rock types, some of these terms clearly have systematic value but a number of other rock types also have distinctive maceral assem- blages. This allows the development of a more
complete naming system for oil shales. Oil shale nomenclature should be linked with that for coals and other rocks which have high contents of organic matter.
In Fig. 1, a method of defining coal and of separating humic and sapropelic coals is presented. A simple definition for sapropelic coals in terms of maceral composition is not possible and, for example, liptinite-rich coals such as Carboniferous crassidurains should be retained within the humic group. The term "sapropelic" is used here largely because of its widespread use rather than a belief that it is a useful descriptor. At the next level of subdivision, the three categories form distinctive end members. Cannel coals contain abundant higher plant-derived liptinite, whereas torbanitic and lacositic coals contain liptinite mainly derived from algae. Lacositic coals are rare in terms of the litera- ture, but some Palaeozoic coals recorded as cannel coals may more properly be considered as lacositic coals.
On the basis of liptinite and bitumen abundance, other rocks rich in organic matter are grouped into coaly shales, oil shales and bitumen-impregnated rocks and tar sands (Fig. 2). The rocks dominated by vitrinite and inertinite are termed coaly shales. For oil shales, the lower limit of 10% iiptinite and, as used in this paper, liptinitic macerals corresponds approxi- mately with the lowest content of liptinite which will yield a significant amount of shale oil on retorting. Bitumen-bearing rocks are distinguished from other carbonaceous rocks because bitumen has a different origin, mode of occurrence and chemistry to macerals in general and to liptinites in particular, with the probable exception of exsudatinite,
Figure 3 illustrates bitumen-rich rocks and sub- divisions of oil shales. They are divided into five main
Plate I. (facing page) Photomicrographs of lacosites, torbanite, marosite and bitosite. Plate l(a). Tertiary lacosite from Rundle, Queensland, Australia. A slightly weathered sample from the outcrop at Kerosene Creek, showing dominant lamalginite (orange) and sparse telalginite (yellow) in a clay/silt-sized mineral matrix. ~vmax of the overlying coal is 0.28%. Field width = 0.55 mm; fluorescence-
mode; sectioned perpendicular to the bedding. Plate l(b). Permian torbanite from Joadja, N.S.W., Australia. High magnification photomicrograph of Reinschia-derived telalginite (Botryococcus-related). Individual algal cells can be distinguished together with possible growth lines within the cells. J~vmax of the associated coal, free of alginite, is 0.8%. Field
width = 0. I0 mm; fluorescence-mode; sectioned perpendicular to the bedding. Plate l(c). Tertiary lacosite from the Green River Formation, Colorado, U.S.A. Dominant lamalginite (orange to yellow lamellae), vitrinite (black stringers), highly reflecting mineral matter (black flecks) and other mineral matter with background fluorescence. Some of the background fluorescence is probably caused by bitumen impregnation. ~max of the associated vitrinite is 0.3% but ~max for samples from the overlying Uinta Formation is 0.45%. Field width = 0.56 mm; fluorescence-mode; sectioned
perpendicular to the bedding. Plate l(d). Triassic marosite from the Kockatea Shale, Perth Basin, Western Australia. Cuttings sample with lamalginite derived from the acritarch Veryhachium (yellow to orange) in a clay-sized mineral matrix. Rvmax of the associated vitrinite phytoclasts is approx. 0.65% Field width = 0.44 ram; fluorescence-mode;
sectioned parallel to the bedding. Plate l(e). Pennsylvanian bitosite from the Eudora Shale, Kansas, U.S.A. Dominant bituminite (light grey laminations and disseminated lenses) and highly reflecting mineral matter (white flecks) in a clay-sized mineral matrix. 2~vmax for the overlying coal is 0.73%. Reflectance of the bituminite is approx. 0.4%.
Field width = 0.44 mm; reflected white light; sectioned perpendicular to the bedding,
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Classification of oil shales 215
TYPICAL ORGANIC MATTER ASSEMBLAGE
ENVIRONMENT OF DEPOSITION
(TYPICALLY < 10% LIPTINfTE)
I COAL I (>80% ORGANIC MATTER; TYPICALLY V+l~..)
/ ",,, HUMIC C O A L 'SAPROPELIC' COALS
(OIL SHALES IN PART) (TYPICALLY ~10~ LIPTIMTE OR UPTINmC MACISqALS)
V>I>L I ;bV>L I>L>V V>L>I
HIGH TO LOW MOOR TO LACUSTRINE; TYPICALLY FRESHWATER, LESS COMMONLY BRACKISH
CANNEL COAL TORBANITIC COAL I LACOSITIC COALI (RARE) I
LOW MOOR TO LAGLI~NE; L A C L ~ N E ; LACUSTRINE; FRE~.IWATER, FRESHWATER, T ~ Y BRACKBI'~ PO6~.~BLY BRACKISPI OR SALINE FRESHWATER, SALINE IN RARE CASES LESS ~ M G N L Y BRACKISH
Fig. 1. Classification scheme for coals.
rock types based on the dominant type of organic matter present (i.e. higher plant-derived macerals, telalginite, lamalginite, bituminite and bitumens).
In Fig. 3, the oil shale group includes two rock types commonly referred to as coals: cannel and torbanite. These are part of the coal group but are also important types of oil shale in terms of depositional environment. Bitumen-rich rocks have been included in the classification and are termed bitumenosite.
In order to retain the well-established names tasmanite, kukersite and torbanite, telosites are further divided on the basis of the type of alginite present. This division also effects a separation into marine (tasmanite and kukersite) and non-marine (torbanite) telalginite-rich, oil shale types.
Lamosite (lamalginite-dominated oil shale) is divided into a marine type (marosite), and lacustrine
I COALY SHALES [ OIL SHALES i BITUMEN-RICH (<80% ORGANICI(;=10% LIPTINITE, I ROCKS+TAR MATTER;<IO% I OR LIPTINITIC I SANDS LIPTINITE) I MACERALS) 1(>10% BITUMEN)
TYPICAL ORGANIC MATTER ASSEMBLAGE
ENVIRONMENT OF DEPOSITION
V>I>L OR L>V>I OR >V > L LESS COMMONLY
V>L>I (~1 I>L>V
HIGH TO LOW MO~ TO LACU~'rRINE, LACUSTRINE MARINE; MARINE; FRESHWATER, FRESHWATER, BRACKISH, BRACKISH, SALINE SALINE
B ~ M ~
VARKTd~ BITUMEN ORIGINATES FROM Pob'rDEPO6rTK~AL PROCESSES SUCH AS NEAR SURFACE ALTERATION OF OIL SSEPS OR RESERVO~ OR FROM THB~MN. ~OOMPO~noN OF OILS
Fig. 2. Classification scheme for organic-rich rocks and sediments other than coal.
Plate 2. (opposite) Photomicrographs of tasmanite, kukersite, marosite and marobitosite. Plate 2(a). Jurassic tasmanite from Alaska, U.S.A. Dominant telalginite derived from tasmanitid cysts (orange) in a bituminite and mineral matrix (both black). Field width = 0.44 mm; fluorescence-mode;
sectioned perpendicular to the bedding. Plate 2(b). Ordovician kukersite from Estonia, S.S.R. Dominant Gloeocapsornorpha-related telalginite (greenish orange to yellow), acritarch cyst (yellow, with medial suture; lower left) and mineral matter
(black). Field width = 0.36 mm; fluorescence-mode; sectioned perpendicular to the bedding. Plate 2(c). Cretaceous marosite from the Muderong Shale, Carnarvon Basin Western Australia. Domi- nant lamalginite derived from dinoflagellate/acritarch cysts (orange) and highly reflecting (black) and other mineral matter. ,~vmax = 0.35%. Field width = 0.44 mm; fluorescence-mode; sectioned oblique to
the bedding. Plate 2(d). Cretaceous marobitosite from the Toolebuc Formation, Queensland, Australia. Dominant bituminite (dark grey laminae), lamalginite (black) minor micrinitized bituminite (grey with light grey flecks; left side) micrinite (light grey, flecked laminae; upper middle), bitumen (grey lens; upper middle) and highly reflecting minerals (white) in a clay-sized mineral matrix (buff). Rvmax interpolated from the adjacent units is 0.4%. Field width = 0.38 mm; reflected white light; sectioned perpendicular to the bedding. Plate 2(e). Cretaceous marobitosite from the Toolebuc Formation, Queensland, Australia. Same field of view as Plate 2(d), showing major lamalginite (yellow stringers), associated liptodetrinite (yellow flecks), bitumen (orange pod; upper middle), bituminite and micrinitized bituminite (greenish brown to black), micrinite (black) and highly reflecting mineral matter (blue to black) in a clay-sized mineral matrix with orange background fluorescence. ~vmax interpolated from the adjacent units is 0.4%. Field
width = 0.38 ram; fluorescence mode; sectioned perpendicular to the bedding.
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Classification of oil shales 217
BITUMINITE
LAMALGINITE 5 0 TELALGINITE
Fig. 4. Ternary diagram showing primary divisions of oil shale types in terms of liptinite and liptinitic maceral
composition.
LAMALGINITE
90
50 50
HIGHER PLA VITRINITE+ LIPTINITE INERTINITE
Fig. 6. Ternary diagram showing the compositional fields of oil shales deposited under non-marine conditions where
lamalginite is dominant over telalginite.
type (lacosite) as shown in Fig. 3. All rocks classified here as bitosites are marine and they form a mixed series with the other marine oil shale types. Hutton et al. (1980) and Cook et al. (1981) classed some of these bituminite-bearing marine oil shales as "mixed oil shales". Lacosites contain various assemblages of iamalginite and the terms Rundlesite (from Rundle in Queensland) and Mahogosite (from the Mahogany Ledge of the Green River Formation) apply to what may be end members of this variation.
Figure 4 presents a threefold division of the main oil shale types (except for cannel coals) and this is made on the basis of the relative abundance of the three principal liptinite and liptinitic macerals in these rocks: telalginite, lamalginite and bituminite. Figures 5-7 show classification of the large range of compo- sitions between end members. The major divisions are based on maceral abundance, and together with the subdivisions provide a classification which applies to both petrological and geochemical characteristics.
Figures 4-7 illustrate the most common assem- blages of macerals. Other assemblages exist and similar classification triangles can be constructed to include these less common oil shale types. For example, a lamalginite, telalginite and higher plant liptinite triangle is needed for some types of fresh- water oil shales and this defines rock types such as
NOTE: CURAINS FALL ON THE HIGHER PLANT LIPTINITE-VITRINITE* INERTINITE AXIS AND ARE CLASSED AS HUMIC COALS
Fig. 5. Ternary diagram showing the compositional fields of oil shales deposited under non-marine conditions where
telalginite is dominant over lamalginite.
lacositic torbanite and torbanitic lacosite. The re- lation of subdivisions to chemical composition of organic matter is illustrated in Figs 8 and 9. In these figures, atomic H/C ratios vary markedly with lip- tinite percentage and with oil shale type, respectively. The large range of liptinite contents for H/C < 1.4 reflects the different properties of the various macer- als and the correlation would be greatly improved if liptinite content was recalculated to take account of the H/C ratio of each maceral.
The distinctions between cannel coal and coaly cannel, lacositic coal and lacositic shale, humic coal and coaly shale and torbanitic coal and torbanitic shale are based upon the amount of mineral matter present. As shown in Fig. 1, the term coal is restricted to rocks containing <20% (by vol) mineral matter. A complete series occurs, from coals that contain very small proportions of mineral matter to coaly shales that contain minor amounts of organic matter.
Figures 3 and 4 encompass the basic variations in maceral composition, but for most purposes the level of detail provided by Figs 5-7 is necessary. The subdivisions of the fields correspond as closely as possible with natural divisions. Within the non- marine oil shales (Figs 5 and 6) the lamalginite- dominated rocks form a distinctly different suite from the telalginite-dominated rocks.
In the group of marine oil shales (Fig. 7), only kukersite and tasmanite have previously been given
LAMALGINITE
90
90 50 90 TELALGINITE BITUMINITE
Fig. 7. Ternary diagram showing the compositional fields of oil shales deposited under marine conditions,
doc: 2.17.gxyf
218 A.C. Cook and N. R SHI/RWOOD
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O CANNELOID HUMIC COAL (HIGHER PLANT LIPTINITE >10%)
o COALY CANNEL o TORBANITIC COAL • TORBANITE (IN PART COALY
TOR BA NIT E) = WEATHERED TORBANITE
MAROBITOSITE ('MIXED OIL SHALE, BITUMINITE-RICH')
• BITOMAROSITE ('MIXED OIL SHALE, LA MALGINITE-RICH')
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$ COALY LACOSITE ('SUBCAR BONACEOUS LA MOSITE', 50% >VITRINITE >10%)
$ WEATHERED LACOSITE e KUKERSITE x TASMANITE
J BITUMEN • OIL
NOTE: Some points representing 100% liptlnlta are plotted at slightly greater than 100% for clarity
Fig. 8. H/C (atomic ratio) plotted against liptinite abundance.
specific rock names. The presence or absence of bituminite is an important factor for this group of oil shales.
DESCRIPTIONS OF OIL SHALE ROCK TYPES
The descriptions presented here are primarily based on the petrological nature of the rock types. As many workers use the van Krevelen diagram and the kerogen type nomenclature of Tissot, as set out in Tissot and Welte (1984), the positions of the rock types on these plots are summarized in each section. Many of the oil shales are complex mixtures of macerals and considerable type variation can occur as well as variation due to level of maturation. Bulk chemical analyses represent weighted arithmetic aver- ages of the component macerals. The yields and characteristics of retort oils of mixtures of macerals will not necessarily be the same as those of single macerals or other types of mixtures having the same bulk composition. Although the "kerogen types" are listed here, elemental compositions are better represented within "rock type" (i.e. organic matter assemblage) fields on van Krevelen diagrams.
A. Non-marine
1. Terrestrial-deposited (swamps)--coals, and some coaly shales. Organic matter is abundant in many non-marine sequences deposited for the most part under swampy conditions but not under bodies of open water. The associated epiclastic facies range from channel and barrier sands, to levee deposits and overbank deposits. Most of the organic matter de- posited within the terrestrial regime accumulates as peat. With increasing depth of water, overbank peat facies grades into open-water lacustrine facies as defined here.
Organic matter in terrestrial regimes is dominantly of higher plant origin although minor algal contri- butions are commonly present and products of fungal and bacterial decay are ubiquitous. The organic matter in coal measures sequences exists mainly as seams of coal rather than as coaly shale (Cook and Struckmeyer, 1986).
Liptinite is the dominant maceral in a small pro- portion of coaly shales and coals, but most coals have vitrinite as the main macerai. Some Permian, Triassic, Jurassic, Cretaceous and Early Tertiary coals contain more inertinite than vitrinite. Systematic changes in
Fig. 9. H/C (atomic ratio) plotted against oil shale type.
coal type occur with time (Cook, 1975, 1982, 1986; Thomas, 1982).
2. Lacustrine-deposited (open-water)--cannels, torbanites, lacosites and some coaly shales. Organic matter in most lacustrine sequences is of higher plant origin and inertinite is typically the most abundant maceral. Cannel coals and coaly cannels, however, contain abundant liptinite of higher plant origin. These oil shale types are present in many coal measures sequences, but are not normally important volumetrically.
Some lacustrine deposits contain algal remains and the richer sequences form oil shales. Torbanites are rich in algal remains but are restricted in their occurrence. A more widespread type of algal-rich lacustrine shale has been termed lamosite by Hutton et aL (1980) and Cook et al. (1981) but is here termed lacosite. The typical maceral in lacosites is lamalginite. In some deposits this is derived from Pediastrum, Septodinium or Cleistosphaeridium (Hutton, 1984), but in the Green River Formation it may be eyanobacterial in origin. Lamalginite is a prominent component of some lacustrine source
rocks. Lacosites are well-developed in many Tertiary basin sequences. Examples of thick, extensive lacosite deposits are in the Green River Formation (Col- orado, Utah and Wyoming, U.S.A.), some Tertiary basins of Thailand (including units near the oilfields of Fang and Lan Krabu), the numerous Tertiary basins of eastern Queensland (the best known of which are Rundle [Plate 1 (a)] Stuart and Condor), some of the Oligocene sequences in Sumatera and probably Java, and the early rift sequences in some west African coastal basins. Lacosites are widespread through the geological record. The Irati oil shale of Brazil is possibly a bitumen-impregnated lacosite. Oil shales which are probably lacosites occur in the Carboniferous of the Midland Valley of Scotland (Raymond, pers. commun. 1986). The oldest reported lacosites are Middle Proterozoic and occur in the McArthur Basin of northern Australia (Crick et al., 1988). Botryococcus-rdated telalginite and related forms are commonly minor components in Carbon- iferous and post-Carboniferous lacosites.
High concentrations of Botryococeus-related telalginite constitute torbanite. The type location of
Fig. 10. van Krevelen diagram illustrating the fields of various oil shale types.
torbanite is in the Carboniferous of the Midland Valley of Scotland. The telalginite belongs to the genus Pila. Numerous torbanite deposits exist in the Per- mian of South Africa and Australia, where the telal- ginite is typically derived from the genus Reinschia [Plate l(b)]. Torbanites also exist in some Cretaceous rocks from Canada. Torbanites have very high specific yields of shale oil and by inference a high yield of oil under natural conditions. The rock type is normally not volumetrically significant. Nevertheless, Botry. ococcus evidently makes a contribution to some oils, as chemical biomarkers related to Botryococcus have been reported in some oils by Tissot and Welte (1984).
Lacosites, although dominantly algal in origin, typically plot within the Type II field of Tissot and Welte (1984) on a van Krevelen diagram (Fig. 10). The Green River Formation oil shales plot within the Type I field, possibly because of the presence of large amounts of dispersed bitumens within the sequence. Torbanites plot as Type I kerogen (Fig. 10), and cannels and canneloid shales as Type II/III kerogen on a van Krevelen diagram (Fig. 10).
B. Marine
1. Tasmanite and other rocks rich in tasrnanitid cysts. Tasmanite mainly comprises the tests of unicellular
marine algae (some species being up to 0.5 mm dia). Pachysphaera is a possible related modern form. Oil shales rich in Tasmanites are present in some Permian rocks of Tasmania, the type locality for tasmanite being on the Mersey River in northern Tasmania. A related form is present in a Jurassic tasmanite in Alaska [Plate 2(a)]. Lower concentrations of tasman- itid cysts characterize some widespread source rocks such as the Antrim and Chattanooga Shales of the U.S.A. Tasmanitid cysts also occur as a major or minor component of many source rocks which are dominated either by bituminite or by dinoflagel- late/acritarch cysts.
Tasmanite has a very high H/C ratio and plots in the Type I kerogen field on a van Krevelen diagram (Fig. 10).
2. Kukersite. The type area for kukersite is in Estonia, where a thin but extensive unit exists within the Ordovician where Palaeozoic cover laps onto the Baltic Shield. The organic matter consists almost entirely of telalginite derived from Gloeocapsomorpha [Plate 2(b)]. The algal colonies have some resemblance to Botryococcus colonies. Kukersites, such as those in the Ordovician of the Amadeus and Canning Basins in Australia, occur in fully marine sequences (shown by the presence of graptolites and chitino-
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Classification of oil shales 221
zoans). As compared with other rocks containing telalginite, kukersites have low H/C and high O/C ratios and generally plot as Type II kerogens.
3. Marosite and related shales. Marosites are shales in which the majority of the organic matter is marine and pelagic in origin. The organic matter largely comprises the resting cysts of dinoflagellates and acritarchs [Plate 2(c)]. Units characterized by abundant dinoflagellate/acritarch cysts include the Triassic Kockatea Shale and the Jurassic Dingo Claystone of Western Australia and the Smackover Formation in the Jurassic of the Gulf of Mexico. Some of these units reach 500-1000 m in thickness. Many rocks of this facies are transitional to bitu- minite-rich facies for example, the Kimmeridge Clay commonly contains abundant cysts; these are the most abundant form of organic matter in some horizons. Dinoflagellate and acritarch cysts generally plot within the Type II kerogen field, but some forms plot within the Type I field of a van Krevelen diagram.
4. Bituminite-rich shales--bitosites and related rocks. These are shales deposited in quiet, though typically not very deep, waters. Sediments are well- bedded but in places are weakly bioturbated. Some benthonic fossils are typically present. In most rocks where bituminite occurs evidence exists that the sedi- ment/water interface is dysaerobic or lies just below the aerobic/anaerobic boundary. The most abundant form of organic matter is bituminite occurring as thin lenses but lamalginite and telalginite are nor- mally present as well [Plates 2(d,e)]. Bituminite is commonly stated to be amorphous but some cryptic structures are present. Bituminite is probably derived from degraded cyanobacterial mats (Glikson and Taylor, 1986), red algae and brown algae (Sherwood and Cook, 1986). Some of the most important marine oil shales and source rocks contain both lamalginite and bituminite. Rocks in which bitu- minite is the dominant organic component form a small but distinctive suite, and include some of the Pennsylvanian black shales from Kansas [Plate l(e)]. The term poseidonite refers to a bitosite with >90% by vol (m.m.f. basis) bituminite and the name is taken from the Posidonienscheifer in the Jurassic of Germany. This was probably a major unit examined by Teichmfiller in her studies leading to the proposal of the term bituminite. Other source rocks characterized by an abundance of bitu- minite include the Toarcian of the Paris Basin, the Kimmeridge Clay (U.K. and the North Sea Basin), the Miocene Monterey Formation (Califor- nia), and parts of the Devonian Chattanooga Shale (eastern U.S.A.). Many of these units contain bitu- minite-rich horizons interbedded with horizons rich in acritarch, dinoflagellate, or tasmanitid cysts or a combination of all of these forms. Some bituminite- rich shales are thick as well as laterally extensive. Bituminite plots as Type II/III kerogen on a van Krevelen diagram.
VALUE OF THE CLASSIFICATION OF OIL SHALES
Arkell (1956) commented that the only excuse for having taxa is that they serve a useful purpose. The classification of oil shales and the naming of oil shale types highlights both similarities and differences within organic-rich sedimentary rocks and develops a systematic treatment of the occurrence and chemistry of organic matter in oil shales.
The various types of oil shale typically have differ- ent environments of deposition which result in dis- tinctively different thickness and distribution charac- teristics. For example, most telosites occur as thin and discontinuous units. Although they have very high specific yields of shale oil, they generally are not characteristic of deposits which are large enough to be commercial. Lamosites tend to be much more widespread in their occurrence. Lacosites are com- monly less widespread than marosites but have higher yields of shale oil than most marosites and form a possible base for commercial oil shale industries. Some marobitosites were deposited as very wide- spread deposits and their size is a favourable factor for development of an oil shale industry. Some maro- bitosites also contain significant amounts of heavy metals and, provided these do not pose environ- mental problems, the metal content may be a positive factor in relation to the mining of these oil shales.
The distribution of various oil shale types on a van Krevelen diagram is indicated in Fig. 10. In general, telalginite has the highest H/C ratio and the highest yield of shale oil so that telosites such as torbanite and tasmanite plot in the left part of Fig. 10. Kuker- site, however, has a much lower H/C ratio. Lamal- ginite generally has a lower H/C ratio and a lower specific yield of shale oil than telalginite. Lacosites such as those of the Green River Formation have high specific oil yields, but this, at least in part, is caused by the presence of bitumens. Therefore, the chemical data for the Green River Formation are not representative of only the algal component. Bitu- minite has a low specific yield of shale oil and gives a high yield of residual carbon. Some differences in shale oil composition can also be related to oil shale type.
CONCLUSIONS
Oil shales form a complex group of rocks deposited in a wide range of sedimentary environments and have a wide range of maceral assemblages. They can be classified in terms of their maceral content; the existence of some distinctive suites of maceral assemblages assists the classification procedure.
Oil shales overlap with both coals and petroleum source rocks such that any classification of oil shales has to take these other types into account. The resulting classification has value in simplifying and making more precise, references to different types of oil shales.
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222 A.C. COOK and N. R SrmRWOOD
The major types of oil shales have distinct and different characteristics in terms of bed thickness, lateral extent, specific and overall shale oil yield and shale oil chemistry. The classification has value in relation to attempts to redevelop commercially viable oil shale mining operations. The relationship of oil shale type to depositional environment increases the value of organic petrological studies in basin studies. The close relation of some of the oil shale types to some of the classic petroleum source rock types enables considerable refinement of the classification and delineation of petroleum source rocks. In par- ticular, the relation between the rock types defined and the chemical properties offers opportunities for better integration of chemical and petrological methods.
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