An integrated analytical approach for determining the origin of solid bitumens in the McArthur Basin, northern Australia

Org. Geochem. Vol. 21, No. 3/4, pp. 235-248, 1994 Copyright © 1994 ElsevierScienceLid Printed in Great Britain.All rights reserved 0146-6380/94 $7.00+ 0.00

Pergamon

An integrated analytical approach for determining the origin of solid bitumens in the McArthur Basin, northern Australia S. C. GEORGE, S. M. LLORCAand P. J. HAMILTON CSIRO Division of Petroleum Resources and Australian Petroleum Cooperative Research Centre, P.O. Box 136, North Ryde, New South Wales 2113, Australia AImtract--An integrated analytical approach using petrological, geochemical and isotopic techniques has been used to determine the origin of solid bitumens in the Middle Proterozoic Roper Group, McArthur Basin, northern Australia. Sandstone and dolerite samples, which in hand specimen contain dark material believed to be solid bitumens, were examined from six wells. Under ultraviolet illumination, non-fluorescent solid bitumens can be distinguished from two generations of crude oil, one of lower maturity (orange fluorescence), the other of higher maturity (white fluorescence). Other petrographic observations indicate that the precursor hydrocarbons to the solid bitumens and the subsequent charges of crude oil postdate all diagenetic clay and quartz cementation. Geochemical analyses indicate that many of the sandstones contain both an aliphatic-rich oil and solid bitumen, mixed in varying proportions, thus corroborating the petrological results. On the basis of n-alkane distributions, the oil appears to have two subtly-different source inputs, one of which is typified by a greater proportion of high molecular weight n-alkanes which have a slight even carbon-number predominance and an isotopically lighter aliphatic hydrocarbon fraction. One sandstone sample contains solid bitumen in a fracture which is characterized by a high abundance of asphaltenes, polar compounds and sulphur and may have formed by deasphalting of a precursor oil. The solid bitumens recovered from fractures in dolerite sills were formed by thermal processes which in one sample resulted in an unusual series of ketone isomers. However most solid bitumens, particularly where present in the coarser sandstones, are related to the generation of secondary porosity. The large proportion of unresolved complex mixture, the lack of n-aikanes and the isotopically heavier aliphatic hydrocarbon fractions of samples containing predominantly solid bitumens indicate that bitumen formation occurred mainly by biodegradation of a precursor oil. Key words--solid bitumen, crude oil, fluorescence, Proterozoic, biodegradation, deasphalting, thermal alteration, carbon isotopes

INTRODUCTION Solid bitumens are commonly found in petroliferous basins as black, solid, asphaltic or graphitic coatings, particles and veins within the porosity of reservoir rocks (Rogers et al., 1974). The occurrence of solid ("reservoir") bitumens has been reviewed by Abraham (1945) and Curiale 0986). For the purposes of this paper the definition of solid bitumens by Curiale (1986) is used, viz. "allochthonous, localized organic matter found in, or closely associated with, sedimentary rocks". Only bitumens which are products of the alteration of once-liquid petroleum will be discussed here (post-oil solid bitumens; Curiale, 1986). Solid bitumens can be formed from liquid petroleum by three main processes: thermal alteration, deasphalting, and biodegradation (Evans et ai., 1971, Rogers et al., 1974, Curiale, 1986). Other possible mechanisms for solid bitumen formation include the interaction of oils with the thermochemical reduction of sulphate, which can give rise to bitumens enriched in sulphur and associated with carbonate-hosted lead-zinc deposits (Powell and MacQueen, 1984), and the irradiation of liquid hydrocarbons surrounding radioactive heavy mineral grains such as monazite 235

(Rasmussen and Giover, 1990). The thermal alteration of pre-existing liquid hydrocarbons has frequently been cited as the mechanism of solid bitumen formation (e.g. Parker, 1974; Kirkland, 1988; Sassen, 1988; Dixon et al., 1989; Levine et al., 1991). For example, the black sandstones in the Jurassic Smackover Formation (Gulf Coast, U.S.A.) contain a black residue which is believed to be due to the thermal alteration of a pre-existing oil pool by late Cretaceous igneous intrusions, which also produced methane (Parker, 1974). Deep burial of a pre-existing oil reservoir is expected to have the same effect. During thermal alteration, isotopically light methane is cracked off, so that the solid bitumen has a heavier isotopic ratio and a lower H/C atomic ratio than the original oil (Rogers et al., 1974). This disproportionation reaction leads ultimately to the stable end products of methane and an insoluble ( < 2 % in carbon disulphide, CS2), carbon-rich bitumen residue (Evans et ai., 1971; Rogers et al., 1974). Deasphalting of an oil occurs when large volumes of gas dissolve in an oil and cause the asphaltenes to be precipitated (Evans et ai., 1971; Rogers et al., 1974). This may occur when increasing depth of burial forces gas and other low molecular weight compounds generated during maturation into

236

S.C. GEORGEet al.

solution in an oil (Evans et al., 1971). A bitumen formed by deasphalting is a soluble residue (Levandowski et al., 1973) composed predominantly of asphaltenes, polar compounds and aromatic hydrocarbons, which would have a lower H/C atomic ratio but a similar carbon isotopic ratio compared with the original oil (Rogers et al., 1974). Biodegradation occurs when oils come into contact with surfacederived, meteoric formation waters which can carry dissolved oxygen and microorganisms into a reservoir (e.g. Evans et al., 1971: Bailey et al., 1973). The resultant microbial alteration of the oil results in depletion of certain classes of compounds, in particular n-alkanes, as has been widely documented (e.g. Alexander et al., 1983; Cassani and Eglinton, 1991). Extreme biodegradation results in the formation of tar mats, such as the Athabasca tar sand (Deroo et al., 1974). In this instance the residue or bitumen will contain some aliphatic hydrocarbons, albeit as an unresolved complex mixture (UCM) which appears as a hump in a gas chromatogram. Sofer (1984) has shown that during biodegradation the carbon isotopic composition of the saturate fraction may be shifted by as much as +2%o, whereas the aromatic hydrocarbons are generally less affected ( + 1%o maximum). The presence of solid bitumens in reservoir rocks is significant because they demonstrate that oil generation and al least some migration must have occurred. As well as providing information on the processes of oil degradation, the analysis of solid bitumens can help identify the source rocks responsible for the original oil charge (Curiale, 1986) and, by considering the spatial petrographic relationships between the bitumens and diagenetic cements, the timing of oil migration can be constrained within a

framework of burial diagenesis. The aim of this paper is to illustrate how an integrated analytical approach which utilizes petrographic, geochemical and isotopic techniques can be of value in determining the mechanism by which solid bitumens formed in the McArthur Basin, northern Australia. SAMPLING AND EXPERIMENTAL PROCEDURE

The Middle Proterozoic McArthur Basin in northern Australia (Fig. 1) comprises an unmetamorphosed, structurally simple sedimentary sequence which has considerable petroleum prospectivity (Jackson et al., 1986, 1988; Crick et al., 1988; Summons et al., 1988; Crick, 1992). The Velkerri Formation in the Roper Group (Fig. 1) consists of fine-grained marine sediments, rich in Type II kerogen, which are marginally mature to mature and are thus regarded as potential source rocks for oil (Jackson et al., 1986, 1988: Crick et al., 1988). The Roper Group also contains laterally extensive, wellsorted quartz arenites in which many shows of solid bitumen have been recorded. Crude oil present in the Velkerri Formation is one of the oldest oils in the World (ca 1400Ma: Jackson et al., 1986, 1988). Sixteen samples from cores of sandstone horizons and two samples from dolerite sills, all of which contain obviously discernible solid bitumens, were taken from six wells in the McArthur Basin (Friendship-I, Borrowdale-2, Altree-2, McManus-l, Ladv Penrhyn- I, Scarborough-1 ; Table l). Standard polarizing light petrological microscopy enabled the timing of bitumen occurrences relative to that of diagenet~c cements to be determined. The fluorescence induced by ultraviolet (u.v.) and violetlight irradiation of lhin sections was used 1o

~

~

ChambersRiver Formation McMinnFormation M~roakSstMember VelkerriFormation BessieCreekSandstone CorcoranFormation

~

AbnerSandstone

~ ~/~./t p--_~

Tasman: d LimmenSandstone

Vertical,scale: t tOOOm I Fig. 1. Location of the McArthur Basin, northern Australia and a simplifiedstratigraphic column of the Roper Group (modified from Summons et al., 1988).

Integrated analytical approach for determining solid bitumens

237

Table I. Sample details and geochemical parameters Sample number

Depth (m)

Petrological type

Extractability (%)

CPI (22-28)

Wax ratio

Geochemical group

# 142 # 143 # 144

358.8 366.4 369.9 272.3

II 1,II,IV I,II III

0.24 0.23 0.083

3.4 1.8 1.6

3.9 0.06 3.7

0.97 -1.06

0.96 -0.28

B -A

Borrowdale- 2 # 145 # 146

532.6 509.9

I IV

0.16 0.006

3.3 2.0

2.0 0.5

0.99 --

0.62 0.61

B --

575.7 1127.2 1235.5 1264.7

---IV

0.45 1.08 0.087 0.046

1.9 4.6 8.7 2.5

2.2 2.1 1.2 3.2

1.07 1.09 0.98 0.92

0.23 0.42 0.96 0.41

A A B A/B?

M c Manus - 1 # 150 # 151 # 152

495.8 733.0 821.2

III V --

0.014 0.43 0.81

1.0 2.4 2.2

1.1 1.9 2.6

-1.02 1.03

0.58 0.37 0.20

-A A

Lady Penrhyn-I # 153 # 154

703.2 168.0

IV I

0.036 0.20

1.5 1.5

0.4 2.6

-0.99

1.16 0.75

-B

621.3 629.0 633.0

IV I I

0.05 0.10

1.0 1.3

0.5 0.3

---

0.42 0.77

Ali/Aro

UCM ratio

Friendship - I

Altree-2 # 147 # 148 # 149 # 706

Scarborough-1 # 183 # 184

Ali/Aro = aliphatic-to-aromatic hydrocarbon ratio. U C M ratio = height o f largest n-alkane/height o f U C M " h u m p " in the gas c h r o m a t o g r a m . CPI22_28 = 0.5 (C23-C27/C22-C26)+(C23-C27/C24-C28). W a x ratio = n-C21 to n-Cal/n-Cis to n-C2o,

document the distribution of organic matter. Scanning electron microscopy (SEM) in conjunction with energy dispersive X-ray (EDX) analysis (Cambridge Model 240) with thin window enhancements for the detection of carbon was used to confirm occurrences of bitumen. The morphology of the bitumen occurrences and their relationship to inorganic phases were examined both on fractured and polished surfaces. Sixteen samples (numbered in Table 1) were selected for further geochemical and isotopic work. The exterior portion (ca 5 mm) of the core samples was removed by grinding prior to crushing of the interior in a "Tema" disc mill. Rock powders were exhaustively extracted for 48 h in a mixture of dichioromethane (DCM) and methanol (MeOH) (93:7). Asphaltenes were precipitated by adding a 100-fold excess of n-pentane at room temperature in one batch to up to 300 mg of total extracts in < 1 ml DCM. The soluble maltene fractions were separated into component fractions by column chromatography on silica gel above alumina into aliphatic hydrocarbons [100 ml of petroleum ether (b.p. 40-60°C)], aromatic hydrocarbons [150ml of a mixture of DCM and petroleum ether (4:1)] and polar compounds [100 ml of a DCM and MeOH mixture (1:1)]. Gas chromatograms of the aliphatic and aromatic hydrocarbon fractions were obtained on a Hewlett Packard 5710A gas chromatograph fitted with a fused silica column (25m x 0.33mm i.d.) coated with BPI (methyl silicone, 1 # m film thickness), using a splitless injection technique and a flame ionization

detector (FID). The oven was programmed for an initial temperature of 20°C for 2 min, followed by heating at 4°Cmin -~ to 300°C, where the temperature was held for 28 min. Helium was the carrier gas. Some samples were analysed in greater detail by gas chromatography-mass spectrometry (GC-MS) on a Kratos MS25 fitted with a fused silica column (50m x 0 . 3 3 m m i.d.) coated with BP1 (l/~m film thickness), using an on-column injector. The oven was programmed for an initial temperature of 30°C for 2 min, followed by heating at 4°C min- ~to 300°C. The carbon isotopic composition (3 mac) of the total extract, the four separated fractions (asphaltenes, polar compounds, aromatic and aliphatic hydrocarbons) and de-carbonated whole rock was determined by quantitative combustion in an oxygen atmosphere at 950°C for 15 min to carbon dioxide (CO2) using a modified flow-line oxidation technique with a quartz tube and furnace connected to a glass line and vacuum system (Schoell et al., 1983). Following cryogenic purification of the CO2 its carbon isotopic ratio was determined on a Micromass 602D mass spectrometer and is expressed by the standard notation: 613C(~)

(13C/12C)standard (13C/12C) standard

(13Cr2C) s a m p l e -

x 1000,

where the standard is the "Peedee Belemnite" or PDB (Craig, 1953). The precision of 6 13C was _0.1%o.

S.C. GEORGEet al.

238 RESULTS AND DISCUSSION

Petrology Material observed in thin section which is amorphous and dark brown to black in colour is ascribed to an organic origin and may be crude oil, solid bitumen or detrital particles of organic matter. The modes of occurrence may be divided into five types, as summarized below. Type I occurs as thin, partial to complete coatings of black material on mineral grains. The coatings have no associated birefringence and hence are not mixed with inorganic mineral matter [Fig. 2(a)], and they do not fluoresce under u.v. illumination. The coatings are observable with SEM as smooth, occasionally fragmented coverings with no obvious crystalline structure [Fig. 2(b)]. With EDX analysis these yield a distinct carbon signal and so are identified as solid bitumens. Type II occurrences are solid bitumens with similar properties to type I but are associated with secondary porosity, either as partial linings [Fig. 2(c)] or as partial moulds to pre-existing grains [Fig. 2(d)]. In rare instances, secondary pores have a cross-hatched arrangement of solid bitumen which could be the result of pseudomorphing of a detrital feldspar. The type I and II solid bitumens equate to the various "migrabitumens" identified under reflected light by Crick (1992) in fine-grained samples from the McArthur Basin. Type III comprises solid bitumens associated with fracture surfaces and occurs as amorphous coverings to, and intimate mixtures with, host mineralogy juxtaposed to the fractures [Fig. 2(e)]. Two examples were examined in this study, one of which (sandstone sample # 150 from McManus-l) is unusual in that EDX analysis indicates the presence of sulphur, either as an organically-bound form within the bitumen or as native sulphur. The other example of a fracture bitumen is in a dolerite sample ( # 144) from Friendship-l, in which the calcite mineralization associated with the fracture contains abundant cream-white and yellow fluorescing liquid hydrocarbon fluid inclusions with variable gas contents. Type IV occurrences are dark staining of clay mineral coatings on framework mineral grains and of diagenetic kaolinite and chlorite pore fills. Not all clays exhibit the dark staining and, of those that do, not all exhibit the white fluorescence under u.v. illumination that some examples do. Some clays are enclosed within quartz overgrowths but none of these exhibit fluorescence or staining. Type V is abundant dark amorphous material in the finer grained and more lithic sandstones, some of which occurs as non-fluorescent solid bitumen, some as bright orange fluorescing rims to mineral grains and some as white fluorescing pore fills [Fig. 2(f)]. The bright fluorescence is ascribed to the presence of crude oil. The orange fluorescing oil has not been observed in coarser samples whereas the white

fluorescing material has been observed in both the finer and coarser sandstones. Some of the pore space now occupied by the crude oil is large and angular, indicating that it may be of secondary origin [Fig. 2(f)].

Timing of oil migration and bitumen .]brmation No organic matter, either as fluorescent clays, solid bitumens or fluorescing fluid inclusions was observed within quartz overgrowths or on overgrowth-detrital grain boundaries. Diagenetic cementation appears to have been complete prior to hydrocarbon charge to the sandstones. Fluorescing liquid-bearing hydrocarbon inclusions do occur sporadically, but these are restricted to locations within healed fractures that formed subsequent to quartz diagenesis. In the coarser sandstones, the strong association between the existence of secondary pore space and the spatial distribution of solid bitumens suggests that generation of the secondary porosity occurred after an oil film had coated mineral grains. This dissolution event could have been responsible for the alteration of the oil to form bitumen. In the finer grained sandstones, some secondary pores are now occupied by crude oil and hence invasion of the fluids responsible for generating the secondary porosity occurred prior to this later oil charge. Areas of orange fluorescence are restricted to the finer grained, more lithic sandstones and are indicative of a lower maturity oil than that found in the white fluorescent areas, which occur in porosity and in association with diagenetic clays in both coarse and fine sandstones. The finer grained sandstones have therefore preserved a record of the migration of an earlier generation of oil which is not present in the coarser sandstones, whereas the higher maturity and more recent oil is present in both fine and coarse grained sandstones.

Organic geochemtstrv The extractability of the 16 samples analysed geochemically is very variable (<0.01-1.08%; Table 1) and bears some relationship to the amount of bitumen visible in hand specimens. It is stressed that these data relate to the whole samples, including mineral grains, and not to isolated organic fractions. The solid bitumens are predominantly extractable, as can be judged by the loss of dark material from the extracted rock. The copper turnings in the solvent mixture of one sample ( # 150) were highly reduced during extraction, indicating the presence of elemental sulphur, which corroborates the EDX analysis of the fracture bitumen in this sample. The compositional characteristics of the extracts are mainly a function of variation in the relative proportions of aliphatic hydrocarbons and the polar compounds + asphaltenes, with the proportion of aromatic hydrocarbons mostly falling between 10 and 24% (Fig. 3). Bitumens rich in asphaltenes and polar compounds were extracted from the sandstone with high sulphur content ( # 150) and from the two dolerite samples

Fig. 2. (a) Photomicrograph (plane polarized light) of opaque, non-fluorescent solid bitumen coating the corroded surface of quartz overgrowths; Scarborough-1,633.0 m, field of view = 610 #m. (b) Scanning electron photomicrograph of Type I solid bitumen as a fragmented coating on quartz overgrowths; Scarborough-1, 629.0 m (sample # 184), field of view = 29 #m. (c) Photomicrograph of solid bitumen (Type II) lining secondary porosity; Friendship-l, 358.8 m, field of view = 700 gm. (d) Scanning electron photomicrograph of solid bitumen (Type II) forming a partial mould of a pre-existing grain; Friendship-1, 369.9 m (sample # 143), field of view = I01/tm. (e) Scanning electron photomicrograph of Type Ili solid bitumen coating a fracture surface in a sandstone. In the central part of the view it partially covers quartz overgrowths and diagenetic kaolinite; McManus-1, 495.8 m (sample # 150), field of view = 33/Jm. (f) Photomicrograph taken with u.v. illumination showing the co-existence of non-fluorescent solid bitumen (left of centre), orange fluorescent crude oil rim to mineral grain (further to left) and large white fluorescent secondary pore fills of crude oil; McManus-l,733.0 m (sample # 151), field of view = 330#m.

239

Integrated analytical approach for determining solid bitumens

o%

o,

' v ....

°/-

0

i

i

i

20

40

60

i .... \ o 80

100

Asphaltenes and polar compounds (%) Fig. 3. Ternary diagram showing the proportion of aliphatic hydrocarbons, aromatic hydrocarbons and polar compounds + asphaltenes in the extracts of samples from the McArthur Basin. ( # 144 and # 146). The aliphatic-to-aromatic ratios mostly fall between 1 and 3.5 (Table 1), except for two samples from Altree-2 ( # 148 and # 149) which are much richer in aliphatic hydrocarbons. Similar aliphatic-to-aromatic ratios have been noted in mature fine-grained sediments from the McArthur Basin (Summons et al., 1988). Aliphatic hydrocarbon distributions are extremely variable, as exemplified by two samples only 3.5 m apart (Friendship-l). Sample # 142 [Fig. 4(a)] has a prominent homologous series of n-alkanes with a maximum at n-Cl9, whilst sample # 143 [Fig. 4(b)] contains no identifiable n-alkanes and only a large unresolved complex mixture (UCM). Most samples have a distribution intermediate to these two endmember compositions [e.g. sample # 148, Fig. 4(c)]. As a qualitative measure of the relative amount of unresolved material in the aliphatic hydrocarbon fraction, a "UCM ratio" is defined as the height of the largest n-alkane/height of UCM "hump" in the aliphatic hydrocarbon gas chromatogram (Table 1). It is recognized that this ratio could vary quite strongly depending on the particular gas chromatography conditions used, particularly the programme rate, so gas chromatograms for all samples were acquired using carefully controlled standard conditions. The UCM ratio varies from 3.9 (sample # 142) to 0,06 (sample # 143). Five samples have very low UCM ratios (<0.5; Table 1) and must have undergone extensive biodegradation which removed most n-alkanes. UCMs are generally considered to be composed of structurally complex branched and cyclic hydrocarbons (e.g. Eglinton et al., 1975), although recent work has demonstrated that they may in part consist of relatively simple compounds such as isomeric monoalkyl substituted "T"branched alkanes (Gough and Rowland, 1990; Gough et al., 1992). These compounds are resistant OG 21-3/4--43

241

to biodegradation compared to n-alkanes and monomethyl alkanes (Gough et aL, 1992) and thus the UCM is a response to removal of the latter and the relative concentration of compounds that cannot be resolved by gas chromatography. The samples which have UCM ratios > 1.0 are characterized by n-alkanes ranging from about n-C~0 to n-C32, with low molecular weight maxima (n-Cl4 to n-El9 ). Detailed GC-MS analysis of sample # 144 indicates that only very low amounts of pristane and phytane are present. The peaks eluting between the n-alkanes are mostly due to monomethyl branched aikanes, although a homologous series of n-alkylcyclohexanes with a similar carbon number distribution to that of the n-alkanes was also detected in sample #144. The m / z 191 and 217 mass chromatograms were carefully monitored, but no hopanes or steranes could be detected. These hydrocarbon distributions are similar to those of fine-grained marine sediments in the McArthur Basin (Summons et al., 1988). A high abundance of monomethyl alkanes appears to be characteristic of Precambrian sediments and oils (Hoering, 1981; Fowler and Douglas, 1987; Summons et al., 1988, and references therein). These compounds may originate from the diagenetic migration of methyl groups on the carbon chain (e.g. Hoering, 1981), although on the basis of isomer distributions Summons et al. (1988) argued for a direct, primary biogenic origin, possibly from long-chain monomethyl fatty acids. Close inspection of the n-alkane profiles of the samples that are not highly biodegraded (UCM ratios > 1.0) indicates some subtle variations which can be used to group the samples, irrespective of the relative size of their UCM. Group A samples ( # 144, # 147, # 148, # 151 and # 152) contain a preponderance of lower molecular weight n-alkanes ( < n-C16) and have no odd or even carbon number predominance [e.g. Fig. 4(c)]. Group B samples ( # 142, # 145, # 149 and # 154) contain more higher molecular weight n-alkanes and a distinct even-carbon number predominance in the high molecular weight region [e.g. Fig. 4(a)]. In particular, n-C24 and n-C26 are of noticeably greater abundance than the adjacent odd-carbon number homologues. These variations can be quantified by a high molecular weight carbon preference index (CPI22 28; Table 1) and by a wax ratio (n-C2t to n-C3i/n-Cl5 to n-C20; Table 1), a cross plot of which is shown in Fig. 5. Sample # 706 has characteristics of both these groups, with a low wax ratio and a slight even-carbon number predominance. The highly biodegraded samples with UCM ratios <0.5 are not included on this graph; nor is sample # 150, because it contains no n-alkanes > n-C26 and thus the CPI22 2s could not be calculated. Sample # 150 has a rather different n-alkane distribution from that of the other samples, with bimodal maxima at n-Cl4 and n-Ct8 and a relatively large UCM (UCM ratio= 1.1), which may relate to a different origin for this fracture bitumen.

242

S.C. GV,OROEet al,

!

~9

~7

l 10

20

30

40

50

60

70

80

90

Retention time (rain)

Fig. 4. Gas chromatograms of (a) aliphatic hydrocarbons, sampie# 142. Friendship-l~ (b) aliphatic hydrocarbons, sample #143, Friendship-I; (c) aliphatic hydrocarbons, sample #148, Altree-2; (d) aromatic hydrocarbons, sample # 142, Friendship-l; (e) aromatic hydrocarbons, sample # 144, Friendship-1. Numbers refer to n-alkane carbon chain length.

A predominance of even carbon-number n-alkanes between n-C2~ and n-C3, as in the four Group B samples has not been demonstrated previously in the McArthur Basin and may be due to a subtle source variation, The fine-grained sediment extracts analysed by Summons et aL (1988) are very similar to the Group A samples of this study. Even carbonnumber n-alkane predominances are commonly associated with highly saline and anoxic carbonate environments (e.g. Dembicki et aL, 1976; Tissot et al., 1977: Sofer, 1988) and may be due to the reduction of precursor fatty acids or alcohols, instead of their decarboxylation (Welte and Ebhardt, 1968; Kvenvolden, 1970), Recently n-atkanes with a strong even carbon-number predominance have been found

in a wide range of sedimentary environments, including marine and freshwater systems as well as oxic and anoxic depositional conditions (Grimalt and Albaig~s, 1987; Nishimura and Baker, 1986: Kennicutt and Brooks, 1990), thus suggesting a biological source from bacteria or fungi which is more plausible for Middle Proterozoic sediments. The four Group B samples are from four different wells so this source difference is not geographical; they also have widely varying UCM ratios so it is unlikely that their n-alkane distribution relates to a particular degree of secondary alteration. The aromatic hydrocarbon fractions of most samples are dominated by UCMs and therefore provided little useful information. Even those

Integrated analytical approach for determining solid bitumens

243

-29.0"

1.15

.3o01

Group A 1.10.

1.05,

1.00!

e~ " " ~ 149w ....... "'""

70 -33.01 1

5

,"

1

",

~

""N 149

~

~

---l'~ 143

0.95"

El 0.90

' 0.0

'

•

i

.

.

.

0.2

i

0.4

.

.

.

i

,

,

0.6 Wax ratio

,

i

.

,

0.8

•

i 1.0

.

.

•

1.2

Fig. 5. Plot of the high molecular weight carbon preference index (CPI22_2s) versus the wax ratio (n-Czt to n-C3t/n-Cls to n-C20). Group B samples contain more higher molecular weight n-alkanes and have a slight even-carbon number predominance. samples which contain abundant n-alkanes in their aliphatic hydrocarbon fraction have a very poorly resolved aromatic fraction [e.g. sample #142, Fig. 4(d)]. The aromatic hydrocarbon fraction of one of the dolerite samples ( # 144) contains an unusual and prominent homologous series of doublet peaks, together with a marked UCM [Fig. 4(e)]. Detailed G C - M S analysis of this sample reveals that these peaks are due to a complex series of saturated C7-C27 ketones, including n-alkan-2-ones, n-alkan-3-ones and various branched, mid-chain isomers (George and Jardine, 1994). Ketones are not present in any of the sandstone samples, nor in the other dolerite sample. The ketones in sample # 144 have a quite different distribution from those found in recent sediments (e.g. Volkman et al., 1983; Grimalt et al., 1991) and hence are unlikely to be due to weathering or microbial oxidation (George and Jardine, 1994). Ketones are normally either absent or present in only very small quantities in the solvent extracts of rocks (e.g. Saban et al., 1980), but they are found in considerable abundance in the pyrolysates of oil shales (shale oil), implying that the ketone precursors are bound into the kerogen and only released during

13

WR

TE

AS

PO

AR

AL

Fraction

Fig. 6. Isotope-type curves (Stahl, 1978) to show variation in ,5 ~3C of decarbonated whole rock (WR), total extract (TE), asphaltenes (AS), polar compounds (PO), aromatic hydrocarbons (AR) and aliphatic hydrocarbons (AL) for samples from Friendship-1 (# 142, # 143 and # 144), Altree-2 (# 149 and #706) and McManus-I (# 151). rapid heating, or that they are artefacts of the pyrolysis process (e.g. Klesment, 1974; Regtop et al., 1982; Ingram et al., 1983; Rovere et al., 1983; Harvey et al., 1984, 1985). By analogy, it is likely that the ketones in sample # 144 are due to the natural pyrolysis of kerogen within fine-grained sediments associated with the dolerite sill, the liquid products from this process being concentrated in fractures and vesicles as solid bitumen and as fluid hydrocarbon inclusions (George and Jardine, 1994). Carbon isotope geochemistry

Carbon isotope data for the samples from the McArthur Basin are summarized in Table 2. For most samples the carbon isotopic composition of the whole rock (6'3Cwr) is similar to that of the total extract (6 t3Cte), whereas the asphaltenes (6 J3C,~) are considerably heavier (more positive). The isotopetype curves (Stahl, 1978) for representative samples illustrate how 6 ~3C varies with the polarity of the fraction (Fig. 6). Sample # 142 has the isotopically lightest aliphatic hydrocarbon fraction of the whole

Table 2. Carbon isotope data for the different fractions of the samples from the McArthur Basin

Sample

Whole rock 6 ~3C(%o)

Total extract 6 13C(%o)

Asphaltenes 6 ~3C(%0)

Polar compounds c~13C(%o)

Aromatic hydrocarbons 3 t3C(%o)

Aliphatic hydrocarbons 3 13C(%o)

#142 # 143 # 144 #145 # 146 # 147 # 148 # 149 #706 #150 #151 #152 #153 #154 #183 # 184

-33.2 -33.2 -32.9 -33.3 -30.4 -33.5 -33.5 -32.2 -31.6 -30.3 -33.0 -33.5 -32.2 -33.3 -32.8 --32.9

-33.8 -33.2 -33.2 -33.8 -30.9 -33.6 -33.2 -31.8 -31.5 -30.9 -33.2 -33.2 -32.5 -33.2 -32.6 --31.8

-32.5 -32.7 -31.3 -31.6 -29.2 -33.1 -32.3 -29.5 -29.5 -29.2 -32.4 -32.7 -30.5 -32.9 -31.5 -31.2

-33.4 -32.9 -33.1 -33.1 -31.6 -33.4 -32.5 -31.2 -30.6 -30.7 -33.0 -33.0 -31.5 -33.2 -32.5 -31.9

-33.5 -33.2 -33.2 -33.1 -31.4 -33.4 -32.7 -30.6 -30.9 -31.7 -33.0 -33.0 -32.3 -33.5 -32.7 -32.1

-34.3 -33.0 -33.4 -33.9 -30.4 -33.5 -33.3 -32.3 -31.4 -30.6 -33.3 -33.3 -32.9 -34.1 -32.5 -32.4

244

S.C. GEORGEet

at.

-30.0 •

-30.51 -31.0

146

l • [ 150

O Group A • Group B Undifferentiated

•

Large UCM

706

,~ 32 0 •~

-a2.5-

-33.o- I

Mod~ate U(~I

149

Minor

"8 -33.5i k -34.0 :

-34.5 . . . . j . . . . i . 0.0 0.5 1.0

.

.

.

.

.

1.5

.

.

.

.

.

.

.

.

.

.

2.0 2.5 UCM ratio

.

.

.

.

3.0

3.5

4.0

Fig. 7. Plot of 6 t3C of aliphatic hydrocarbons versus the UCM ratio (height of largest n-alkane/height of UCM "hump" in the gas chromatogram) for samples from the McArthur Basin. Symbols distinguish the Group A from the Group B samples, and the undifferentiated samples (mostly biodegraded). sample suite (-34.3%0); this fraction also has the smallest UCM [Fig. 4(a); UCM ratio = 3.9]. The more polar fractions display a trend of heavier isotopic compositions with increasing polarity of the fraction, due to the normal thermodynamic ordering of carbon isotope systems (e.g. Galimov and Kodina, 1983). The total extract is only slightly isotopically heavier (-33.8%0) than the aliphatic hydrocarbon fraction, reflecting the large proportion of aliphatic hydrocarbons in the total extract of this sample (54.3%, Fig. 3). The whole rock is isotopically 0.6%0 heavier than the total extract, indicating the presence of a significant amount of non-extractable and isotopically heavier organic matter in this sample. In contrast, sample # 143 has a much flatter isotope profile, with total isotopic variation between the fractions being only 0.5%0. Indeed, the aliphatic hydrocarbon fraction is slightly isotopically heavier than the aromatic hydrocarbon fraction, due to the intense biodegradation which preferentially utilizes the isotopically light components of the aliphatic hydrocarbon fraction by a kinetic isotope effect; this is also manifested in the large UCM detected in the aliphatic hydrocarbon fraction of this sample [Fig. 4(b)]. The flat isotope-type curve of sample # 143 is accentuated because the polar compounds and the asphaltene fraction are isotopically lighter than might be expected. This could be due to the generation of high molecular weight condensation products from initially t2C-enriched sources (i.e. aliphatic hydrocarbons), although this has only been observed previously in thermally altered rocks in which disproportionation reactions have occurred (Galimov and Kodina, 1983). Many samples have isotope-type curves intermediate between the two end-members represented by # 142 and # 143; one example ( # 151) is shown in Fig. 6. Ignoring samples with much heavier isotopic signatures, which are discussed later, there is a trend

for samples with a large UCM to have less negative 6 J3Ca~values, whilst samples with a minor UCM tend to be isotopically lighter (Fig. 7). This is particularly well illustrated by the 6 ~3C,r versus 6 ~3Calplot (Fig. 8), which includes the correlation lines described by Sofer (1984) for waxy and nonwaxy oils. Sofer (1984) has demonstrated that biodegradation of oils results in a positive shift in the isotope compositions of both the saturate (equivalent to the aliphatic hydrocarbon fraction in this paper) and the aromatic hydrocarbon fractions. This is generally more pronounced for the saturate fraction (up to 2%o), than the aromatic hydrocarbon fraction (up to 1%o), presumably because biodegradation has a more pronounced effect on n-alkanes, which are an isotopically light and volumetrically significant part of saturate fractions. This approximate biodegradation trend is shown on

°

U C M m l i o < 1.S

•

UCM

ratio

-29.0.

Waxy

1 ,

-35.0 t . . . . -36.0

1.5 t o 3.0

•

UCM

/

ratio

> 3.0

I

/ "

z.----*// 15 1s2

,r, . . . . -35.0

, .... -34.0

/

, .... -33.0

/

=°

, .... -32.0

813(: o f a l i p h a t i c h y d r o c a r b o n s

, .... -31.0

, .... -30.0

-29.0

(*/~o)

Fig. 8. Plot of 6 ~3Cof aromatic hydrocarbons versus 6 ~3C of aliphatic hydrocarbons for samples from the McArthur Basin. Correlation lines for waxy and nonwaxy oils and the direction of biodegradation are taken from Sofer (1984). Symbols indicate the size of the UCM in the aliphatic hydrocarbon fraction.

Integrated analytical approach for determining solid bitumens the t$ ~3Carversus 6 13Calplot (Fig. 8) and corresponds well with the trend from the "least altered" to the "most altered" samples. The samples tend to cluster around the nonwaxy correlation line constructed by Sorer (1984; Fig. 8), as would be expected for organic matter derived from type II kerogen in Middle Proterozoic source rocks. Compared with the bulk of Phanerozoic oils, it is evident that the McArthur Basin samples are considerably isotopically lighter, a finding corroborated by analyses of other Proterozoic oils and sediments (Golyshev, 1984; McKirdy and Hahn, 1982; Golyshev et al., 1991) and presumably due to the peculiar chemical composition of the biomass of Precambrian organisms. The dolerite sample #144 has an isotope-type curve which is similar to that of sample # 142, but its fractions are consistently isotopically heavier, particularly the asphaltenes and aliphatic hydrocarbons (Fig. 6). Three of the samples which have more high molecular weight n-alkanes and a slight even carbonnumber predominance (Group B samples: #142, # 145 and # 154; Fig. 5) have the three isotopically lightest aliphatic hydrocarbon fractions, despite variation in their UCM ratio (Fig. 7). Thus the differences in 6 ~3Ca~between these Group B samples (e.g. # 142) and Group A samples (e.g. # 144) may be due to the same subtle source variation noted by gas chromatography. The aromatic hydrocarbon fraction of sample # 144, which contains the ketone isomers, has an isotopic composition that would be predicted from that of the other fractions (Fig. 6), so the ketones must have a gross isotopic composition which is similar to that of the other components of this fraction. It is clear from Figs 7 and 8 that there are four samples which do not fall into the pattern described above. One of these (sample # 149) was classified by gas chromatography as a Group B sample, but is considerably isotopically heavier than the other Group B samples (Fig. 6). This can be accounted for either by the larger UCM in this sample, or by a different organic matter source. Sample # 706 also has fractions which are considerably isotopically heavier than most samples, although it has a more uniform and predictable variation of t5 ~3C relative to fraction polarity (Fig. 6). This, together with its n-alkane distribution which has similarities with both Group A and B (Fig. 5), suggests that the organic matter in this sample has a different source. The reason for samples # 146 and # 150 being isotopically heavier than most other samples may relate to the mechanism of solid bitumen formation. Sample #146 is from a dolerite sill and thus must have formed by thermal processes. The large UCM in the aliphatic hydrocarbon fraction of this sample suggests that it was also affected by biodegradation. Sample # 150 is the fracture bitumen from a sandstone which is rich in sulphur and has a high proportion of asphaltenes and polar compounds.

245

ORIGIN OF THE SOLID BITUMENS AND OCCURRENCE OF CRUDE OIL

The geochemical and isotopic characteristics of five of the samples (#143, #146, #153, #183 and # 184) are commensurate with them having undergone extensive biodegradation. These samples have large UCMs, low amounts of n-alkanes, UCM ratios < 0.5 and aliphatic hydrocarbon fractions depleted in 12C. The order of susceptibility of hydrocarbon groups to bacterial attack has been extensively studied and it has been shown that n-alkanes tend to be biodegraded at a faster rate than other compound classes and thus become preferentially depleted (e.g. Alexander et al., 1983; Cassani and Eglinton, 1991; Gough et al., 1992). Aromatic hydrocarbons are generally attacked at a slower rate and in the order monoaromatics, diaromatics and then triaromatics (Connan, 1984), although there is some overlap between groups, and individual isomers sometimes exhibit different susceptibilities (Rowland et al., 1986). This biodegradation sequence implies some difficulty in the interpretation of the gross composition of the aliphatic and aromatic hydrocarbons for samples in this study because the aromatic hydrocarbon fractions of the solid bitumens in all the sandstone samples exhibit a large UCM. Therefore biodegradation must have been severe in all cases, including those samples in which the aliphatic hydrocarbon fraction shows little or no evidence of biodegradation (samples # 142 and #706). The aliphatic hydrocarbon fractions of many of the samples are composed of both a minor UCM and an extensive homologous series of n-alkanes (UCM ratios 1-3), including n-aikanes of low molecular weight (n-Cl~ to n-Cls) which would normally be expected to be attacked by bacteria at an early stage (cf. Connan, 1984). This evidence indicates that the samples in this study do not show a simple biodegradation sequence. Instead there must be two components involved in these samples, one of which has been heavily biodegraded, the other which has undergone virtually no biodegradation. The solid bitumens are considered to have been highly biodegraded in all the sandstone samples, but when these were extracted a portion of crude oil was also obtained in most cases. Sample # 143, which contains no n-alkanes, is typical of the extracted solid bitumen alone, whilst samples # 142 and # 706 which contain most n-alkanes relative to the UCM, are typical of extracts containing a large proportion of crude oil. The proportion of crude oil in the other samples can be estimated by the relative abundance of the n-alkanes and the UCM (the UCM ratio; Table 1). The samples with the largest contribution from crude oil have few resolvable peaks in the aromatic hydrocarbon fractions and thus it is likely that the crude oil is extremely enriched in aliphatic hydrocarbons. This conclusion, which is deduced primarily from the organic geochemistry data, is corroborated by both petrology and isotope geochemistry. The spatial

246

S.C. GEORGEet al.

distribution of solid bitumens in secondary porosity suggests that they formed as a result of the alteration of an early oil during a dissolution event and that crude oil has subsequently migrated into the sandstone. By examining the distribution of fluorescence induced by u.v. light, it was possible to identify non-fluorescent solid bitumen together with two generations of crude oil in the same samples [e.g. Fig. 2(f)]. It has not been possible to distinguish geochemically between the low maturity oil, which occurs as bright orange fluorescence rims in some of the finegrained sandstones, from the high maturity oil, which has white fluorescence. On the basis of petrography the low maturity oil is considerably less abundant than the high maturity oil and where present it is presumably swamped geochemically by the latter when a sample is extracted. There is no correlation between the observed presence of low maturity oil and either the Group A or Group B n-alkane distributions which could be distinguished geochemically. These two groups represent subtly-different source inputs for crude oils in the sandstone samples and are not related to any maturity variation. The isotope-type curves (Fig. 6) and the position of most samples on the plots of 3 ~3C~jversus UCM ratio (Fig. 7) and ~ 13C,~ versus 6 13C,j (Fig. 8) clearly corroborate the presence of both crude oil and biodegraded solid bitumens. The samples with only minor UCMs, which contain predominantly crude oil, plot near the correlation line for nonwaxy samples (Fig. 8; Sofer, 1984), whilst the samples containing mainly solid bitumen are depleted in ~2C and plot away from this line in the direction predicted by Sofer (1984) for biodegraded samples. Those samples with an even mix of oil and biodegraded solid bitumen plot between these two extremes. As discussed in the previous section, the heavier isotopic ratios of two of the sandstone samples may be related to a different organic matter source which was not clearly distinguished by organic geochemistry, Deasphalting of oils results in solid bitumens which are soluble and which have a similar carbon isotopic ratio to the original oil (Levandowski et al., 1973; Rogers et al.. 1974) and thus it could be argued that the solid bitumens in the sandstones analysed in this study have formed by deasphalting. However the high abundance of aliphatic hydrocarbons in those samples containing little or no crude oil suggests that this is not the case, as bitumens formed by deasphalting would also be expected to be enriched in asphaltenes, polar compounds and aromatic hydrocarbons (Rogers et al., 1974). The one exception is the solid bitumen of sample # 150 from McManus- 1, which is from a fracture in a sandstone. This sample is characterized by a high abundance of asphaltenes and polar compounds (Fig. 3), a high sulphur content and also a rather unusual distribution of aliphatic hydrocarbons. It is suggested that this solid bitumen could be the result of sulphate reduction associated with deasphalting. Sulphate reduction can occur on the intro-

duction of a hydrocarbon gas phase which would yield H 2S and promote deasphalting of a precursor oil to form bitumen; the presence of H2S could result in the formation of native sulphur in intimate association with the bitumen. Bitumens formed by thermal alteration are expected to be virtually insoluble and to have a heavier isotopic ratio than the precursor oil (Evans et al., 1971; Rogers et al., 1974). The intimate mixture of solid bitumen and crude oil in most of the samples makes any judgement on the extractability of the solid bitumen alone impossible, but the sandstone samples containing only solid bitumen ( # 143, # 153, #183 and #184) are moderately extractable (0.0364).23% of the total sandstone, including mineral grains). Taking into account the low amount o1 bitumen relative to quartz grains in these samples, the solid bitumen is regarded as being moderately to fully soluble in organic solvents. Furthermore, the gross carbon isotopic compositions (6 ~3C~ and 6 ~3C,,) o1" the four samples containing only solid bitumens fall between -31.8%o and -33.2%0, values which are similar to those fbund for Precambrian oils (Golyshev, 1984; McKirdy and Hahn, 1982). It is unlikely that a precursor oil could have had a significantly lighter isotopic composition, so there is no evidence to suggest that the bitumens in any of the sandstone samples were lbrmed by thermal alteration. Solid bitumen from one of the dolerite samples ( # 146) is only slightly extractable and has a heavier isotopic composition than most of the sandstone samples. This bitumen may have formed by thermal alteration, although the large UCM in its aliphatic hydrocarbon fraction indicates that it must have also undergone subsequent biodegradation. The other dolerite sample ( # 144) contains both fracture bitumen and fluorescing hydrocarbonbearing fluid inclusions associated with secondary calcite mineralization. The extract of this sample contains abundant ketones. This evidence, together with the position of the sample from within a thick dolerite sill indicates that the thermal alteration and natural pyrolysis of kerogen in fine-grained sediments associated with the sill can best explain this bitumen occurrence. However, this is not the thermal alteration of a pre-existing oil p e r st'. as demonstrated by Parker (1974) in the Jurassic Smackover Formation and by George (1990, 1993) in the Midland Valley of Scotland. Thus the products are extractable and have similar isotopic compositions to those of other samples in the McArthur Basin. One unknown about this sample is whether the unusual ketone isomers were extracted from the fracture bitumen or the hydrocarbon fluid inclusions (George and Jardine, 1994). Perhaps the most likely explanation is that following generation of liquid products by natural pyrolysis of kerogen, secondary mineralization took place in the cooling sill and some liquids were trapped in a pristine state in the inclusions. The remainder of the liquid was concentrated on fractures and thus was

Integrated analytical approach for determining solid bitumens more prone to subsequent alteration and biodegradation, hence explaining the slight U C M s in the aliphatic and aromatic hydrocarbon fractions of this sample. CONCLUSIONS

1. M a n y of the samples from the Middle Proterozoic M c A r t h u r Basin contain both an aliphaticrich crude oil and solid bitumen, mixed in varying proportions. The crude oil is hosted either within fluid inclusions in fractures across mineral grains or in unconnected pores in the sandstones. 2. On the basis of n-alkane distributions the crude oil appears to have two subtly-different source inputs. Fluorescence studies indicate migration of two generations of crude oil, one of which is of lower maturity. 3. Diagenetic cementation was complete prior to hydrocarbon charge to the sandstones. 4. Solid bitumen formation in coarser sandstones is related to the generation o f secondary porosity. 5. O f the three plausible mechanisms for the formation of solid bitumens in the sandstones (thermal alteration, deasphalting and biodegradation), biodegradation of a precursor oil explains both the geochemical and isotopic observations best. 6. One sandstone sample ( # 150) contains solid bitumen which is characterized by a high abundance of asphaltenes and sulphur and may have formed by deasphalting of a precursor hydrocarbon. 7. The solid bitumens recovered from fractures in dolerite sills were formed by thermal processes and in one sample ( # 144) resulted in an unusual series of ketone isomers.

Acknowledgements--We thank Geoff Hansen and Manal Kassis for careful sample preparation and mineral separations, Chris Taylor for photography and Peter Eadington for fluid inclusion petrography. Pacific Oil & Gas Pty Limited are thanked for their support of this project. The CSIRO Division of Petroleum Resources comprises part of the research activities of the Australian Petroleum Cooperative Research Centre (APCRC). REFERENCES

Abraham H. (1945) Asphalts and Allied Substances. Van Nostrand-Rheinhold, New York, 2142 pp. Alexander R., Kagi R. I., Woodhouse G. W. and Volkman J. K. (1983) The geochemistry of some biodegraded Australian oils. APEA J, 23, 53-63. Bailey N. J. L., Krause H. R., Evans C. R. and Rogers M. A. (1973) Alteration of crude oil by waters and bacteria-evidence from geochemical and isotope studies, Am. Assoc. Pet. GeoL Bull. 57, 1276-1290. Cassani F. and Eglinton G. (1991) Organic geochemistry of Venezuelan extra-heavy crude oils, 2. Molecular assessment of biodegradation. Chem. Geol. 91, 315-333.

247

Connan J. (1984) Biodegradation of crude oils in reservoirs. In Advances in Petroleum Geochemistry, Iiol. 1 (Edited by Brooks J. and Welte D. H.), pp. 229-335. Academic Press, London. Craig H. (1953) The geochemistry of the stable carbon isotopes. Geochim. Cosmochim. Acta 3, 53-92. Crick I. H. (1992) Petrological and maturation characteristics of organic matter from the Middle Proterozoic McArthur Basin, Australia. Aust. J. Earth Sci. 39, 501-519. Crick I. H., Boreham C. J., Cook A. C. and Powell T. G. (1988) Petroleum geology and geochemistry of Middle Proterozoic McArthur Basin, Northern Australia, II: Assessment of source rock potential. Am. Assoc. Pet. Geol. Bull. 72, 1495-1514. Curiale J. A. (1986) Origin of solid bitumens, with emphasis on biological marker results. Org. Geochem. 10, 559-580. Dembicki H. Jr, Meinschein W. G. and Hattin D. E. (1976) Possible ecological and environmental significance of the predominance of even-carbon number C204::30 n-alkanes. Geochim. Cosmochim. Acta 40, 203-208. Deroo G., Tissot B., McCrossan R. G. and Der F. (1974) Geochemistry of the heavy oils of Alberta. In Oil Sands Fuel of the Future, Mem. 3, Can. Soc. Pet. Geol., pp. 148-167. Dixon S. A., Summers D. M. and Surdam R. C. (1989) Diagenesis and preservation of porosity in Norphlet Formation (Upper Jurassic), Southern Alabama. Am. Assoc. Pet. Geol. Bull. 73, 707-728. Eglinton G., Maxwell J. R. and Philp R. P. (1975) Organic geochemistry of sediments from contemporary aquatic environments. In Advances in Organic Geochemistry 1973 (Edited by Tissot B. and Bienner F.), pp. 941-961. Editions Technip, Paris. Evans C. R., Rogers M. A. and Bailey N. J. L. (1971) Evolution and alteration of petroleum in western Canada. Chem Geol. 8, 147-170. Fowler M. G. and Douglas A. G. (1987) Saturated hydrocarbon biomarkers in oils of late Precambrian age from Eastern Siberia. Org. Geochem. 11, 201-213. Galimov E. M. and Kodina L. A. (1983) Organic matter in oceanic sediments of high thermogradient (DSDP Leg 64, Gulf of California). In Advances in Organic Geochemistry 1981 (Edited by Bjorgy M. et al.), pp. 431-437. Wiley, Chichester. George S. C. (1990) The influence of igneous activity on the generation and accumulation of petroleum in the central area of the Midland Valley of Scotland. Unpublished Ph.D. thesis, University of Newcastle upon Tyne. George S. C. (1993) Black sandstones in the Midland Valley of Scotland: thermally metamorphosed hydrocarbon reservoirs? Trans. R. Soc. Edin. Earth Sci. 84, 61-72. George S. C. and Jardine D. R. (1994) Ketones in a Proterozoic dolerite sill. Accepted by Org. Geochem. Golyshev S. I. (1984) Application of stable carbon isotopes in geochemical investigations. In Modern Methods of Oil Investigation, pp. 405-423. Nedra, Moscow. Golyshev S. I., Verkhovskaya N. A., Burkova V. N. and Matis E. Y. (1991) Stable carbon isotopes in source-bed organic matter of West and East Siberia. Org. Geochem. 17, 277-291. Gough M. A. and Rowland S. J. (1990) Characterization of unresolved complex mixtures of hydrocarbons in petroleum. Nature 344, 648-650. Gough M. A., Rhead M. M. and Rowland S. J. (1992) Biodegradation studies of unresolved complex mixtures of hydrocarbons: model UCM hydrocarbons and the aliphatic UCM. Org. Geochem. 18, 17-22. Grimalt J. and Albaig6s J. (1987) Sources and occurrence of CI2-C22 n-alkane distributions with even carbon-number preference in sedimentary environments. Geochim. Cosmochim. Acta 51, 1379-1384.

248

S.C. GEORGE et al.

Grimalt J. O., Yruela 1., Saiz-Jimenez C., Toja J., de Leeuw J. W. and Albaig~s J. (1991) Sedimentary lipid biogeochemistry of an hypereutrophic alkaline lagoon. Geochim. Cosmochim. Acta 55, 2555-2577. Harvey T. G., Matheson T. W. and Pratt K. C. (1984) Chemical class separation of organics in shale oil by thin-layer chromatography. Anal. Chem. 56, 1277-1281. Harvey T. G., Matheson T. W., Pratt K. C. and Stanborough M. S. (1985) Determination of carbonyl compounds in an Australian (Rundle) shale oil. J. Chromatogr. 319, 230-234. Hoering T. C. (1981) Monomethyl acyclic hydrocarbons in petroleum and rock extracts. Carnegie Inst. Wash., Yearbk. 80, 389-393. Ingram L. L., Ellis J., Crisp P. T. and Cook A. C. (1983) Comparative study of oil shales and shale oils from the Mahogany Zone, Green River Formation (U.S.A.) and Kerosene Creek Seam, Rundle Formation (Australia). Chem. Geol. 38, 185-212. Jackson M. J., Powell T. G., Summons R. E. and Sweet I. P. (1986) Hydrocarbon shows and petroleum source rocks in sediments as old as 1.7 × 109 years. Nature 322, 727-729. Jackson M. J., Sweet I. P. and Powell T. G. (1988) Studies on petroleum geology and geochemistry, Middle Proterozoic, McArthur Basin, Northern Australia. I: Petroleum potential. APEA J. 28, 283-302. Kennicutt M. C. and Brooks J. M. (1990) Unusual normal alkane distributions in offshore New Zealand sediments. Org. Geochem. 15, 193-197. Kirkland B. L. (1988) Petrographic and graphic analysis of shelf-edge porosity in Lower Cretaceous Sligo Formation, South Texas. Am. Assoc. Pet. Geol. Bull. 72, 1114-I I 15. Klesment I. (1974) Application of chromatographic methods in biogeochemical investigations: determination of the structure of sapropelites by thermal decomposition. J. Chromatogr. 91, 705 713. Kvenvolden K (1970) Evidence for transformations of normal fatty acids in sediments. In Advances in Organic' Geochemistry 1966 (Edited by Hobson G. D. and Speers G. C.), pp. 335 366. Pergamon Press, Oxford. Levandowski D. W., Kaley M. E., Silverman S. R. and Smalley R. G. (1973) Cementation in Lyons Sandstone and its role in oil accumulation, Denver Basin, Colorado. Am. Assoc. Pet. Geol. Bull. 57, 2217-2244. Levine J. R., Samson I. M. and Hesse R. (1991) Occurrence of fracture-hosted impsonite and petroleum fluid inclusions, Quebec City Region, Canada. Am. Assoc. Pet+ Geol. Bull. 75, 139-155. McKirdy D. M. and Hahn I. H. (1982) The composition of kerogen and hydrocarbons in Precambrian rocks. In Mineral Deposits and the Evolution of the Biosphere (Edited by Holland H. D. and Schidlowski M.), pp. 123 154. Dehlem Konferenzenm, Berlin. Nishimura M. and Baker E. W. (1986) Possible origin of n-alkanes with a remarkable even-to-odd predominance in recent marine sediments. Geochim. Cosmochim. Acta 50, 299-305. Parker C. A. (1974) Geopressure and secondary porosity in the deep Jurassic of Mississippi. Trans. GCAGS 24, 69-80. Powell T. G. and MacQueen R+ W. (Ic)~4) Precipitation of

sulfide ores and organic matter: sulfate reactions at Pine Point, Canada. Science 224, 63~6. Rasmussen B. and Glover J. E. (1990) The diagenetic and economic significance of composite grains of monazite and hydrocarbon in Western Australian arenites. J. Geol. Soc. Lond. 147, 843-850. Regtop R. A., Crisp P. T. and Ellis J. (1982) Chemical characterization of shale oil from Rundle, Queensland. Fuel 61, 185-192. Rogers M. A., McAlary J. D. and Bailey N+ J. L. (1974) Significance of reservoir bitumens to thermal-maturation studies, West Canada Basin. Am. Assoc. Pet. Geol. Bull. 58, 1806-1824. Rovere C. E., Crisp P. T., Ellis J. and Bolton P. D. (1983) Chemical characterization of shale oil from Condor, Australia. Fuel 62, 1274--1282. Rowland S. J., Alexander R., Kagi R. I., Jones D. M. and Douglas A. G. (1986) Microbial degradation of aromatic compounds of crude oils: a comparison of laboratory and field observations. Org. Geochem. 9, 153 161. Saban M., Porter S., Costello C., Djuricic M. and Vitorovic D. (1980) Polar constituents isolated from the Aleksinac oil shale. In Advances in Organic Geochemistry 1979 (Edited by Douglas A. G. and Maxwell J. R), pp. 559-566. Pergamon Press, Oxford. Sassen R. (1988). Geochemical and carbon isotopic studies of crude oil destruction, bitumen precipitation and sulfate reduction in the deep Smackover Formation. Org. Geochem. 12, 351 361. Schoell M., Faber E. and Coleman M. L. (1983) Carbon and hydrogen isotopic compositions of the NBS 22 and NBS 21 stable isotope reference materials: an inter-laboratory comparison. Org. Geochem+ 5, 3 6. Sofer Z. (I 984) Stable carbon isotope compositions of crude oils: application to source depositional environments and petroleum alteration. Am. Assoc. Pet. Geol. Bull. 68, 31 49. Sofer Z. (1988) Biomarkers and carbon isotopes of oils in the Jurassic Smackover Trend of the Gulf Coast States, U.S.A. Org. Geochem. 12, 421~432. Stahl W. J. (1978) Source rock-crude oil correlation by isotopic type-curves. Geochim. Cosmochim. Acta 42, 1573 1577. Summons R. E., Powell T. G. and Boreham C. J. (1988) Petroleum geology and geochemistry of the Middle Proterozoic McArthur Basin, Northern Australia--Ill. Composition of extractable hydrocarbons. Geochim. Cosmochim. Acta 52, 1747 1763. Tissot B., Pelet R., Roucach~ J. and Combaz A. (1977) Utilisation des alcanes comme fossiles g6ochimiques indiateurs des environnements g+ologiques (alkanes as geochemical fossil indicators of geological environments). In Advances in Organic Geochemistry 1975 (Edited by Campos R. and Goni J.), pp. 117-154. Enadimsa+ Madrid. Volkman J. K., Farrington J. W., Gagosian R. B. and Wakeham S+ G. (1983) Lipid composition of coastal marine sediments from the Peru upwelling region. In A&'~ances in Organic Geochemistry 1981 (Edited by Bjor~y M. et al.), pp. 228 240. Wiley, Chichester. Welte D. H. and Ebhardt G+ (1968) Distribution of long chain n-paraffins and n-fatty acids in sediments from the Persian Gulf. Geochim Cosmoehim. Acta 32, 465466.