Terpane Distributions Research Articles

A geochemical study of bituminous mixtures from Failaka and Umm an‐Namel (Kuwait), from the Early Dilmun to the Early Islamic period

This paper is the last in a series presenting geochemical analyses of fragments of bituminous mixtures excavated from archaeological sites in Kuwait. The first was devoted to bituminous boat remains from the Ubaid‐related Neolithic site of H3, As‐Sabiyah, while the second dealt with bituminous amalgams from the Partho‐Sasanian site of cAkkaz, a former island now joined to the south side of Kuwait Bay. This, the third, refers to bitumen‐bearing samples from two other islands, Failaka and Umm an‐Namel, and covers a time span including the Early Dilmun period, the Kassite period and the Hellenistic to Early Islamic periods. The composition of the bituminous amalgams was studied in detail. The proportions of soluble and insoluble organic matter as well as vegetal organic matter were evaluated. Mineralogical composition by X‐Ray diffraction and thin‐section analysis was used to estimate the mineral input in the bituminous mixtures. It can be confirmed that the recipes used in the preparation of these bituminous amalgams comply with those traditionally used in antiquity, as seen at many sites in Mesopotamia and the Gulf. Analysis of the soluble organic matter, and especially its ‘‘saturates’’ fraction, provided sterane and terpane distributions and the measurement of diagnostic molecular ratios. These data, complemented by the isotopic composition of asphaltenes, allowed the identification of the sources of the bitumen, by calibration with numerous references from Iran and northern Iraq (oil seeps, bitumen from archaeological sites). It was established that the bitumen from Failaka and Umm an‐Namel was mainly imported from central Iraq (Hit‐Abu Jir) and northern Iraq (around Mosul). One sample of oil‐stained sand, dating to the Early Dilmun period, originated from Burgan and thus documents small‐scale imports from inland Kuwait. These results, and those of previous analyses, agree with the geopolitical context of the Early Dilmun, Kassite and Hellenistic periods, and the maritime trade routes that linked Mesopotamia to the settlements of the Gulf and beyond. The paper concludes with an overview of recent bitumen provenance analyses, and discerns chronological patterns in the distribution of Iraqi and Iranian bitumen in the Gulf and Indian Ocean, from the Neolithic to the Islamic periods.

Terpanes from oil shows of Lake Baikal

The composition and distribution of terpanes in oil shows that emerge from the bottom of Lake Baikal were studied. The oil samples from three sites of Baikal showed different extents of their bacterial degradation, from practically unaltered to heavily degraded oils. In the unaltered samples of oils and moderately degraded differences, a unique variety of biomarkers (sesquiterpanes, secohopanes, new regular hopanes with still unknown structure, oleonane, β-carotane, etc.) was discovered. It was shown that the concentration of triterpanes and β-carotane increases with a growth in the degree of bacterial degradation and the amount of alkanes and sesquiterpanes is simultaneously reduced. The array of the obtained data suggests that the source of Baikal oils is the organic matter buried in freshwater reservoirs. In this organic material, together with the remnants of the living matter of lacustrine organisms, a significant role was played by the remnants of higher plants brought from the land. The age of source rock cannot be older than the Cretaceous, i.e., the time of appearance of angiospermous plants on the land (presence of oleanane).

Application of geochemical parameters for classification of crude oils from Egypt into source-related types

Seven crude oils representing the different petroleum-bearing basins in the Western Desert were characterized by a variety of biomarker and nonbiomarker parameters. For comparison, one crude oil from the Gulf of Suez region has also been studied. The oils have been analyzed for geochemical biomarkers using GC and GC-MS techniques. The results reveal significant differences within the oils that suggest five oil types. Type 1 oils from the Gulf of Suez show C 29/C 30 17α(H) hopane ratio >1, high C 35 homohopane index, and the presence of considerable amounts of gammacerane indicating a marine saline carbonate or evaporite source rock and highly reducing (low Eh) conditions. Type 2 oils from Matruh basin and type 3 oils from Shushan basin are very similar and show relatively high Pr/Ph ratios, low sulfur and metal contents, paucity of C 30 steranes and the presence of high relative abundance of 17α(H) diahopane (C 30*) suggesting that they probably originated from source rocks containing a significant proportion of higher plant material. Another related feature of these oils is the absence of 18α(H)-oleanane which suggests a source age older than Cretaceous. Type 4 oils from Abu-Elgharadig basin show terpane distribution dominated by C 24 tricyclic, absence of C 30*-diahopane and medium diasterane/sterane ratios which reflect generation from marine siliciclastic source rocks. Type 5 oils from Alamein basin possess source biomarkers indicating a mixed contribution of terrestrial and marine sources. The presence of measurable amounts of oleanane in this type of oils suggests source rocks deposited in deltaic or near shore environment in Post-Cretaceous basin.

Geochemical evidence for mudstone as the possible major oil source rock in the Jurassic Turpan Basin, Northwest China

Geologists and geochemists have debated whether hydrocarbons from Jurassic coal measures are derived from the mudstones or the coals themselves. This paper identifies mudstones as the possible major source rock of hydrocarbons in the Jurassic basins in Northwest China. The Turpan Basin is used as a representative model. Mudstones in the Middle-Lower Jurassic are very well developed in the basin and have an average genetic potential from 2 to 4 mg/g. The vitrinite reflectance of the source rocks ranges from 0.6 to 1.3%, exhibiting sufficient thermal maturity to generate oil and gas. Biomarkers in crude oils from the basin are similar to those in mudstones from the coal-bearing strata, with a low tricyclic terpane (cheilanthane) content, a relatively high content of low carbon number (less than C 22) tricyclic terpanes and a low content of high carbon number tricyclic terpanes, relatively high ratios of T s/ T m, and C 29 T s/17α (H)-C 29 norhopane, and low ratios of T m/17α (H)-C 30 hopane and 17α (H)-C 31 homohopane/17α (H)-C 30 hopane. These characteristics and the distribution of steranes and terpanes in the crude oil and mudstone differ significantly from those of the Jurassic coals and carbonaceous shales of the basin, indicating mudstone is possibly the major source rock of the oils in the Turpan Basin.

Influence of paleoenvironment and radiolytic alteration on the geochemistry of organic matter from Autunian shales of the Lodeve uranium deposit, France

Abstract Thirty-three samples of shales from the Lodeve Permian uranium deposit were examined by different analytical techniques. Samples were analyzed by Rock-Eval pyrolysis and by gas chromatography-mass spectrometry after extraction and fractionation. The determination of uranium content was carried out by atomic emission spectrometry. The composition of the organic extracts allows two groups of shales to be distinguished: the first one is marked by a high proportion of aliphatic hydrocarbons and the second by the predominance of aromatic compounds. These two groups exhibit distinctive biomarker characteristics. One group is characterized by (1) pristane/phytane ratios higher than 1, (2) distributions of terpanes dominated by the tricyclic terpanes and (3) the predominance of C 29 and C 28 steranes. The second group is marked by (1) pristane/phytane ratios lower than 1, (2) the predominance of the pentacyclic terpanes over the tricyclic terpanes and (3) the predominance of C 27 and C 29 steranes. It is suggested that the differences observed are mainly related to different depositional environments, although the uranium content may also influence some parameters such as the hydrogen index and the extraction yield.

Genesis and evolution of hydrocarbons entrapped in the fluorite deposit of Koh-i-Maran, (North Kirthar Range, Pakistan)

The exceptional development of coeval hydrocarbon and aqueous fluid inclusions (FI) in fluorite from the MVT-type ore deposit of Koh-i-Maran, Baluchistan (North Kirthar range, Pakistan), provides samples which are representative of the ore-forming fluid and which support the hypothesis of petroleum migration in the province. Primary brines at 125°C (10 wt% equ. NaCl) and secondary CH 4-rich brines at 135°C (7 wt% equ. NaCl), are recognised to be associated with oil migration in the fluid inclusions. They support the model of a per ascensum MVT (Mississippi Valley Type) stratabound hydrothermal deposit. A pressure–temperature path of 120–125°C to 165–200 bars is calculated from microthermometric data and PVT modelling of hydrocarbon FI using the modified Peng–Robinson Equation of State (IFP software) from primary cogenetic inclusions (oil and brines). The composition of gas and oil fractions is obtained by a combination of Synchrotron FTIR microanalysis and gas chromatography performed on individual fluid inclusions. The oil entrapped as a coeval primary fluid phase is a light aliphatic normal oil in the range C 8–C 35 with a high CO 2 content. The brown solid phase found systematically in the oil is probably asphaltene resulting from precipitation after trapping of the heavy fraction, which commonly occurs by decreasing pressure and temperature and\\or by CO 2 injection. Later CH 4-rich brine influx probably modified part of the oil in the primary fluid inclusions because degraded oil is observed within such inclusions. Biomarkers obtained by GC-MS analysis indicate a terpane distribution quite similar to the nearest oil seepage in the Gokurt area. This result and the high CO 2 content of organic fluid inclusions indicate a restricted/confined sedimentary environment for the source rock, which could correspond to the Eocene Carbonate formation with type-II organic matter. A possible additional input of gas from the Sambar formation is suggested as feasible. The link between the fluid inclusion data and the geodynamic evolution lead us to propose a circulation of basinal fluids driven mainly by the fault system during dewatering in the foredeep. In Pakistan, they are coeval to major compressional NW–SE Oligocene episode in the thrust belt. The origin of the fluorine may be found in the basin sediments as well as near the basement. The brines originated in salt structures recognized in eocambrian at the decollement level, the source rock was already mature.

Distribution and evolution of tricyclic terpanes in lacustrine carbonates

Abundant and peculiar pairs of C20 to C25 tricyclic terpanes were discovered in the Tertiary lacustrine carbonates of the Biyang Depression. Though all organic matter contained in the entire carbonate section are of type I kerogen, the distribution of the tricyclic terpanes varies regularly with the burial depth of samples. The relative concentration of 13α(H), 14α(H) isomers in the paired tricyclic terpanes declines sharply with increasing burial depth. On the basis of this variation, new tricyclic terpane maturity parameters for immature and early mature carbonate source rocks are proposed.

Organic petrology and organic geochemistry of Devonian black shales in southwestern Ontario, Canada

The hydrocarbon source rock potential of the Devonian Marcellus and Kettle Point black shales in southern Ontario has been assessed using Rock-Eval pyrolysis, gas chromatography, gas chromatography-mass spectrometry and incident-light microscopy. Both formations contain sufficient hydrogen-rich organic matter (Type II) to be considered possible source rocks. The kerogen is predominantly marine in origin. This organic matter was deposited in a clastic algal-dominated environment, and mainly consists of unstructured bituminite and unicellular alginite. The organic microfacies indicate shelf paleodepositional settings with a transition to an open basinal region. The optical (reflectance, fluorescence) and geochemical (Rock-Eval Tmax, extract yields, distributions of steranes and terpanes) maturity data indicate that the organic matter in the Kettle Point Formation is immature, whereas in the Marcellus Formation it has reached the early stages of hydrocarbon generation and expulsion. Some Devonian oils occurring in this area have characteristics similar to the Marcellus extracts, suggesting that more mature equivalent units from the Appalchian Basin could be their source.

Assessing thermal maturity of Palaeozoic rocks from reflectance of chitinozoa as constrained by geochemical indicators: an example from southern Ontario, Canada

The reflectance of chitinozoa (%ChR 0) was investigated as an alternative technique of determining the level of thermal maturity of organic-rich Palaeozoic rocks in southern Ontario. These sedimentary strata, which include the Ordovician Collingwood Member and the Blue Mountain Formation, as well as the Devonian Marcellus Formation, lack vitrinite precluding the application of a standard vitrinite reflectance (%VR 0) technique. ChR 0 shows a proportional increase at marginal to moderate maturities, being on average 20 to 25% higher than expected vitrinite reflectance. The reflectance data fall into a very narrow range showing a high degree of consistency for each lithostratigraphic unit. The average ChR 0 are as follows: Collingwood Mbr 0.63% (Georgian Bay area) and 0.88% (Toronto area), Blue Mountain Fm 0.92%, Marcellus Fm 0.68%. Correlation with more conventional optical and geochemical maturity parameters obtained from the same set of samples (fluorescence of Tasmanites, Leiosphaeridia and Gloeocapsomorpha alginite, Rock-Eval Tmax, extract data, distribution of terpanes and steranes in extracts) indicates that, within the area of study, the beginning of the catagenetic stage corresponds to ChR 0=0.65% (equivalent VR=0.50%) whereas the threshold of significant oil generation is reached at ChR 0=0.9% (equivalent VR=0.70%). Therefore the Blue Mountain Formation is thermally mature with respect to hydrocarbon generation throughout the whole area of study. The Collingwood shales are mature only in the Toronto area while those occurring in the Georgian Bay area as well as the Marcellus shales have yet to enter the main stage of hydrocarbon generation. This integrated approach of assessing thermal maturity shows that ChR 0, when constrained with other maturity parameters, is a very reliable indicator of thermal maturity in Lower to Middle Palaeozoic sedimentary rocks.

Petroleum biomarkers as tracers of lubricating oil contamination

This study demonstrates the use of tricyclic and pentacyclic terpanes, trace constituents of lubricating oils, as indicators of the origin of diffuse lubricating oil contamination in plankton and sediments around St John's, Newfoundland, Canada. Different types of lubricating oils and motor exhausts were found to consistently feature distinct terpane distributions. Differences in the relative contribution of automotive and two-stroke outboard oils could be recognized in the terpane distributions of sediments and plankton from different areas. The ratio of durable pentacyclic terpanes to the size of the more labile unresolved complex mixture is demonstrated to be an indicator of the degree of weathering that oil contamination has undergone. Analysis of the terpane distributions of the entire range of refined oils and greases would enhance the use of these compounds as tracers of the sources of diffuse lubricating oil contamination.

Geochemistry of oil seeps and rock samples of the Early Tertiary section from the Northandean Flank of the Venezuelan Andes

An organic geochemical study of oil seeps and Early to Middle Tertiary source rocks of the Northandean Flank (NAF) of the Venezuelan Andes range was performed to establish the possible contribution of terrestrial source rocks to the oil accumulations in the unexplored southern part of the Maracaibo Basin. Source rocks were identified within the Paleocene Barco and Los Cuervos Formations, and the Late Eocene-Oligocene Carbonera Formation. Biomarker distributions indicate a terrigenous organic source for these units. Geochemical modeling performed by Parnaud et al. (1995), indicated Plio-Pleistocene oil generation for the Orocué Group and Middle Miocene to Plio-Pleistocene oil generation for the Carbonera Formation. Geochemical modeling also indicates that the quantity of crude oil expelled by the Carbonera Formation is four times that expelled by the Orocué Group (Barco and Los Cuervos Formations). A northeast to southwest variation from marine to terrestrial oil seeps was identified based on sterane and terpane distributions. The marine oil seeps appear to be derived from the La Luna source rocks. The characteristics of the mixed oils suggest contributions from different sources (La Luna and a terrestrial source rock) most likely the Orocué Group or Carbonera Formation coals. Source facies similar to those in the Los Cuervos and Carbonera Formations coals are most likely the main source rocks of terrestrial oil seeps in the NAF.

Productivity control on oil shale formation—Mae Sot Basin, Thailand

Neogene oil shales from the freshwater, lacustrine, intermontane Mae Sot Basin, western Thailand, are examined in order to define (a) oil source rock potential, (b) variations in molecular and isotopic geochemical characteristics, and (c) the influence on source potential of organic matter productivity and preservation. Twelve samples spanning 7 m of section were examined using conventional isotopic, molecular, and organic petrographic methods of geochemical analysis; temporal resolution is 2700 yr per sample. Because thermal maturity differences and fluid migration within the sample set are absent, and organic matter type input variation is either minor or absent (based on visual kerogen analysis), we propose that organic matter differences among the samples are caused by variability in surface-water productivity. All samples are excellent potential source rocks ( VR = 0.4−0.5% R o) containing Types I and II organic matter (modified van Krevelen plot determination) consisting of almost 100% fluorescent amorphous kerogen (visual kerogen determination). Numerous diagnostic molecular markers and characteristics are present, including perhydro-β-carotene, dammaranes, norsterane(s), and novel distributions of tricyclic terpanes. Stable carbon isotope ratios of kerogens and extract fractions range over 5%, and co-vary with hydrogen index. This covariance is attributed to temporal increases in surface-water productivity leading to CO 2-limiting conditions and consequent increase in δ 13C of the organic matter in the photic zone. During times of elevated productivity, increased amounts of 13C-enriched organic matter reached the water-sediment interface. Thus times of greater productivity are accompanied by higher δ 13C and hydrogen index values, with δ 13C related to productivity under CO 2-limiting conditions, and HI related to the relative amount of the water column that was anoxic during deposition. Our findings suggest that, in petroleum geochemical studies involving lacustrine source rocks, δ 13C values must be used with caution as oil-oil and oil-source rock correlation parameters.

Hydrocarbon composition of authigenic inclusions: Application to elucidation of petroleum reservoir filling history

Geochemical analysis of petroleum inclusions trapped in authigenic feldspar and quartz in the Ula Formation in the North Sea Ula oil field revealed a petroleum of markedly different composition than the oil presently in the reservoir. Using microthermometry and the burial history as a dating tools, it is concluded that the petroleum in the K-feldspar inclusions was present in the more porous and permeable parts of the Ula Formation as early as 45–75 My Bp when the field was at a depth of about 1.0–1.5 km, as compared with the current depth of 3.4 km. This early petroleum, which was trapped as inclusions in authigenic K-feldspar, shows a distinctly different distribution of tricyclic terpanes and pentacyclic triterpanes from that of the current petroleum charge in the Ula Formation, which was derived from the Mandal Formation source rock in late Neogene time. Molecular parameters show that the oil in the K-feldspar inclusions is significantly less mature than the crude oil in the present reservoir. The approximate 90°C temperature increase occurring after entrapment of the early petroleum in Kfeldspar (the field is currently at 143°C) appears not to have reset the low maturity signature of the oil in the K-feldspar inclusions. This could suggest that the temperature in the inclusions is too low for isomerization/selective thermal degradation to occur (lack of catalysts?), or that there are other controls on the ratio of some of these parameters. Still, parameters like the ratio of C 21 to C 28 triaromatic steroids, and those based on dimethyl- and trimethyl-naphthalenes, are comparatively similar in both the inclusions and in the reservoir crude. The oil inclusions in authigenic quartz and albite, formed from about 10 My BP (burial depth ≈ 2.5 km) until the present (burial depth = 3.4 km), are interpreted as representing a palaeo-petroleum charge having a composition intermediate between the oil found in K-feldspar inclusions and the oil charge in the present reservoir. Our data suggest strongly that the petroleum trapped in the inclusions in quartz and plagioclase represents progressive dilution of the early reservoired oil, now found only in K-feldspar inclusions, with oil from the Mandal Formation. Analysis of solution gas in these inclusions suggests that the first petroleum-associated gas to arrive at the trap from the progressively maturing Mandal Formation had a much wetter composition than the current reservoir solution gas. To explain the present comparatively drier and isotopically lighter reservoir solution gas composition, the inference is made that there has been a recent (<5 My Bp) influx of comparatively dry thermogenic gas to the field. This interpretation is independently supported by the noncogenetic δ13 C isotope signature of C 1 relative to δ 13 C 2−4 in the present reservoir solution gas. During formation of K-feldspar inclusions (45–75 My BP), maturation of the Upper Jurassic Mandal Formation, the main source rock in this region, was limited possibly to the Graben axis. This suggests that the petroleum found in the K-feldspar inclusions was most likely derived from a deeper post Caledonian Palaeozoic formation.

Depositional Environment and Organic Geochemistry of the Upper Permian Ravnefjeld Formation Source Rock in East Greenland

The Upper Permian Ravnefjeld Formation in East Greenland is composed of shales that laterally pass into carbonate buildups and platforms of the Wegener Halvo Formation. The Ravnefjeld Formation is subdivided into five units that can be traced throughout the Upper Permian depositional basin. Two of the units are laminated and organic rich, and were deposited under anoxic conditions. They are considered good to excellent source rocks for liquid hydrocarbons with initial average TOC (total organic carbon) values between 4 and 5% and HI (hydrogen index) between 300 and 400. The cumulative source rock thickness is between 15 and 20 m. The source rocks are separated and enclosed by three units of bioturbated siltstone with a TOC of less than 0.5% and an HI of less than 100. The e siltstones were deposited under relatively oxic conditions. The organic geochemistry of the source rocks is typical for marine source rocks with some features normally associated with carbonate/evaporite environments [low Pr/Ph (pristane/phytane), low CPI (carbon preference index), distribution of tricyclic and pentacyclic terpanes]. The establishment of anoxic conditions and subsequent source rock deposition was controlled by eustatic sea level changes. The subenvironment (paleogeographic setting, influx of carbonate material, water depth, salinity) has some influence on a number of bulk parameters [TOC-HI relations, TOC-TS (total sulfur) relations] and, in particular, biomarker parameters such as Pr/Ph and terpane ratios. All the basal shales or shales in the vicinity of carbonate buildups or platforms are characterized by low Pr/Ph, high C23 tricyclic terpanes, and high C35 and C33 hopanes.

A geochemical investigation of crude oils and source rocks from Biyang Basin, China

China has a number of petroliferous lacustrine sedimentary basins of varying salinity and age (mainly Eocene). A geochemical investigation has been undertaken on several oils and source rocks from the Eocene lacustrine Biyang Basin. The distributions of n-alkanes, isoprenoids, steranes, and terpanes have been studied and used to characterize the sedimentary environment of deposition, maturity, biodegradation and undertake possible correlations. The ratios of C 30-hopane/gammacerane, 4-methyl-steranes/regular steranes, steranes/hopanes, C 21 tricyclic/C 30 hopane are proposed to be indicative of the depositional environment whereas ß-carotane appears to be a source related indicator. The geochemical data obtained in this study suggest that the major source rocks in the Biyang Basin were deposited in a saline/hypersaline depositional environment.

Diterpanes, triterpanes, steranes and aromatic hydrocarbons in natural bitumens and pyrolysates from different mimic coals

There is a significant difference in the distribution of terpanes in natural bitumen extracted from four coals identified as Rocky Mountain coal (RMC), Australian Gippsland Latrobe Eocene coal (GEC), Australian Gippsland Latrobe Cretaceous coal (GCC), and Texas Wilcox lignite (WL). Whereas pentacyclic triterpanes are dominant in GEC, GCC and WL, diterpanes strongly predominate in the bitumen of RMC. This indicates that resin is a more important constituent of RMC than in the other coals and releases the diterpenoids at an early stage of diagenesis. Furthermore, the composition of diterpanes is also different among these coals. For example, tricyclic diterpanes are the only diterpanes present in RMC, whereas tetracyclic and tricyclic diterpanes are both present in GEC and GCC and tetracyclic diterpanes are most abundant in GEC. However, diterpanes are nearly absent in WL. Surprisingly, the diterpenoid content is negligible in the pyrolysates of all coals. The sterane and triterpane distributions in the natural bitumen of coals are very different from those in pyrolysates. C 31 αβ 22R hopane predominates in the m/z 191 mass fragmentograms of the natural bitumens, whereas a homologous series of hopanes (C 27–C 35 ; except C 28) is present in the coal pyrolysates. C 29 steranes dominate in all of the coal bitumens as well as pyrolysates. C 27 steranes are absent in the natural bitumen, but are generated in pyrolysates during lengthy heating of coal kerogen. This indicates that formation of secondary steranes occurs by cracking the side chain. C 29 monoaromatic steroid hydrocarbons are abundant in the natural bitumen of the four coals. The m/z 253 distribution is similar for GEC, RMC and WL, but it differs from the more mature GGC, which has a lower content of 20R of both 5 α and 5β C 29 MA-steroids. Triaromatic steroid hydrocarbons are only present in GCC, whereas significant amounts of tetra- and triaromatic triterpenoid hydrocarbons are present in the other three coals (GEC, RMC and WL). The ratio of benzo(e)pyrene/perylene may be potentially useful as a maturity parameter because the amount of benzo(e)pyrene increases with thermal stress, whereas perylene decreases with heating time. Benzohopanes are widely present in four humic coals but become unstable after 10 h heating at 300°C.

Organic geochemistry of a lower jurassic synrift lacustrine sequence, Hartford Basin, Connecticut, U.S.A.

Synrift terrestrial strata of the Lower Jurassic East Berlin Formation (Hanford basin, Connecticut, U.S.A.) record cyclical expansion and contraction of major lakes, six of which were deep enough to develop anoxic bottom waters. We have studied one representative lacustrine sequence in detail, sampling a new roadcut near the village of East Berlin. The section examined is 4 m thick, with a gray silstone at the base, deposited in shallow water, overlain by an organic-rich black shale (deep water), succeeded in turn by another gray siltstone, deposited as the lake waters gradually receded. The upper gray siltstone is chemically distinct from the lower siltstone, as it contains small amounts of corrensite, analcime and gypsum, reflecting the increasing salinity and alkalinity of the contracting lake. The samples in the center of the black shale unit contain laminae of thermally-altered, yellowish orange-fluorescing, mottled telalginite. The fluorescence properties indicate a peak oil generation maturity level, confirmed by a vitrinite reflectance of 1.13% and a Methylphenanthrene Index of 1.08. The other samples have less organic matter, becoming increasingly lean towards the top and bottom of the sequence. Samples in the middle of the black shale unit are distinguished by the presence of an homologous series of tricyclic terpanes extending from C 20 to at least C 41, and by the near absence of hopanes and steranes. Moving upsection into the gray siltstone, the samples contain markedly lessextractable organic material (EOM) and the concentration of tricyclic terpanes relative to hopanes steadily decreases. In the uppermost sample, hopanes are the predominant terpanes. Moving downsection from the black shale into the lower gray siltstone, EOM and the ratio of tricyclic terpanes also decrease, except in the lowermost samples, which contain terpane distributions like those of the middle part of the black shale. This likely is migrated material, because bitumen fills microfractures and extensive megafractures. The lack of hopanes and steranes in the black shales cannot simply be a maturation effect, as these biomarkers appear in the adjacent beds. Instead, the manual terpane distributions may indicate a changing depositional environment, documenting the geochemical evolution of the lake. Or, more likely, they may result from fractionation during expulsion of petroleum from these mature source rocks.

Chemical structural units of macromolecular coal components

Chemical degradations of coal resins, coal asphaltenes and coal residues have been performed with selective, non-oxidative reagents. The coal comprise samples a rank interval 0.30–1.21 % R m. Degraded low-molecular-weight compounds were analyzed by GC-MS. The distributions of pentacyclic terpanes, isoprenoids, n-alkanes, acids and alcohols obtained as degradation products illustrate a considerable variability between the macromolecular coal fractions. A structural study on the molecular level of the degraded compounds from coal resins and coal asphaltenes show their potential to generate hydrocarbons during coalification process.

Terrestrial biomarkers in benzene—methanol extracts of Turkish solid fuels

Benzene-methanol extracts of three bituminous coals and three lignites from Turkey were analysed by g.c.-m.s.. The distributions of n-alkanes, alkylbenzenes, hopanes, steranes and terpanes were determined and related to the depositions of the fuels.

The ion trap detector as an aid to analytical chemists in the oil industry

The use of the Finnigan Ion Trap Detector (ITD) for biomarker analyses is described. Whilst the conclusions reached in this study, from a geochemical point of view, are not unique, the results justly illustrate the use of the ITD as a relatively inexpensive system for this type of routine analysis. Samples used in the study were collected from various hydrocarbon-producing basins in China and the U.S.A. and particular emphasis has been placed on illustrating the determination of sterane and terpane distributions.