Hans Peter Nytoft

Oleanane or lupane? Reappraisal of the presence of oleanane in Cretaceous-Tertiary oils and sediments

Nonpolar GC-columns are normally used for GC–MS analysis of saturate fractions from crude oils. Under these conditions lupane coelutes with oleananes and some minor C30 compounds of non-terrigenous origin having lupane-like mass spectra. Because any peak eluting fractionally earlier than 17α,21β(H)-hopane in the m/z 191 mass chromatogram is routinely assigned to oleanane, the presence of lupane may sometimes have been overlooked. Lupane and oleananes are easily separated using reverse phase HPLC. Triterpane concentrates from 10 crude oils known to contain oleananes were HPLC-separated. Lupane was unambiguously identified in six of the oils by full-scan GC–MS analysis of fractions having the HPLC-retention time of authentic lupane. GC-separation of lupane and oleananes is possible using polar GC-columns having a polyethylene glycol stationary phase [Organic Geochemistry, 23 (1995) 21], allowing estimation of the lupane/(lupane+oleanane) ratio. High ratios were measured in the Marraat oil, West Greenland (0.8) and the Amauligak oil from the Beaufort–Mackenzie Delta (0.26). The results suggest that lupane may be more frequently occurring than previously thought, and that this compound is preferably associated with high latitude samples. High concentrations of 28-nor- and 24,28-bisnortriterpanes (oleananes, lupanes and taraxastanes) were detected in the Marraat oil.

Petroleum potential of Oligocene lacustrine mudstones and coals at Dong Ho, Vietnam — an outcrop analogue to terrestrial source rocks in the greater Song Hong Basin

The outcrop of Oligocene age at Dong Ho, northern Vietnam, may constitute an immature analogue to offshore terrestrial source rocks in the greater Song Hong Basin. The outcrop includes an interval with two source rocks: (1) highly oil-prone carbonaceous mudstones containing kerogen types IIA and IIA/I, and with TOC contents from 6.48 to 16.89 wt%, and HI values from 472 to 690; and (2) oilprone humic coals (kerogen type III) with HI values from 200 to 242. The mudstones were deposited in oxygen-deficient lakes, which on occasion were subject to marine influence, and the coals accumulated in freshwater peat-forming mires. The coals have broad activation energy (Ea) distributions, while the mudstones have Ea distributions characterised by a pronounced principal Ea. During artificial maturation about 16‐17% of the organic carbon in the coals and 45‐50% of the organic carbon in the mudstones participated in petroleum formation. The two source rocks primary generate oil and secondary generate gas, however, the mudstones realised the majority of their potential over a more narrow temperature range than the coals. The excellent generative potential of the terrestrial source rocks at Dong Ho is encouraging for offshore exploration for reservoirs charged by Cenozoic rift-lake successions. q 2001 Elsevier Science Ltd. All rights reserved.

Relative sea-level changes recorded by paralic liptinite-enriched coal facies cycles, Middle Jurassic Muslingebjerg Formation, Hochstetter Forland, Northeast Greenland

Abstract The Middle Jurassic Muslingebjerg Formation of Hochstetter Forland, Northeast Greenland, consists of a succession of shallow marine sandstones encasing four coal seams formed in low-lying coastal mires. The seams are up to 3.45 m thick and contain coal facies cycles with high liptinite contents (up to 70 vol%). The cycles generally start with huminite-rich bright or banded coal and end with dull coal or clayey coal/coaly claystone. The dull coals are characterized by a high proportion of liptinite, commonly resinite, and often mineral matter. Liptodetrinite, resinite and cutinite dominate the liptinite maceral group. Similarity in the relative proportions of the liptinite macerals in the bright and dull coals and the general association of bright coal and dull coal with a high resinite concentration suggest, that the dull coals represent a residue after selective removal of ligno-cellulosic tissues in the precursor peat of primarily the bright lithotype. The clayey coal/coaly claystone lithotypes have high contents of mineral matter and commonly contain alginite and pyrite. Occurrence of pyrite in levels with high diasterane C 27 C 29 ratios and sometimes also alginite in the clayey coal/coaly claystone lithotypes, indicates a marine influence during flooding of the mires. This suggests a causal link between base-level rise in the coastal mires and relative sea-level rise. Accommodation space available for thick peat accumulations was governed by overall relative sea-level rise and the dulling-upward cycles record outpacing of peat accumulation due to accelerated rise in base level/relative sea level. The Muslingebjerg Formation consists of four depositional sequences, beginning with a thick coal seam resting on a sequence boundary. Peat accumulation reflects onset of base-level rise in the coastal area and the coals represent the lower part of the transgressive systems tract. The overlying shoreface sandstones form the upper part of the transgressive systems tract and a progradational highstand systems tract. Alternatively the two lower seams in the succession may form a transgressive-regressive couplet separated by a lagoonal sandstone split. In this case a sequence boundary occurs at the top of the upper regressive seam. The dulling-upward cycles within the coal seams represent parasequences or possibly higher order sequences. Minimum age-estimates suggest that they accumulated over 4000–11000 yr.

C26 and C28-C34 28-norhopanes in sediments and petroleum

Abstract A complete series of 28-norhopanes (C26 and C28-C34) has been detected in oil samples and rock extracts from West Greenland and the North Sea. Only the C28 members of the series (28,30-bisnorhopanes) and the related 25,28,30-trisnorhopanes have been described in the literature. 28,30-Bisnorhopanes are often the only 28-norhopanes in oils and sediments, and their isotopic composition can be different from that of the regular hopanes, suggesting that 28,30-bisnorhopanes have a different origin. In other cases, 28-norhopanes and regular hopanes have a similar distribution of homologues, and there is no isotopic evidence for a different origin of the two series. When the complete series of 28-norhopanes is present, it is usually accompanied by high concentrations of the corresponding demethylated aromatic 8,14-secohopanes. The 28-norhopanes seem to be less resistant to biodegradation than regular hopanes, and there is a preferential demethylation of the low-molecular-weight 28-norhopanes. C25 and C27-C31 25,28-bisnorhopanes have been identified in biodegraded oils. The C28-C34 28-norhopanes are best studied using the m/z 355 mass chromatogram, since this fragment is comparatively intense and the interference from other compounds is usually low. The 17β(H),21α(H)/(17α(H),21β(H)+17β(H),21α(H)) ratios of the C29 and C30 28-norhopanes can be used as maturity parameters. In immature samples, a large proportion of the 28-norhopanes (especially C28 and C30) occurs in the bitumen. However, hydrous pyrolysis experiments have shown that 28-norhopanes are also part of the kerogen.

17α,21α(H)-hopanes: natural and synthetic

Abstract 17α,21α(H)-hopanes are found in low concentrations in sediments and oils, but C 30 17α,21α(H)-hopane is the only member of the series which can be detected in the m/z 191 mass chromatogram. The ratio of C 30 17α,21α(H)-hopane to C 30 17α,21β(H)-hopane is typically 0.02–0.04 in crude oils and mature sediments. Ratios up to 0.10 have been found in immature sediments with 22 S /(22 S +22 R ) ratios of C 31 –C 35 hopanes around 0.4. Compounds coeluting with 17α,21α(H)-hopane are usually absent in samples of early oil window rank or higher maturity. 17α,21α(H)-hopane and 17α,21β(H)-hopane have almost identical mass spectra and response factors in the m/z 191 mass chromatogram. These features make 17α,21α(H)-hopane an ideal internal standard for the quantification of hopanes in oils and sediments. 17α,21α(H)-hopane can be obtained in high yield by hydrogenation of synthetic hopa-15,17(21)-diene.

Source rock evaluation of Middle Jurassic coals, northeast Greenland, by artificial maturation: aspects of petroleum generation from coal

Paralic liptinite-enriched coals and carbonaceous mudstones in northeast Greenland constitute potential highly oil-prone source rocks, whereas the humic coals may be marginal source rocks. The liptinite-rich coals are dominated by resinite or fluorescing amorphous organic matter and alginite, resulting in hydrogen index (HI) values generally above 300 and reaching up to 728. During artificial maturation up to 330 degreesC/72 hr, the coals follow the maturation paths of kerogen types I and II on an HI vs. Tmax diagram, and calculations show that upon passage through the oil window, roughly 85% of their generation potential is realized. Activation energy (Ea) distributions with prominent principal Ea values centered around 60-62 kcal/mole and frequency factors from 5.855 x 1015 s-1 to 3.249 x 1016 s-1 strongly influence the generation characteristics from 300 to 330 degreesC/72 hr artificial maturation. Important changes include marked loss of liptinite fluorescence and increase in resinite reflectance; small change in Tmax; significant decrease in HI; pronounced increase in extract yields; increased generation of saturates; and generation of labile bitumen with low Ea values. These observations indicate significant bitumen/petroleum formation from the coals during a relatively narrow temperature range, which, together with the petrographic composition, may facilitate expulsion of a waxy crude oil. The coals demonstrate that under certain depositional conditions, highly prolific coal source rocks can form with the capacity not only to generate but also to expel liquid petroleum. (Begin page 234)

Source rock quality and maturity and oil types in the NW Danish Central Graben: implications for petroleum prospectivity evaluation in an Upper Jurassic sandstone play area

Abstract The principal exploration targets in the northwestern part of the Danish Central Graben have been Upper Jurassic sandstone reservoirs. The presence and effectiveness of the oil-generating rocks of the Upper Jurassic–lowermost Cretaceous marine shales of the Farsund Formation has generally not been considered as a significant risk. This study provides an evaluation of the source rock quality, maturity and distribution and of the oils in this area. The kerogen in the Farsund Formation is algal-derived, and kerogen type ranges from Type II to Type III. Generally the source rock quality is fair to excellent, but the petroleum generation potential varies considerably. In most wells the uppermost part of the Farsund Formation (Bo Member) consists of highly oil-prone shales. However, the presence of oil-prone kerogen may be masked by kerogen of poorer source quality. Favourable conditions for oil-prone kerogen preservation were present during the time of deposition of upper parts of the Farsund Formation, but exceptions are not unusual. Similar vitrinite reflectance gradients indicate a uniform thermal regime over the area. The oil window occurs from c. 3800–4000 to 4800 m, i.e. spanning approximately 800–1000 m. A general decrease in the generation potential from the top towards the base of the formation is caused by both generation and deterioration of kerogen quality. The Gertrud Graben and Feda Graben constitute the main kitchen areas, and oil compositions indicate sourcing from marine shales. In the shallow parts of the Outer Rough Basin the shales are mostly immature and the sourcing is dependent on kitchen areas outside the area or on Palaeozoic rocks. Mature Zechstein is indicated by a minor oil show probably locally sourced.

Hydrocarbon traces in the Tertiary basalts of the Faeroe Islands

Abstract Hydrocarbons in the form of gases, oils and waxes have been observed in the basalts of the Faeroe Islands in the North Atlantic. Gases and traces of oil were observed in the outflowing water of the deep Lopra-1 well drilled in 1981. The hydrocarbon gas was fairly dry, with stable isotopic ratios of δ13C1−3=−41.4; −32.4; −26.5% respectively, typical of a thermogenic gas. High temperature gas chromatography of the oil showed that it consisted mostly of C13−60 n-alkanes. Biomarker distribution observed by GC-MS indicates that the oil was derived from a mature source rock deposited in an anoxic environment; this suggests that the source rock must lie beneath the known basalts. Waxes exhibiting bright yellow fluorescence under UV light were observed as coatings on zeolite minerals widely distributed on the Faeroe Islands. The waxes consist predominantly of higher n-alkanes shown by HTGC. The fluorescence indicates the presence of aromatic compounds. Biomarker distribution indicated that the waxes were derived at least in part from a source rock containing some terrestrial organic matter astestified by the low amounts of oleanane present. The waxes were probably deposited from traces of oil present in deeply circulating waters in fractures within the basalts. Coals which had been suspected to generate some of the hydrocarbons observed in the Faeroese basalts were also examined. Vitrinite values of Ro=0.5% as well as GC-MS analyses of the Suduroy coal extracts showed that these coals are immature and have not generated significant hydrocarbons.

Modeling of petroleum generation in the Vietnamese part of the Malay Basin using measured kinetics

Two-dimensional (2-D) modeling of source rock maturation and hydrocarbon (HC) generation histories were conducted for the Malay-Cho Thu Basin in the Gulf of Thailand and South China Sea. The source rocks comprise Oligocene synrift lacustrine mudstones and coals, postrift coals, and terrigenous-influenced mudstones. Three different lacustrine mudstone source rocks and coals were considered in the 2-D modeling, and each source rock was assigned specific generation potential and kinetics. Measured kinetics for bulk petroleum generation determined on two thermally immature upper Oligocene oil-prone lacustrine mudstones and on a terrigenous-influenced mudstone derived from wells were used together with published coal kinetics. The onshore Krong Pa graben, a small-scale rift basin in central Vietnam, was used as a conceptual model for the distribution of lithofacies, including source rock types, in the 2-D models. Exploration targets and drilled direct HC indicators (DHIs) are mainly located in the tectonically disturbed postrift succession. Modeling results suggest that the risks related to this play are (1) timing of petroleum generation from the oil-prone lacustrine synrift deposits relative to structural trap formation, (2) complex migration pathways through strongly faulted strata, and (3) relatively small kitchen areas. Oil generation from uppermost synrift and postrift coaly source rocks with minor contribution from lacustrine deposits after principal trap formation is consistent with the prominent terrigenous geochemical signature of oils in the Malay-Cho Thu Basin. A new untested play is proposed based on mapping of potential DHIs associated with sandstone bodies in tectonically undisturbed synrift traps.

Assessment of the petroleum generation potential of Lower Carboniferous coals, North Sea: evidence for inherently gas-pronesource rocks

The petroleum generation potential of Lower Carboniferous coastal plain coals in the Danish Gert-2 and Norwegian 2/11-9 wells in the Central Graben, North Sea, has been assessed in order to determine the source-rock quality of the coals in connection with deeper plays. The coals are vitrinite-rich, have H/C ratios from 0.75–0.79, and hydrogen index (HI) values from 171–219, which are very close to the HImax values attained during thermal maturation. The thermal maturity of the Gert-2 coals is close to the start of the effective oil window (oil expulsion), c. 0.90–0.95% vitrinite reflectance. The proportion of aliphatic chains >C18 in the coals is negligible or very low: the C19–35 aliphatic chains constitute only c. 6% of the total amount of C12–35 aliphatic chains in the coal structure. Aliphatic moieties are characterized by shorter-chain aliphatics and isolated CH2. The generated liquid petroleum is trapped in the coals and the saturated hydrocarbon fraction is dominated by shorter-chain aliphatics. Upon solvent extraction, the measured HI values of the Gert-2 coals can, on average, be reduced by 30%, indicating that the trapped petroleum contributes to the measured generation potential. The Lower Carboniferous coals are thus inherently gas-prone, a feature they have in common with Carboniferous coals in general and which is not maturity related. Inefficient expulsion of the saturated hydrocarbons may enhance the gas-proneness by intra-source rock oil-to-gas cracking. In a deep exploration context in the North Sea area, Lower Carboniferous coal/coaly sections can therefore only constitute a gas source rock.