Source: https://pg.lyellcollection.org/content/23/2/190
Timestamp: 2019-04-24 02:06:02+00:00

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The Barents Sea hosts multiple source rocks from Palaeozoic to Cretaceous age. Attempts in the past to link individual oil and condensates directly to one type of source rock have often been complicated due to ‘blended-oil’ signatures. As a result of uplift, remigration, alteration and mixing of petroleums, deconvolution of primary petroleum signatures in terms of maturity, age and depositional environment is generally complicated. In this paper, we use δ13C isotopes, and age- and source-related biomarkers to line out the main basin-scale trends concerning the depositional environments and source-rock ages, as well as the type of organic matter input that constitutes the inferred source-rock kerogen. Multivariate statistical analysis was applied as an auxillary tool to suggest petroleum families. Results classify the petroleums into four families: (1) Permian–Triassic-sourced petroleums; (2) Carboniferous-sourced petroleums; (3) Jurassic-sourced petroleums; and (4) phase-fractionated condensates charged from late mature Triassic–Jurassic source rocks. The inferred palaeo-environments for the petroleums cover marine, transitional and terrestrial depositional environments, and display geological variations that prevailed during Permian–Jurassic times. Isotope signatures and age-specific parameters suggest that many oils in the region should be considered as blends or mixtures derived from more than one source rock.
Important challenges concerning petroleum geochemical studies, and also basin modelling studies on hydrocarbon migration and entrapment in the Barents Sea, include: (1) the presence of multiple source rocks that matured and expelled at different times (i.e. several critical moments) (cf. Johansen et al. 1993; Ohm et al. 2008); (2) burial, uplift and glaciations with differential effects on already migrated and entrapped petroleums, source rocks and cap rocks (Doré & Jensen 1996; Cavanagh et al. 2006); and (3) migration, remigration, mixing and alteration of petroleums in traps (Ohm et al. 2008; Bjorøy et al. 2009; Rodrigues Duran et al. 2013; Killops et al. 2014; Lerch et al. 2016a, b). Early geochemical work on oils recognized Triassic and Jurassic source rocks as the main contributors for petroleums in the western part of the Barents Sea (e.g. Berglund et al. 1986). Yet, investigations of Vobes (1998), Alsager (2005) and Opstad (2005) on oils and condensates, plus core extracts from the region, suggested a much more complicated relationship and also pointed towards possible Palaeozoic sources. Karlsen (pers.comm. 2013) argued that preserved Palaeozoic and Triassic palaeo-oil charges are better preserved in structurally complex regions and on platforms, while traps in central basin parts tend to be dominated by the most recent arrived oil or condensate. Thus, a much more complicated picture seemed to emerge concerning oils and condensates in traps in the region. Lerch et al. (2016a) recognized long-distance migration of petroleums towards elevated basin margins and structural highs. Thus, early migration of Palaeozoic/Triassic petroleums, which may have been mixed with later charges from Jurassic sources, may complicate age and source-rock inferences.
Petroleum blends have been reported by Lerch et al. (2016a, b), who conducted systematic evaluation of C4–C8 light hydrocarbons, C10–C20 medium-range hydrocarbons and C20+ biomarker range compounds to evaluate co-sourcing for these individual petroleum fractions. Ohm et al. (2008) applied δ13C isotopes, extended tricyclic terpane ratios (ETR) and n-alkane distributions on oil samples to infer possible source rocks. He et al. (2012) investigated source- and age-related biomarkers of petroleums mainly from the Russian Barents Sea and the Timan Pechora Basin. They classified six oil families, and concluded on generation from Devonian, Triassic and Jurassic strata. Rodrigues Duran et al. (2013) found no clear trend regarding inferred source-rock ages using the ETR and C28/C29 steranes in a set of petroleums from the Hammerfest Basin, and argued that mixing of petroleums may have led to interferences. Killops et al. (2014) suggested a Permian–Late Jurassic origin for a set of oils based on novel specific age biomarkers.
The objective of the study was to evaluate basin-scale trends by inferring the ages, depositional environments and potential source rocks for the petroleums investigated. The present paper reports the results in the context of observations obtained from previous maturity and alteration studies (Lerch et al. 2016a, b). It is felt that such a systematic approach provides the basis for discerning the ages and origins of blended and altered oils.
Map of the study area showing wells and major discoveries. MNFC, Måsøy–Nysleppen Fault Complex; SD, Samson Dome; TFFC, Troms–Finnmark Fault Complex. Modified after NPD (2014).
Carboniferous shales of Visean age on the Finnmark Platform reveal fair–good petroleum potential (Pedersen et al. 2005). Local deposition in restricted basins formed by half-graben resulted in very good source quality (Johansen et al. 1993). The oil-prone, coal-bearing Lower Carboniferous Tettegras Formation (Fig. 2), deposited on deltaic to coastal plains (Ehrenberg et al. 1998), has the potential to generate liquid hydrocarbons (van Koeverden et al. 2010). Thus, the Tettegras Formation could serve as an important source interval in the graben structures, and can be related to the Billefjord type shales on Svalbard (Abdullah et al. 1988; Nøttvedt et al. 1993).
Lithostratigraphic chart for the SW Barents Sea showing lithologies, potential source rocks and reservoir rocks (modified after Ohm et al. 2008; Norlex 2013).
Organically poor- to moderate-quality source-rock intervals of Lower Permian evaporites (Fig. 2) show some potential in the Nordkapp Basin (Johansen et al. 1993), while Lower Permian Brucebyen Beds on Svalbard have oil potential (Nøttvedt et al. 1993). Limited source potential for Upper Permian shales and spiculites was reported by Stemmerik & Worsley (2005), but the potential may be substantially better downdip from the typical drilled highs and could be similar to the Ravnefjeld Formation in East Greenland studied by Christiansen et al. (1993). The Røye Formation (Fig. 2), deposited in low-energy, deep-shelf to distal marine environments (Larssen et al. 2002), was tested oil prone in the eastern part of the study area (Pedersen et al. 2005). Deposition of thin and organic-rich shales in deep-shelf environments with dysoxic–anoxic conditions resulted in gas potential in the Upper Permian Ørret Formation in the eastern part of the study area (Johansen et al. 1993; Larssen et al. 2002). However, it is still debatable whether the Upper Permian in the Barents Sea shows similar facies to those found on East Greenland and off Mid-Norway (Bugge et al. 2002), or if hypersaline sabkha facies might exist in undrilled locations.
Marine, organic-rich Lower–Middle Triassic source rocks include the Havert, Kobbe (Steinkobbe) and Klappmyss formations, equivalent to the Botneheia Formation on Svalbard (Mørk & Bjorøy 1984; Riis et al. 2008; Lundschien et al. 2014). These represent some of the best studied and most widely distributed source-rock units in the Barents Sea (Fig. 2). Mørk & Bjorøy (1984) concluded that the Botneheia Formation mainly contains Type II kerogen. Yet, Vigran et al. (2008) mentioned an additional occurrence of Type I kerogen that may increase the generation potential. Leith et al. (1993) reported that organic-rich mudstones of the same formation deposited in lagoonal or lacustrine settings may be considered in the Hammerfest Basin. More proximal, near-land conditions might explain woody fragments in Triassic rocks from the Svalis Dome area (Fig. 1). However, Abay et al. (2014) found the Steinkobbe and Kobbe formations from the Svalis Dome and Hammerfest Basin, respectively, to have been deposited under marine, restricted reducing environments. The Kobbe Formation from the Nordkapp Basin and the Bjarmeland Platform is characterized by a higher input of terrigenous organic matter (OM) deposited under fluvio-deltaic, dysoxic conditions. Upper Triassic shales of the Snadd and Fruholmen formations (Fig. 2) were deposited in transitional environments (Ohm et al. 2008), and show good petroleum generation potential (Pedersen et al. 2005) comparable to the Lower–Middle Triassic shales (Johansen et al. 1993).
The rapid ‘build-out’ and westwards migration of the Triassic clastic systems from Novaya Zemlya to the western margin of the Barents Shelf is a characteristic element of the Triassic period. Thus, OM deposited under hypersaline, lagoonal, marine-proximal and marine-distal, and with variable amounts of carbonate input, has to be considered (Brekke et al. 2001). Triassic source rocks in the region may, hence, take on many shades of organo-facies signatures, and may contribute to the problems of a regional relevant, uniform identification of a ‘Triassic source-rock facies’.
The Upper Jurassic, organic-rich marine shales of the Hekkingen Formation (Fig. 2) are the most widely distributed prolific source rocks in the western part of the Barents Sea. These shales are much more uniform in organo-facies signatures compared to the Triassic systems. The Hekkingen Formation contains Type II–III OM with excellent potential to generate both oil and gas, and is of the same organo-facies as the Spekk, Draupne, Mandal and Kimmeridge formations further south on the Norwegian Shelf (Ohm et al. 2008). Still, the ‘petroleum machinery’ based on this facies is regionally restricted and highest in the Hammerfest Basin, with immature to early mature levels further to the east. Gas mature and overmature conditions prevail towards the west and in the Tromsø Basin. The humic to gas-prone Lower Jurassic Nordmela Formation (Fig. 2) was deposited in a more terrestrial-influenced palaeo-depositional system, thus having the capability to generate more waxy oil compared to the Hekkingen Formation (Stewart et al. 1995; Ohm et al. 2008). The Tubåen Formation is characterized by mixed terrestrial and marine input.
The Cretaceous Kolje Formation shales are mature in the western part of the study area (Johansen et al. 1993). Its potential to generate hydrocarbons varies from gas- to oil-prone, corresponding to marine Type II–II/III kerogen (Pedersen 2014), but its regional significance as a source rock for oil is, for now, unclear.
Fifty liquid hydrocarbon samples (condensates and oils) from 30 wells in the SW Barents Sea were analysed by gas chromatography flame ionization detector (GC-FID), gas chromatography mass spectrometry (GC-MS) and GC-MS-MS by Applied Petroleum Technology AS, Norway. Analysed samples were collected between the mid-1980s and 2008 from wells representing discoveries and producing fields (e.g. Askeladd, Albatross, Snøhvit and Goliat) (Fig. 1), non-commercial discoveries, and dry structures with oil shows. Three of the samples are from Cretaceous reservoirs, 28 from Jurassic reservoirs, 11 from Triassic reservoirs, six from Permian reservoirs and two from Lower Carboniferous–Early Permian reservoirs (Table 1).
Whole oil analysis was carried out on an Agilent 7890A instrument equipped with a HP PONA column (50 m × 0.2 mm i.d., film thickness 0.5 µm). The temperature program applied was: 30°C (10 min hold) to 60°C at 2°C min–1, then to 130°C at 2°C min–1, followed by 4°C min–1 to 320°C (25 min hold).
Gas chromatography mass spectrometry of saturated and aromatic fractions was carried out on a Micromass ProSpec high-resolution instrument equipped with a CP-Sil-5 CB-MS column (60 m × 0.25 mm i.d., film thickness 0.25 µm). The temperature program used was: 50°C (1 min hold) to 120°C at 20°C min–1, then to 320°C (20 min hold) at 2°C min–1. Data were acquired using selected ion recording (SIR) mode. Saturated hydrocarbons were monitored using m/z 191, 217 and 218, while aromatic hydrocarbons were monitored using m/z 192, 198 and 231.
GC-MS-MS for aliphatic compounds was performed on a Thermo Scientific TSQ Quantum instrument. The collision energy is 15 V with argon as the collision gas at a pressure of 1.0 mTorr. The column used was a FactorFour VF-1ms (60 m × 0.25 mm i.d., film thickness 0.25 μm). Transitions monitored are the following: m/z 358 → 217, 372 → 217, 386 → 217, 400 → 217 and 414 → 217.
δ13C isotope values of selected samples were included in the database and collected from different geochemical reports available at the NPD (2014). The biomarker ratios have been calculated based on peak areas.
δ13C isotope values can be used for petroleum correlation (Peters et al. 2005), age classification (Andrusevich et al. 1998) or indication of depositional environments (Sofer 1984). The δ13C signature of the saturated fraction in this study was found to vary between −27.1 and −32.2‰, while the aromatic fraction has δ13C values ranging from −25.6 to −31.5‰ (Table 1).
Holba et al. (2001) defined the extended tricyclic terpane ratio (ETR = (C28 + C29 tricyclic terpanes/Ts)) to discriminate between petroleums sourced from the Triassic (ETR ≥ 2.0), Early Jurassic (ETR ≤ 2.0) and Late Jurassic (ETR ≤ 1.2). However, the ratio may be influenced by marine upwelling (Holba et al. 2003). ETR values in this study range from 0.56 to 2.56 (Table 1), indicating Triassic–Late Jurassic derived petroleum. The sterane ratio C28/C29 (measured on the m/z 218) was applied by Grantham & Wakefield (1988) and Schwark & Empt (2006) to interpret ages of oils and source rocks. Both studies found increasing C28/C29 ratios with decreasing age of the source. Preferred enrichment of C29 steranes in land-plant-derived OM may lead to lower ratios, while greater abundances of C28 steranes indicate lacustrine source rocks. C28/C29 ratios in this study vary from 0.49 to 0.98 (Table 1). To investigate a possible Cretaceous contribution, the age-specific C26 sterane-based parameters 24-norcholestane (NCR) and 24-nordiacholestane ratio (NDR) were applied (Holba et al. 1998a, b). Both the NCR (0.14 – 0.47: Table 1) and the NDR (0.05 – 0.28: Table 1) ratios increase with decreasing geological age, and are associated with evolution of diatoms and dinoflagellates, respectively (Holba et al. 1998a; Rampen et al. 2007).
Values from 0.36 to 11.06 and from 0.21 to 7.06 were recorded in the dataset for the isoprenoid ratios pristane/n-heptadecane (Pr/n-C17) and the phytane/n-octadecane (Ph/n-C18) (Table 1; Fig. 3), respectively. These parameters indicate the redox conditions during deposition of the source rocks (Didyk et al. 1978), but also indicate maturity and biodegradation.
Representative GC-FID whole oil chromatograms. n-Alkanes are shown in five steps starting at n-C10. The filled circles indicate the two n-alkanes n-C17 and n-C18, while the two stars illustrate the isoprenoid compounds pristane and phytane.
The ratio bisnorhopane/(bisnorhopane + norhopane) (0.03 – 0.58, Table 1) can be applied as a facies parameter, provided that the petroleum samples are not of too high a maturity. Bisnorhopane commonly indicates anoxic deposition and is regarded as a marker for Upper Jurassic source rocks on the Norwegian Continental Shelf (Grantham et al. 1980; Karlsen et al. 1995). However, the ratio may be affected by maturity as the amount of bisnorhopane is reduced through the oil window, while norhopane shows a relative increase (Moldowan et al. 1984; Peters et al. 2005).
Marine- and terrestrial-derived OM can be differentiated using the hopane/sterane ratio (C30αβ/24-ethyl-5α-cholestanes (20R, 20S)). The values in this dataset vary between 1.30 and 5.96 (Table 1), which is much larger than the typical range observed for this parameter for the Kimmeridge, Mandal, Draupne and Spekk formation-derived oils (Karlsen et al. 1995). While hopanes derive from prokaryotic organisms mainly representing marine OM, steranes are attributed to eukaryotic organisms reflecting essentially algae and higher plants, and hence indicate a higher non-marine OM input (Moldowan et al. 1985). Thus, low hopane/sterane values (≤1) are indicative of marine-derived OM with dominant planktonic and/or marine algae input, while higher hopane/sterane ratios (≥1) point towards enhanced bacterial, bacterially reworked or terrestrial OM input.
Values above 1.0 for the C29αβ/C30αβ (norhopane/C30αβ) parameter typically indicate deposition of anoxic carbonate and marl source rocks (Peters et al. 2005). Values in this study range from 0.29 to 0.93 (Table 1). The ratios C3122R-hopane/C30αβ (0.14 – 0.38, Table 1) and C26/C25 tricyclic terpane (TT) (0.68 – 1.54, Table 1) discriminate marine from lacustrine-derived oils. Values > 0.25 and < 1.0 indicate deposition under marine condition for C3122R-hopane/C30αβ and C26/C25 TT ratios, respectively (Zumberge 1987; Peters et al. 2005).
The parameter diasteranes/steranes has ratios of between 0.56 and 3.83 (Table 1), and is usually applied to distinguish clastic and carbonate source rocks. Petroleums generated from carbonate source rocks commonly tend to show lower values than petroleums generated from clastic source rocks (Rubinstein et al. 1975; Hughes 1984; Mello et al. 1988). However, this parameter may be influenced by maturity, alteration and mineralogy (Peters et al. 2005), but is commonly a good proxy for the mineralogy of the source rocks in the North Sea and the Norwegian Sea (Karlsen et al. 1995). Rubinstein et al. (1975) concluded that clay-rich source rocks show a greater abundance of diasteranes because clay minerals catalyse steroid transformation. The relative abundance of C27, C28 and C29 ββ-steranes expressed as percentages calculated from the m/z 218 is used to infer depositional environments (Huang & Meinschein 1979; Moldowan et al. 1985). Values in this dataset range from 26 to 49% (C27), from 21 to 34% (C28) and from 26 to 46% (C29) (Table 1), indicating transitional environments for the majority of the samples.
As a first approximation, the samples were classified based on δ13C isotope values according to Ohm et al. (2008) (Fig. 4): Permian–Carboniferous-sourced petroleums (lightest δ13C values: −32 to c. −30‰); Triassic-sourced petroleums (intermediate δ13C values: c. −30 to c. −29‰); and Jurassic-sourced petroleums (heaviest δ13C values: c. −29 to −25‰). However, Throndsen (pers. comm. 2014) ascribed the lightest values (−32 to c. −30‰) to Triassic-sourced petroleums, intermediate values (−30 to c. −29‰) to Jurassic sources, and values between approximately −29 and −25‰ to Palaeozoic petroleums.
Cross-plot of the δ13C saturated v. δ13C aromatic hydrocarbon fractions indicating genetic relationships between the samples. The suggested ages are taken from Ohm et al. (2008).
Still, this classification can only be an indirect method to determine the age, as the stable carbon isotope values reflect the δ13C composition of the parent kerogen (Galimov 1980): that is, the effect of OM input and preservation in the palaeo-depositional environment, more than age as such. Yet, Sofer (1991) mentioned increasing δ13C values from Palaeozoic to Recent kerogens. Karlsen et al. (1995) reported that variations in δ13C whole oil values in oils from the Upper Jurassic Spekk Formation off Mid-Norway were related to the distance from the palaeo-depositional coastline. These variations seem to reflect the variable input of woody material into the source rocks with isotopically heavier, more terrestrial vitrinite influenced values in the proximal, palaeo-near-land direction.
Most condensates (squares) show heavier δ13C signatures in comparison to oils. Karlsen et al. (1995) ascribed heavier δ13C values in condensates to pronounced portioning: that is, to the enrichment in the amount of alkanes with tertiary carbon in the phase-fractionated condensates according to the beta factor discussed in Galimov (1980). It is thus likely that the stable carbon isotope composition of the Barents Sea oils and condensates are systematically different due to this effect. Fractionation effects were reported for condensates from the Askeladd and Albatross discoveries in the C4–C8 light hydrocarbon and biomarker range (Lerch et al. 2016a). However, equal isotope values for Snøhvit condensates (E, L, L2 and M; see Table 1 for the well name) and oils (E1, L1 and N; see Table 1 for the well name) indicate that the current condensate zone of the reservoir previously contained oil generated from the same formation: that is, an example of differential entrapment (cf. Gussow 1954).
Sample A from well 7119/12-3, probably generated from the gas to overmature Upper Jurassic Hekkingen Formation in the Tromsø Basin, shows the heaviest isotope signature due to its rich isoprenoid signature and very high maturity (Lerch et al. 2016a, b). Source rocks exposed to high temperatures resulted in the cracking of all hopane and sterane biomarkers in this condensate, and estimates based on methylphenanthrenes indicate a maturity in the range of 1.9% Rc (Rc is the calculated value of vitrinite reflectance) (Lerch et al. 2016b).
Heavy δ13C values for the peak-oil mature samples Z, Z1, Z4 and Z5 from the Finnmark Platform (7128/4-1) may be related to a contribution from oil-prone coaly intervals that are in agreement with the ‘heavy-end-biased’ waxy n-alkane profiles of these samples, indicating a non-marine contribution. Yet, investigation of coal samples from the same well by van Koeverden et al. (2010) showed δ13C values of around −23‰, while samples from shaly successions of the same well have δ13C values of around −27‰. The latter values correspond to δ13C values of the petroleums from well 7128/4-1 in this study. Thus, one may speculate whether the δ13C value of samples from the 7128/4-1 well represent a charge from the shaly intervals only, or if the oil-prone coals of the Tettegras Formation could also contribute. However, Killops et al. (2014) and Throndsen (pers. comm. 2014) suggested a possible Permian origin that is in accordance with parameters applied in Figure 5, suggesting Late Palaeozoic–Early Jurassic source rocks.
Cross-plot of C28/C29 ββ steranes (Grantham & Wakefield 1988) against the extended tricyclic terpane ratio (ETR) (Holba et al. 2001), indicating the ages of the inferred source rocks.
Ohm et al. (2008) suggested a Permian origin for the oil found in well 7121/5-2, while Killops et al. (2014) suggested a Jurassic origin with a possible Triassic contribution. In this study, ETR values (Fig. 5) indicate a Late Jurassic origin, while the NDR values < 0.2 indicate an older origin for sample O (well 7121/5-2) (Table 1; Fig. 6). However, n-alkanes in the n-C18–n-C24 range show an even-over-odd predominance (cf. Ohm et al. 2008; Lerch et al. 2016b) that is characteristic of carbonate facies. The same characteristic pattern was also observed for the Snøhvit oils E1 (7120/6-1), L1 (7121/4-1) and N (7121/5-1), which plot with lighter isotope values and ETR values, suggesting Late Jurassic contributions (Fig. 5). Carbonate deposition in the Barents Sea is mainly associated with the Permian and not the Jurassic. Yet, Pedersen et al. (2006) described Jurassic oil from the North Sea (well 25/5-5) with an even n-alkane predominance, and suggested generation from a limited anoxic carbonate facies developed in the Upper Jurassic. Slightly higher MDBT/MP (the sum of methyldibenzothiophenes to the sum of methylphenanthrenes) (see the discussion later) ratios for sample O indicate a higher sulphur content in the parent kerogen, and may be associated with a carbonate source facies. Because the Snøhvit oils do not show elevated sulphur concentrations, it might be speculated that only the reservoir of well 7121/5-2 received higher abundances of the carbonate-associated charge.
Cross-plot showing the norcholestane ratio (NCR) against the nordiacholestane ratio (NDR). Age classification was carried out according to Holba et al. (1998a, b).
The early oil mature sample B1 from the Cretaceous reservoir of well 7120/1-2 was suggested to be a mixture of a severely biodegraded palaeo-oil and a non-degraded later charge (Lerch et al. 2016b). While sample B1 plots together with samples that are suggested to have been generated from Triassic source rocks (Fig. 4), ETR and C28/C29 ββ steranes (Fig. 5) indicate a Late Jurassic origin, and that age was also considered by Killops et al. (2014). However, given the light δ13C values, it may be suggested that the biodegraded palaeo-oil charge was actually derived from a Triassic source, the isotope signature of which was not fully ‘overprinted’ by the later arrived, non-altered Jurassic charge. Oleanane, a compound characteristic of flowering plants of the Cretaceous and Tertiary (Moldowan et al. 1994), was found in sample B1 and may support migration from a Cretaceous source. However, it could be possible that oleanane was ‘picked-up’ during migration into the Cretaceous reservoir, or that it is an in situ component of the reservoir siltstones and clays. The NCR and NDR ratios could not be determined for sample B1. Still, they were tested for sample B (7120/1-2), and a Cretaceous origin could not be proven (Fig. 6). Based on light hydrocarbon and biomarker characteristics, these two samples were reported with equal maturity and alteration histories (Lerch et al. 2016a, b). Hence, a Cretaceous contribution for the biomarker range is suggested excluded for sample B1.
For sample B2 (7120/1-2), light δ13C values (Fig. 4) suggest a Palaeozoic origin, while parameters in Figures 5 and 6 indicate Early Jurassic or older ages. However, this sample does not correlate with samples that are proposed to be sourced from Permian–Triassic source rocks (see discussion later). Yet, it may be possible that the δ13C signature represents an early oil charge, which was overprinted by a later arriving charge.
The samples C (7120/2-1), T2 and T3 (7122/7-3), U (7122/7-4 S), X (7125/1-1), Å (7220/6-1), and Ø (7222/6-1) (see Fig. 1 for well location) show δ13C values that indicate generation from Permian or Triassic source rocks (Fig. 4). Additional analyses of triaromatic dinosteroids (Karlsen pers. comm. 2013) suggested a Palaeozoic age, and a Permian source-rock affinity for sample C (7120/2-1), while Killops et al. (2014) suggested a Triassic origin. The samples Æ–Æ2 are not shown in Figure 4 owing to a lack of δ13C data. Still, these samples have common biomarker characteristics to the mentioned samples, and it is suggested that these were also generated from Permian–Triassic sources.
Sample AB (well 7228/7-1 A) from the Nordkapp Basin shows the highest ETR value in the dataset, which is partly related to its low maturity and small amounts of 18α-trisnorhopane (Ts). The NCR and NDR values suggest a Jurassic or younger age (Fig. 6). This is noteworthy as the Jurassic source rocks are immature in this eastern part of the study area. It is therefore unclear how Jurassic source rocks could have generated these oils, as Jurassic source rocks are seldom observed with the striking pattern of tricyclic terpanes, although some C28TT and C29TT have been found in petroleums from the Haltenbanken area (Karlsen et al. 1995). It is only speculated here that the NCR and NDR values might have been influenced by migration pick-up during migration.
The oil samples S (7122/7-1), T and T1 (7122/7-3) from the shallower Goliat reservoir (Tubåen and Snadd formations; Late Triassic) correlate well with oils E1, L1 and N from the Snøhvit Field (Figs 4 and 5), and support long-distance migration of Jurassic-sourced oils as suggested by light hydrocarbon signatures (Rodrigues Duran et al. 2013; Lerch et al. 2016a). However, the deeper and more complicated reservoir (Kobbe Formation; Middle Triassic) section in Goliat contains the signature of oil that is markedly similar to Triassic or older derived oils. Thus, it seems that the deeper reservoir of the structurally very complex Goliat Field was able to retain older palaeo-petroleum compared to the upper, shallower part, which may have received a later charge of Jurassic derived oil.
Tri- and tetracyclic terpanes as unconventional age indicators?
Lerch et al. (2016b) suggested a characteristic terpane distribution (sparse C24TET and more abundant C26TT) to be indicative of Permian–Triassic-sourced petroleum in the present database (Fig. 7).
Representative chromatograms of m/z = 191 showing the distribution of tri- and tetracyclic terpanes that may be indicative of age in the present database. Samples from Family A have low abundances of C24TET and greater abundances of C26TT, while samples from Family C show greater abundances of C24TET and lower abundances of C26TT. The peaks labelled ‘U’ and ‘V’ represent the C28 and C29 cheilanthanes, respectively.
Tricyclic terpanes are generally applied to indicate the depositional environment of source rocks, OM input and also for oil correlation studies (Peters et al. 2005). Various precursors for tricyclic terpanes have been proposed over about the last 30 years (Ourisson et al. 1982; Aquino Neto et al. 1983; Simoneit et al. 1993; Revill et al. 1994; Farrimond et al. 1999; Dutta et al. 2006; Samuel et al. 2010). While Ourisson et al. (1982) regarded tricyclic terpanes to be diagenetic products of prokaryotic membranes, Revill et al. (1994) and Simoneit et al. (1993) considered the origin of tricyclic terpanes in Tasmanites. However, Farrimond et al. (1999) mentioned that tricyclic terpanes have been observed in various sediments, and Dutta et al. (2006) and Samuel et al. (2010) advised that a relationship between tricyclic terpanes and Tasmanites does not always exist, and that their occurrence may also be related to other biological sources.
Furthermore, as the tricyclic terpanes are structurally smaller than C30+ hopanes, they have significantly higher thermal stabilities, and also a greater generation rate at elevated maturities. They are also enriched compared to the pentacyclic compounds (i.e. in high gas to oil ratio (GOR) petroleums (condensates)), which is an effect of their smaller molecular size and, hence, higher vapour pressure compared to the C30+ hopanes (Karlsen et al. 1995). While marine-derived petroleums often show greater abundances of C23TT (Aquino Neto et al. 1983), the C19TT and C20TT are more abundant in terrestrial petroleums (Peters & Moldowan 1993). Originally, greater amounts of C24TET in petroleums were considered to indicate carbonate/evaporitic and terrestrial depositional environments by Palacas et al. (1984) and Philp & Gilbert (1986), respectively. Aquino Neto et al. (1983) suggested thermal degradation of hopanoid compounds as an origin for C24TET. However, it was shown that the abundance of C24TET in the present database is not related to increased thermal maturity (Lerch et al. 2016b).
Figure 8a shows the ratios (C20 + C21)/(C23 + C24)TT v. C26TT/C24TET. The C26TT/C24TET ratio appears to be source related, with higher values reflecting deposition under slightly reducing conditions. Samples suggested to imply Palaeozoic or Triassic ages (Figs 4 and 5) plot close together, indicating a genetic relationship and inferred source-rock deposition in marine to transitional-lagoonal reducing environments. A similar sample distribution is shown in Figure 8b, where the inferred Permian–Triassic samples indicate deposition under lacustrine–marine environments, while the remaining samples suggest deposition under marine–transitional conditions.
Two cross-plots illustrating the use of tri- and tetracyclic compounds as unconventional age discriminators in the present study. Both plots show good correlation and thus are suggested to effectively discriminate between Permian–Triassic- and Jurassic-derived petroleums. (a) (C20 + C21)/(C23 + C24)TT v. C26TT/C24TET; and (b) C25TT/C24TET v. C26/C25TT.
Sparse C24TET in combination with abundant C26TT and extended tricyclic terpanes was recently reported for migrated oil stains in the Triassic De Geerdalen Formation on Svalbard (Abay pers. comm. 2016). The migrated oil is of a maturity in the range of % Rc = 1.3 – 1.5, and is considered to be sourced from the Botneheia Formation, the Triassic onshore equivalent of the Kobbe/Steinkobbe Formation in the Barents Sea. In addition, elevated abundances of tricyclic terpanes have also been found by Isaksen (1996), studying bitumen from Triassic rocks on Bjørnøya, who concluded bacterial-rich source rocks as an origin.
Furthermore, elevated extended tricyclic peaks, sparse C24TET and abundant C26TT are in accordance with observations made by Bugge et al. (2002), who investigated oil-stained sandstones on the mid-Norwegian Shelf (well 6611/09-U-01). The cored section was dated as Upper Permian–Lower Triassic, and was correlated with the Upper Permian Ravnefjeld and the Lower Triassic Wordie Creek formations known from East Greenland. Generation from Upper Permian marine source rocks was suggested based on geochemical similarities of the extracts combined with lithostratigraphic observations. Despite heavier δ13C values (−27.8 to −26.3‰) for the oil stains extracted from the Permian sandstones in Bugge et al. (2002), the characteristic tricyclic terpane distributions found in the present study and data by Abay (pers. comm. 2016) are taken to imply contributions from Permian source rocks in addition to Triassic derived oils.
A comparable grouping of the samples has been observed in a cross-plot using C27/C28 triaromatic steroids and C28/C29 steranes (Fig. 9). It can be seen that both ratios correlate well, thus suggesting a genetic relationship between the ratios used (cf. Li et al. 2012). Samples characterized by higher C26TT/C24TET ratios demonstrate a closer genetic relationship compared to other samples. Elevated values for the condensates can be attributed to fractionation effects (cf. Karlsen et al. 1995).
Cross-plot of C27/C28 triaromatic steroids against C28/C29 regular steranes separating the samples with respect to source-rock age.
Despite the fact that the parameters applied in Figure 8 are primarily utilized to indicate organic facies, the samples show variations with respect to depositional environments (see the discussion in the following section). The characteristic terpane pattern (sparse C24TET and abundant C26TT) may thus suggest basin-wide occurrence of the precursor compounds that preferentially occurred in shallow shelf to delta plain environments (cf. Riis et al. 2008). It is therefore suggested that these compound distributions can be used as an unconventional auxiliary parameter for inferences of source-rock age in the present database.
Family A: C (7120/2-1), T2 and T3 (7122/7-3), U (7122/7-4 S), X (7125/1-1), Å (7220/6-1) and Ø (7222/6-1), Æ–Æ2 (7222/11-2T), and AB (7228/7-1 A).
Family C: B–B2 (7120/1-2), D (7120/2-2), E1 (7120/6-1), L1 (7121/4-1), N (7121/5-1), O (7121/5-2), R1 (7122/6-1), S (7122/7-1), T–T1 (7122/7-3), V–V1 (7123/4-1 A), W (7124/3-1) and Y (7125/4-1).
Family 4: The generic condensates: that is, samples that group separately due to their phase-fractionated origin which ‘skews’ several source facies parameters, so that the source affinity is obscured.
Cumulative bar-chart diagram dividing the samples into four families related to their tri- and tetracyclic terpane percentage distribution.
Figure 11 compares the isoprenoid ratios Pr/n-C17 and Ph/n-C18. Family B samples Z–Z5 (7128/4-1) indicate deposition under oxic conditions related to a peat coal environment that is in agreement with the waxy n-alkane profile. The majority of the samples indicate deposition in transitional environments with varying oxygen levels. The Pr/Ph ratio plotted against MDBT/MP (Hughes et al. 1995) in Figure 12 indicates the redox potential during deposition. Anoxic conditions are indicated by Pr/Ph ratios < 1 (Didyk et al. 1978), deposition under oxic conditions is expressed by ratios > 1 (Peters et al. 2005), while Type II marine shales have values ranging between 0.6 and 1.6. All samples plot in the area indicating deposition under marine–lacustrine conditions. The samples D (7120/2-2, Family C) and X (7125/1-1, Family A) show higher Pr/Ph values indicating generation from source rocks deposited under slightly higher oxic conditions, which is consistent with Figure 11. High Pr/Ph and low MDBT/MP values for samples from well 7128/4-1 (Family B) illustrate generation from a peat coal environment (cf. van Koeverden et al. 2010) rather than Permian marine carbonates (Throndsen pers. comm. 2014).
Cross-plot of phytane/n-C18 v. pristane/n-C17 indicating the depositional environment and redox conditions during deposition (modified after Shanmugam 1985). The elevated values for sample Å (7220/6-1) are related to biodegradation, as described in Lerch et al. (2016b).
Cross-plot of pristane/phytane (Pr/Ph) v. MDBT/MP, suggesting the depositional environment of the source rocks (after Hughes et al. 1995).
MDBT/MP values illustrating a slightly higher sulphur content in the source kerogen are shown for Family C samples B and B2 (7120/1-2), O (7121/5-2) and W (7124/3-1) (Table 1; Fig. 12). Elevated amounts of MDBT may suggest a contribution from a Permian or Jurassic (cf. Pedersen et al. 2006) carbonate source to sample O that is in agreement with the slight even-over-odd preference in the n-C20–n-C24 n-alkane range.
The condensates (Family D), however, express a more terrestrial origin in both diagrams (Figs 11 and 12). This effect can be ascribed to the relative enrichment of isoprenoid compounds pristane and phytane relative to n-C17 and n-C18 during migration-induced fractionation processes (Karlsen et al. 1995).
Hydrocarbon generation from carbonate source rocks could not be confirmed by the C29αβ/C30αβ ratio in Figure 13a. Family C samples B, B2, O and W (Table 1) that showed higher MDBT/MP ratios plot far below the suggested value of 1.0 that is indicative of carbonate source rocks (Peters et al. 2005). Thus, low C29αβ/C30αβ ratios seem rather to indicate generation from marine, clay-rich source rocks (Connan et al. 1986).
Two cross-plots demonstrate the inferred depositional environments of the source rocks. Samples that are suggested to be derived from Permian–Triassic source rocks show a good correlation in both diagrams, which indicates a common depositional environment compared to the majority of the samples.
Values greater than 0.25 for the C3122R/C30αβ parameter suggest generation from marine shale, carbonate or marly source rocks (Fig. 13a). Samples from Family A, except samples Æ1and AB, plot close together, suggesting comparable depositional environments. The oils from Family C are broadly separated into two clusters. Oils from the Snøhvit discovery (E1, L1, and N) plot together with oils from the shallower Goliat reservoir (S, T, T1), indicating a clear correlation and supporting remigration into the shallower part of the Goliat reservoir from the Snøhvit region, as previously discussed. Oils V and V1 (7123/4-1 A: see Fig. 1 for the location), and two oils from the Måsøy–Nysleppen Fault Complex (W (7124/3-1) and Y (7125/4-1: see Fig. 1 for the location), plot in the marine-influenced area. Sample B2 (7120/1-2) has the highest C3122R/C30αβ values, which may indicate generation from a carbonate source rock (cf. Peters et al. 2005), and is in agreement with the highest MDBT/MP values in the database (Fig. 12). However, the C29αβ/C30αβ ratio does not support a carbonate origin.
Because samples V, V1, W and Y show nearly identical biomarker characteristics (see the discussion below), and nearly identical maturity values for the C20+ fraction (Lerch et al. 2016b), generation from genetically linked sources can be suggested.
Figure 13b shows the ratios of C3122R/C30αβ v. C26/C25TT. Samples from Family A indicate generation from marine–lacustrine source rocks, a variation that probably reflects changing redox conditions and variable input of OM into palaeo-depositional environments that is in agreement with Figure 8b. Although Family A samples demonstrate generation from a lacustrine source, the absence of β-carotane (cf. Jiang & Fowler 1986) and distribution of ββ regular steranes do not support contributions to the reservoired petroleums from lacustrine source rocks as such.
Samples B2 (7120/1-2) and O (7121/5-2) have low C26/C25TT values, and indicate generation from carbonate and/or marly source rocks (cf. Peters et al. 2005).
Ratios of between 0.39 and 2.37 for the C30-diahopane/C29Ts parameter (Table 1) indicate that samples with higher values could have been generated from clastic source rocks deposited under oxic–suboxic conditions (Sachsenhofer et al. 1995; Peters et al. 2005). Lower ratios, however, indicate a more reducing depositional environment. While Volkman et al. (1983) and Philp & Gilbert (1986) suggested a bacterial origin of the C30-diahopane, Moldowan et al. (1991) concluded that the C29Ts derives from a regular bacterial hopane. However, Volkman et al. (1983) and Philp & Gilbert (1986) suggested formation of the C30-diahopane by clay catalysis rearrangement during diagenesis, while Moldowan et al. (1991) concluded that variations in both compounds can be related to diagenetic effects. Because both compounds have been reported to derive from bacterial precursors, higher values could indicate bacterial input into oxic–suboxic depositional environments, and this could represent the progradation of paralic Triassic sediments (Riis et al. 2008). However, higher ratios may be the result of elevated thermal maturities, which has been reported for samples C (7120/2-1), O (7121/5-2), T2 and T3 (7122/7-3), U (7122/7-4 S), and Æ–Æ2 (7222/11-1 T2) in Lerch et al. (2016b).
Homohopane distributions (Fig. 14) can be utilized to differentiate between oxic and reducing palaeo-depositional environments, yet the distributions can be affected by maturity and secondary alteration (Peters & Moldowan 1991). The distribution for Family B (Fig. 14) indicates deposition under slightly higher oxic conditions (cf. Peters & Moldowan 1991), which is in accordance with higher Pr/Ph values (Fig. 12). The homohopane distribution for Family A suggests deposition under more reducing conditions, while sample AB (7228/7-1 A) implicates deposition under slightly higher oxygen concentration that is in contrast to the Pr/Ph values (Fig. 12) and C29αβ/30αβ ratios (Fig. 13). The samples in Family C implicate greater variations in oxygen levels during deposition (Fig. 14). Higher concentrations of C31 and C33 hopanes have been found in samples B and B1 (7120/1-2). Such patterns were reported by Peters & Moldowan (1991) to indicate: (1) other precursors for homohopanes than bacteriohopanetetrol; or (2) a variation in redox conditions under deposition. Therefore, the C33 homohopane dominance may be indicative of different bacterial input and may thus, along with the elevated 28,30-bisnorhopane ratio (Table 1), indicate an anoxic marine niche environment most likely to be associated with the Upper Jurassic (cf. Vobes 1998). Occurrence of 28,30-bisnorhopane generally indicates the presence of chemoautotrophic bacteria that lived at the oxic–anoxic interface (Nytoft et al. 2000), while Mello et al. (1988) considered the compound indicative of highly reducing to anoxic clay-poor depositional environments. Deposition with reduced clay input is consistent with higher C29αβ/C30αβ and diasteranes/sterane ratios for the samples B and B1 (Fig. 13). However, samples B and B1 (7120/1-2) show higher C26/C25TT ratios (0.98 and 1.07, respectively: Table 1), and gammacerane index ratios (gammacerane/(gammacerane + C30αβ hopane)) of 0.09 that suggest some water-column stratification. Because these characteristics have only been observed for samples B and B1, a clay-poor, predominantly marine-reducing depositional environment is suggested for these samples.
Three cross-plots illustrating the percentage distribution of C31–C35 homohopanes, which indicates the redox conditions during source-rock deposition (after Peters & Moldowan 1991).
Figure 15 shows the distribution of ββ-steranes expressed as percentages calculated from the m/z 218 ion chromatogram. Greater relative concentrations of C29 steranes indicate a higher land-plant contribution, C28 steranes are associated with lacustrine algae and C27 steranes mainly derive from marine phytoplankton (Huang & Meinschein 1979). Owing to fractionation effects and the preferred enrichment of C27 steranes over C28 and C29 steranes, condensates take on a more C27-dominated algal signature than the parent source rock (Karlsen et al. 1995, 2004). Higher proportions of C27 steranes for samples Z–Z5 (7128/4-1: Family B) may indicate short-termed marine transgressions or deposition on delta plains (Ehrenberg et al. 1998; van Koeverden et al. 2010) that have led to increased marine OM input into the source rocks, and stay in contrast to the predominant terrestrial signatures observed in Figures 11 and 12.
Ternary plot of C27, C28 and C29 ββ regular steranes (measured on m/z = 218) illustrating the depositional environment for the samples (after Shanmugam 1985).
The majority of the oils show higher abundances of C27 and C29 steranes that demonstrate a predominance of marine and higher plant input, which is to be expected in marine, anoxic shelf settings where the amount of river-carried OM detritus will vary (Fig. 16). This pattern reflects transitional depositional environments and indicates the varying distances to the shoreline, as described in Karlsen et al. (1995). Family C oils that are suggested to have been expelled from the Jurassic Hekkingen Formation, indicate generation from a more terrestrial-influenced kerogen blend as shown by higher C29 sterane concentrations. However, it should be cautioned that higher abundances of C29 steranes may, in certain environments, also derive from marine brown or certain green algae (Moldowan et al. 1985). Yet, higher abundance of C29 steranes may also indicate a contribution from the terrestrial-influenced Nordmela Formation that tends to generate more waxy oil (Linjordet & Grung Olsen 1992). In other words, the problems of multi-source-rock systems are apparent, but we remain confident that the amount of C29 steranes in Family C petroleums is an indicator of proximal and distal shoreline variation.
Representative chromatograms of m/z = 218 showing the distribution of the ββ-steranes for each petroleum family.
Indications of lacustrine depositional environments, commonly expressed by elevated amounts of C28 steranes (as shown in Figs 8 and 13), have not been found to be significant and such environments are not commonly observed for commercial quantities of oil on the Norwegian Offshore Continental Shelf (NOCS) (Karlsen et al. 1995, 2004).
The presence of C30 steranes (24-n-propylcholestane) is related to OM deposited in a marine depositional environment (Moldowan 1984; Peters et al. 2005), but its presence in a source rock would not directly refute that the same source rock also received OM from higher terrestrial flora via river influx and as wind-blown detritus. Calculated C27–C30 sterane percentages for selected samples are shown in Table 2. Values for samples B and B2 (7120/1-2) are consistent with a marine origin, as suggested in Figures 13 and 17. A C30 sterane percentage of 12.07% (Table 2) for sample C (7120/2-1) may reflect a dominant marine input into the source-rock kerogen. However, sample C (Family A) demonstrates generation from a source rock deposited under lacustrine–transitional environments. It is worth considering that lacustrine river input may flow over on top of a marine water column, resulting in a mixed OM signature. The samples Z, Z2 and Z3 (7128/4-1) that have been suggested to be generated from the coaly Lower Carboniferous Tettegras Formation show the lowest C30 sterane values. Still, the presence of C30 steranes supports observations of variations in ‘palaeo-depositional’ environments or mixing of petroleums, as reported in Lerch et al. (2016b). Yet, higher abundances of C29 steranes in samples that are characterized by higher C30 sterane concentrations may indicate a marine origin of the C29 steranes (Moldowan et al. 1985), or illustrate a strong transitional character.
Cross-plot of hopane/sterane against diasteranes/steranes, which indicates the depositional environment of the inferred source rocks.
The ratio diasteranes/steranes shown in Figure 17 is used to distinguish carbonate from clay-rich source rocks. Values of between 0.54 and 3.83 (Table 1) indicate generation from clay-poor to moderate clay-rich source rocks, with substantial variations in oxygen levels during deposition. Still, samples that plot with lower values may have been sourced from more anoxic source rocks. Hughes et al. (1985) reported that steranes are gradually converted into diasteranes with increasing maturity. However, preferred enrichment of diasteranes over regular steranes in condensates is also related to fractionation effects (Karlsen et al. 1995, 2004).
Higher hopane/sterane ratios for samples D (7120/2-2), V, V1 (7123/4-1 A), W (7124/3-1), X (7125/1-1), Y (7125/4-1), Å (7220/6-1), Ø (7222/6-1 S) and AB (7228/7-1 A) indicate a bacteria-rich ‘organo facies’, bacterially reworked OM or terrestrial input (Moldowan et al. 1985). The samples B, B1 and B2 (7120/1-2) indicate a dominant input of marine OM, which is consistent with the bisnorhopane ratio, higher C29αβ/C30αβ and C26/C25TT.
In this dataset, biomarker analysis revealed prevalent petroleum generation from marine Type II to mixed Type II/III to Type III/II kerogens. Yet, kerogen Type I may have contributed to samples deposited under more lacustrine conditions (Figs 12, 13 and 17). However, some of the most characteristic facies-specific biomarkers, like β-carotane and Ni/V ratios, were not at hand in this study, and high relative concentrations of C28ββ steranes and gammacerane have not been found. Therefore, it may only be suggested that the lacustrine or hypersaline sabkha facies signatures, if present in the database, are masked or ‘blended-out’ by other more normal marine oils. It could, however, be claimed that the database is biased by the selection of the available samples, with most from the typical marine-influenced Hammerfest and Nordkapp basins, and that oils from the platform regions will show more varied facies signatures. Evidence for this is sample C (well 7120/2-1) from the Upper Permian carbonates at the Loppa High, which contains both gammacerane and extended tricyclic terpanes. The same was reported for the Gotha oil from well 7120/1-3, which has been defined as Upper Permian, although these oils have been reported not to be of the same source facies (Pedersen pers. comm. 2015). Inferred palaeo-redox conditions (Figs 11 and 12) for the sample set are inferred to have varied from anoxic–dysoxic to suboxic–oxic, suggesting deposition in distal marine, open shelf towards more oxic nearshore, delta/floodplains and swamp depositional environments.
Lerch et al. (2016a, b) investigated maturity signatures for the present database, and found that some petroleum samples are, in fact, blends between C20+ ‘palaeo-oils’ and C20− fractions that represent later charges. In addition, Karlsen (pers. comm. 2015) proposed possible early migration events (e.g. on stable platform highs) that may have been mixed with later generated petroleums. Mixed charges will contain a more complicated maturity and organo-facies signature that needs to be deciphered. Thus, variations in parameters reflecting depositional environments, with contrasting and even conflicting facies signatures, and inferred OM input may, in fact, indicate the presence of multiple petroleum charges. It is our view that such blended signatures are far more abundant in the Barents Sea than elsewhere on the NOCS.
In order to recognize genetic relationships between the samples, principal component analysis (PCA) and hierarchical cluster analysis (HCA) were carried out using Minitab17 software. PCA is commonly used to reduce the dimensionality of greater datasets when many variables are studied together, whereby the most significant statistical variation is reduced to two or three components. The HCA displays the degree of similarity between the samples. The validity of using statistical approaches in oil–oil correlation studies has been proven previously (e.g. Peters et al. 1986; Zumberge 1987; Karlsen et al. 1995).
Care should also be taken when comparing condensates and oils using statistical methods, as systematic differences between these two occur related to pressure–volume–temperature (PVT) relationships: that is, condensates are enriched in lighter, lower boiling point components.
The data set was pre-treated, and samples with missing values were excluded from the data matrix. For the PCA, all variables were standardized to obtain a comparable weight in the PCA. The PCA was preliminary tested prior to the final version in order to recognize any influence of fractionated, biodegraded or highly mature samples. Owing to the fact that only minor influence of condensates and slightly altered samples on the PCA was observed, all samples that could be integrated into the matrix were included in the analyses. The HCA was carried out using standardized values, average linkage and Euclidean distance.
Twenty-three source- and age-related parameters (see Table 1) for 39 samples were used for the analyses. However, some of the condensates have not been included due to low concentrations or the absence of some compounds. The PCA output is shown as a 3D scatterplot in Figure 18, where the first three components account for 67.9% of the total variance (PC1 = 34.4%, PC2 = 21.3% and PC3 = 12.2%), while the HCA results are displayed in Figure 19. Based on the PCA results, it was possible to confirm the classification into four families based on age and organic facies parameters (Fig. 18): Family A (purple oval shape: inferred Triassic–Permian sourced); Family B (pale green oval shape: inferred Carboniferous sourced); Family C (blue circle: inferred Jurassic sourced); and Family D (striped pink oval shape: condensates). By comparing the PCA with the HCA and geochemical results, it is possible to classify several sub-families (SF) related to varying depositional environments and organic input. The sub-clustering in Figure 16 was carried out in accordance with the geochemical results discussed in the previous sections.
3D scatterplot for the PCA of 39 samples based on 23 biomarkers. The first three components explain 67.9% of the total variance and categorize the samples into four families: Family A, Permian–Triassic; Family B, Carboniferous; Family C, Jurassic; Family D, condensates.
Dendogram for 39 samples based on 23 biomarkers. The sub-grouping was carried out according to biomarker results discussed in the text.
Family A samples may be subdivided into two SF: SF A-I, a more marine-influenced family; and SF A-II, a more terrestrial influenced family. Samples Æ1 and Æ2 (7222/11-1 T2) represent highly mature samples, and sample Å (7220/6-1) is classified as being slightly to moderately biodegraded (Lerch et al. 2016b). However, based on isotope signatures and biomarker parameters, a Permian–Triassic origin should also be considered plausible. Family C samples may be divided into five SF: SF C-I is mainly marine influenced and deposited under anoxic conditions. The Jurassic Hekkingen Formation is suggested to be the main contributor. SF C-II shows a dominant marine signature. However, the Snøhvit oils show some indications of contributions from terrestrial-derived OM and demonstrate a slight even-over-odd preference in the n-C20–n-C25 alkanes. SF C-III is inferred to be deposited under marine, suboxic–dysoxic conditions. A contribution from a carbonate niche environment in the Upper Jurassic might be possible for sample O (7121/5-2) that has elevated MDBT/MP values and even-over-odd preference in the n-C20–n-C25 alkanes. SF C-IV consists of samples D (7120/2-2), E (7120/6-1) and L2 (7121/4-1) that indicate deposition under varying oxygen levels in transitional environments. Condensates E and L2 show more similarities with the Jurassic oils, which suggest generation from a genetically linked source rock (e.g. the Jurassic Hekkingen Formation) (cf. Rodrigues Duran et al. 2013). Sample B2 (SF C-V) is classified as being Jurassic sourced, but it shows some unusual signatures. The light δ13C isotope values, the high MDBT/MP ratio and high C3122R/C30αβ suggest generation from possible Permian carbonates. However, sample B2 does not show the characteristic terpane distribution that has been suggested to indicate Permian–Triassic samples.
One may consider the possibility that some of the condensates originated as oils in the reservoirs of the Snøhvit systems, and that later arriving gas or condensate caused a transition of the reservoir charges to high GOR systems (cf. Gussow 1954; Karlsen & Skeie 2006). The condensates (Family D) show comparable characteristics to the Carboniferous-sourced Family B, which is mainly related to the enrichment of lower boiling point compounds.
Four petroleum families have been identified and, based on the distributions of these petroleums, the following implications for petroleum systems can be drawn: inferred Permian and Triassic-sourced petroleums are mainly found in reservoirs ranging from Late Carboniferous to Late Triassic in the western part of the study area around the Loppa High and along the southern margin of the Hammerfest Basin. It is suggested that platform highs and structurally more complex regions located far from the main Jurassic hydrocarbon migration avenues have a greater chance of preservation of pre-Jurassic palaeo-oil signatures. The distribution of Permian and Triassic petroleums may be related to shielding effects provided by faults (cf. Karlsen & Skeie 2006), but might also be linked to fault-induced reactivated migration from deeper strata into the reservoirs. However, mixing with Jurassic petroleums is, in some cases, considered likely. Permian and Triassic petroleums are, in addition, more common in the eastern part of the study area and in the platform regions to the north, where the Jurassic Hekkingen Formation is generally immature or absent.
Biomarker analysis of condensate samples for source inferences may be quite challenging due to low concentrations or the absence of compounds and the high maturity of the samples. Rodrigues Duran et al. (2013) concluded, based on modelling results and gas isotope data, that condensates in the Askeladd Field (Fig. 1) were charged from the Triassic Snadd and Kobbe formations (at 1.3 – 1.5% calculated vitrinite reflectivity (Ro)), while slightly less mature condensates from the Snøhvit region were suggested to derive from the Jurassic Hekkingen Formation (Rodrigues Duran et al. 2013; Lerch et al. 2016a, b). Condensates in this study mainly represent reservoirs of Middle Jurassic age. Given the fact that source rocks from both stratigraphic levels generated and expelled petroleum, it is surprising that oils from the central part of the Hammerfest Basin demonstrate a strong Jurassic signature. Still, long-distance-migrated Jurassic charges have contributed to the shallower Goliat reservoir (Lerch et al. 2016a). Residual oil columns in the Hammerfest Basin suggest massive petroleum generation and migration, in addition to alteration of reservoired petroleums in the past (Augustson 1993), which is linked to repeated uplift and burial. Later influx of fresh, non-altered Jurassic oils and condensates during periods of renewed burial may have diluted pre-Jurassic palaeo-oil signatures in the basin centres rather than in tectonically complex structures and platform regions, where inferred pre-Jurassic petroleums have been found.
Carboniferous-sourced oils may be important in the graben systems on the Finnmark Platform, and in similar deep graben systems of the Barents Sea, where they have been found in Late Permian reservoirs. The contribution from the Permian Røye Formation, deposited in deep shelf–distal marine environments (Larssen et al. 2002) was considered by Killops et al. (2014). Thus, the presence of C30 steranes may be the result of a Permian contribution, although additional migration of petroleum phases from more eastern parts of the Barents Sea (Lerch et al. 2016a) may have occurred.
Several oils and condensates in the study region are concluded to be blends originating from more than one source-rock unit, in particular when comparing the C20+ to the C20− fractions. It was concluded in previous work (Lerch et al. 2016a, b) that it may be possible to fully deconvolute all petroleums in this respect with unique affinity to a given source-rock unit. This is due, in part, to several ‘critical moments’ for migration from Palaeozoic and Mesozoic source rocks in the region, later uplift, dismigration, remigration and refill of structures. Alteration effects – in particular, biodegradation, PVT-migration-induced fractionation and also depletion of water-soluble compounds during long-distance migration – further complicate matters related to oil-source correlation. Still, if emphasis is placed on hydrocarbon compounds in the C15+ range, the use of δ13C data and biomarker parameters, including both age-specific and source-dependent compounds, it was possible to define four petroleum families, which are supported by statistical methods. Family A oils are suggested to have been sourced from inferred Permian–Triassic source rocks, and are mainly found around and on the Loppa High and within the southern elevated basin margin of the Hammerfest Basin and the Nordkapp Basin. Family B oils have probably been sourced from the Lower Carboniferous Tettegras Formation and are found on the Finnmark Platform in the eastern part of the study area. Family C oils have been found in the central part, and on the southern and northern margins of the Hammerfest Basin, as well as the Måsøy–Nysleppen Fault Complex. It has been suggested that Family C oils mainly derived from the Jurassic Hekkingen Formation, while a contribution from the Jurassic Nordmela Formation or Permian–Triassic source rocks in some cases cannot be excluded. Family D condensates have been found in the western part of the Hammerfest Basin and in the Tromsø Basin, and are probably generated from late to gas-mature Triassic–Jurassic source rocks. However, enrichment of lower boiling point compounds in condensates during phase fractionation associated with migration is suggested to give an apparent, but likely, misleading terrestrial signature. This work did not find evidence of a Cretaceous contribution to the C15+ hydrocarbon fraction of the oils and condensates. The findings of this study suggest that petroleum families and affinities to source rocks are largely predictable from basin positions and type. However, a larger than expected proportion of blended petroleums suggest that uplift and remigration is a significantly more important factor in the Barents Sea than elsewhere on the NOCS.
This study is part of ‘The Common Ground – Arctic Petroleum System Research’ project at the University of Oslo, with close cooperation to UNIS (Svalbard) and several industry partners. The authors would like to thank NORECO ASA for project funding. Comments and suggestions by Ray McBride and an anonymous reviewer that helped to improve the manuscript are gratefully acknowledged.
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