OTC 22065

Petroleum Systems of the Russian Western Arctic BasinsT.A. Kiryukhina, A.V. Stoupakova, G. Ulyanov, N. Kiryukhina, D. Norina, A.A. SuslovaLomonosov Moscow State University

Copyright 2011, Offshore Technology Conference

This paper was prepared for presentation at the Arctic Technology Conference held in Houston, Texas, USA, 7–9 February 2011.

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Abstract

The structure of the Arctic Eurasian basins suggests that petroleum systems of Palaeozoic, Mesozoic and Cenozoic age may be present. Palaeozoic petroleum systems are well studied in the northern part of the Timan-Pechora. On the Barents-Kara shelf Palaeozoic petroleum systems are forecast, but no related hydrocarbon accumulations have been discovered, although the Palaeozoic section contains source rocks able to generate hydrocarbons. Mesozoic petroleum systems are studied in the Barents Sea and the Yamal Peninsula. They relate to Lower, Middle and Upper Triassic gas and oil source rocks, Middle Jurassic oil and gas source rocks and very rich Upper Jurassic oil source rocks.

The formation of the petroleum systems and the oil and gas potential of the basins is directly dependent on the basins’ structure and geological history. Palaeozoic intracratonic rifting increased the heat flow of the basin and resulted in oil and gas kitchens in the extensional parts of the basins. Fault tectonics allowed vertical migration of fluids.

In the deep sag basins, like the Central Barents, South Kara and North West Siberia basins, filled by both Palaeozoic and Mesozoic strata the Mesozoic petroleum systems provide significant volume of hydrocarbon, but they are influenced by Palaeozoic petroleum systems. In the Palaeozoic basins, such as Timan-Pechora, Svalbard and, probably, North Kara, the petroleum systems are linked with hydrocarbon migration from the deep Palaeozoic horizons or adjacent Mesozoic basins.

Hydrocarbon generation started long before the present basins’ structural configuration formed, and oil and gas kitchens were associated mainly with extensional parts of the basins. Later phases of rifting and extension affected both the ancient oil and gas kitchens and the younger ones. Inversion caused trapping and affected fluid migration, mixing the petroleum systems. Inverted structures in the old rifts have the highest potential for large hydrocarbons accumulations but, in highly uplifted areas affected by faulting and erosion, exploration risk is high. Forecasting hydrocarbon distribution needs profound understanding of the geological evolution of petroleum basins, their structural units and petroleum systems, which control the location of giant fields.

Introduction.

The Russian Western Arctic Basins cover the huge area including the Barents and Kara seas, the western part of the Laptev sea and adjacent territories with some archipelagoes and islands (Spitsbergen, Franz Josef Land, Severnaya Zemlya, Novaya Zemlya, etc.). They comprise the Barents and Kara Basins, the northern areas of the Timan-Pechora Basin, the North West Siberia, including Yamal and Gidan peninsulas and the Yenisey-Khatanga Basin (Fig.1,2).

The Russian Western Arctic Shelf Basins are potential for exploration of hydrocarbons as confirmed by the discoveries of the giant and large gas fields like Shtokmanovskoye in the Barents Sea, Rusanovskoye and Leningradskoye in the Kara Sea, gas condensate fields on the Yamal peninsula, oil and gas fields in the Pechora Sea and Yenisey-Khatanga basin. All the sedimentary basins on the Arctic Shelf have an intracratonic setting and have been formed by several phases of tectonism (Fig. 3). All of them are deep extensional basins (sag basins), where sediments are 8 - 15 km thick or more. The base of the crust (“Moho” boundary) varies from 40-42 to 33-35 km. The basins are filled by mainly Palaeozoic and Mesozoic sedimentary successions. Cenozoic successions are thick and prospective only on the continental margin slopes.

Fig.1 Russian Western Arctic location Fig.2 Russian Western Arctic Basins

The structure of the Arctic Eurasian basins suggests that petroleum systems of Palaeozoic and Mesozoic age may be present. Palaeozoic petroleum systems are well studied in the northern part of the Timan-Pechora. On the Barents-Kara shelf Palaeozoic petroleum systems are forecast, but no related hydrocarbon accumulations have been discovered, although the Palaeozoic section contains oil source rocks able to generate hydrocarbons. Mesozoic petroleum systems are studied in the Barents Sea and the Yamal Peninsula. They relate to Lower, Middle and Upper Triassic gas and oil source rocks, Middle Jurassic oil and gas source rocks and very rich Upper Jurassic oil source rocks.

Pechora Sea Petroleum Systems.

Pechora Sea contains hydrocarbons (HC) in the Palaleozoic strata and Lower –Middle Triassic reservoirs. There are three main petroleum systems in the basin: Ordovician – Lower Devonian clastic-carbonate, Upper Devonian Frasnian – Famennian – Lower Carboniferous siliceous carbonate and Carboniferous – Permian carbonate-clastic (table 1; fig.4).

The Ordovician – Lower Devonian clastic-carbonate group relates to Upper Silurian source rocks of type II – III. The total organic carbon (TOC) content varies from 0.23 to 4% (Kiryukhina et al. 2006). Oil occurs in Upper Silurian – Lower Devonian dolomites in the Trebsa, Titova and Upper Vozey fields. Stratigraphic traps are expected. Porosity reaches over 20% and permeability varies from 10 - 100 mD. The area contains Lower Devonian shale seals.

The Upper Devonian –Lower Carboniferous petroleum system relates to Upper Devonian Middle Frasnian siliceous carbonate shales, Domanic formation, which is the main hydrocarbon source rocks for the most Upper Palaeozoic fields in the Timan-Pechora Basin. Upper Devonian source rocks of the Pechora Sea have provided HC for the main offshore fields, like Dolginskoye oil and gas field, Prirazlomnoye oil field and Varandey more oil field. The primary source rock interval of the Upper Devonian source rock is about 100 m, which is located beneath the Upper Devonian-Lower Carboniferous carbonate buildups. The Upper Devonian Middle Frasnian Domanic source rocks consist of siliceous limestones, shaley dolomites and marls, which contain predominantly sapropelic type I and humic-sapropelic type II of organic matter. The Domanic facies formed in lacustrine environments and their TOC varies from 0.32 to 7% and reaches to 22 – 30 %. The reservoirs are associated with Frasnian-Famennian carbonate buildups, where porosity varies from 7 to 20 % and permeability from 100 to 500 mD.

Upper Frasnian – Lower Carboniferous, Tournaissian and Visean strata, containing more than 2% of the organic matter, may also be a source rocks. Their organic matter is of type II (humic-sapropelic). These source rocks are identified in the oil fields within the local Upper Devonian – Lower Carboniferous carbonate buildups in the central part of the Khoreyver depression (Surkharata, Tedinskoye, North Khosedayu, Sikhorey and others), in the Pechora-Kolva aulacogen (Kharyaga, Usa and Vozey fields) and in the Varandey-Adzva structural zone (Medyn – more, Toboy and Myadsey).

Other hydrocarbon source rocks for the Pechora offshore are Carboniferous –Lower Permian carbonate shales. They belong to type II-III; and further to the Barents Sea (Murmanskaya, Severo-Kildinskaya areas), the organic matter becomes more sapropelic and can be labeled as type II. The Carboniferous – Lower Permian source rocks contain the lowest percentage of organic matter (TOC varies from 0.32 to – 0.5 %), but the volumes of shale and organic matter are sufficient for its consideration as a source rocks for the Dolginskoye gas condensate field, Varandey more oil field and Severo-Gulyaevskoye gas-condensate field. In the Barents Sea these source rocks may have contributed to the Murmanskoye and Severo-Kildinskoye gas condensate fields. The porous and void reservoirs are associated with limestone and dolomites. Oil

and gas occur in the Pechora-Kolva aulacogen, the Varandey-Adzva structural zone and offshore the Timan-Pechora. These source rocks are located mainly in the offshore part of the basin and may have contributed hydrocarbons by lateral migration from the deepest parts of the basin.

Fig. 3. Main tectonic elements of the north Eurasian basins (Western Arctic and West Siberia)

Stoupakova et al. 2011. Modified from Surkov&Zhero (1981), Kontorovich&Surkov (2000 ), Kontorovich et al. (2001), Skorobogatov et al (2003), Timonin (1998), Ulmishek (1986), Bogdanov& Khain (1996), Gabrielsen (1990), Johansen (1994), Brekhuntsov, Bityukov (2005), Rudkevich (1986), Kalenich et al. (2004), Martirosyan, Vasilyeva (2004) and Bochkarev 2004.

Legend: 1 –extensional depressions/ Palaeozoic (Devonian) intracratonic rift systems with inherited sag basins and inverted swell: Central Barents, West Siberia, Yenisei-Khatanga, East Ural; 2 – Triassic grabens; 3 - relatively stable areas of the ancient platform; 4 – Middle Ob platform massif; 5 – syneclise; 6 – monoclines; 7 – inverted swells; 8 – depressions/extensional basins, overlying older; 9 – domes and uplifts; 10 – 13 fold belts: 10 – Baikalian, 11 – Caledonian; 12 – Hercynian; 13– Cimmerian; 14 – Triassic intrusions in West Siberia; 15 – oceanic rifting; 16 – rivers; 17 – coastal line; 18 – name of structures, 19 – Seismic profiles; 20 – Oil and gas provinces boundaries.

Core samples of the Lower Palaeozoic and and Upper Devonian-Lower Carboniferous source rocks are considered representative of the thermally mature organic matter, that constitute source rocks in this succession. They are related to the middle or end of the oil window - beginning of at the depth below 3000 m (Fig.5). Hydrogen index (HI) varies within 500 – 990 HC mg/g of rocks. Maximum bitumoid is found in the Upper Devonian Middle Frasnian source rocks and it is equal to 1.1 and 2.0%, bitumoid factor β – 18,7 and 43,6 %. The main oil and gas kitchens are located in the deep parts of the basin, in the Pechora-Kolva and Varandey-Adzva aulacogens and their extension to the offshore Pechora area, where source rocks have been matured enough for gas generation. Oil generation from Lower-Middle Palaeozoic source rocks probably started at 270 – 250 Ma during the Late Permian time and continued in the whole Mesozoic time period. Gas generation from these source rocks probably started 150 Ma in the deepest parts of the basin, but the oil generation had been continued within the whole basin.

№ Age Thickness, m Ro, % TOC, % Organic matter type

1. S1V 20-100 0.85 - 4 0.2-5.0 I-II

2. S2P 50-300 0.85 - 4 1.0-4.0 I-II

3. D1l 100-1000 0.8 - 4 0.1-11.6 II

4. D2-D3f1kn+sr 20-200 0.5 – 2.5 0.2-3.8 II-III

5. D3f3-C1t 10-300 0.4 - 2 0.5-22.7 I, II

6. С2-P1ar 50-1000 0.4 – 0.85 0.8-4.0 II-III

7. P,k-Т 50-70 0.4-0.6 0.2-2.8 (up to 25.0%) III

Table 1. Main characteristics of the source rock horizons in the Timan-Pechora basin

Fig. 4. Palaeozoic source rocks of the northern Timan-Pechora basin (Stoupakova et al 2011)

Fig. 5. Vitrinite reflectivity index variation with depth in the Prirazlomnaya and Severo-Gulyaevskaya areas

Fig. 6. Modified Van-Krevelen diagram for the Barents sea Carboniferous – Lower Permian strata

The Carboniferous – Lower Permian source rocks penetrated in the Pomorskoye and Prirazlomnoye fields at 2600-2900 m depth are located in the oil window. Their maturation is various in different parts of the Pechora offshore achives the maximum in the eastern parts of the Pechora sea, adjacent to pre-Paikhoy foreland. The mixed type of the Lower Permian organic matter is confirmed by the distribution of n-alkanes and isoprenanes in chloroform extracts in Severo-Dolginskaya and Dresvyanskaya areas. The chromatograms have bimodal distribution of n-alkanes: the first peak is in С17-С19, the second one – in С27-С28 and С29. Pristane/phitane coefficient is >1, which is evidence of dominant of humic organic matter. In the Dresvyanskaya area this ratio is 2, in Severo-Dolginskaya area it is 1.3. Lower Permian Asselian–Sakmarian and Artinskian source rocks are in the beginning of the oil window. They have not been matured enough to produce substantial quantities of oil (fig. 6).

Barents Sea Petroleum Systems.

Nowadays HC discoveries in the Eastern Barents Sea are connected mainly with the Triassic and Jurassic reservoirs. In the South Barents Sea, the Middle and Upper Triassic strata can be considered as oil and gas source rocks with prevailing gas potential. The Middle Triassic strata are represented mainly by multi-colored shales with interbeds of siltstones and sandstones. The shales comprise organic matter with TOC from 0.15% in the Severo-Kildinskaya well to 1.17% in the Pomorskaya well. The organic matter is associated with humic detritus, less often – with calcareous algae (Severo-Kildinskaya area). Rock-Eval pyrolysis data show organic matter of various types (I, II, III and transient II-III) (fig. 7).

In the northern part of the Barents Sea, Middle Triassic succession was accumulated in proximately deep shelf environments. The total thickness of the Middle Triassic succession on the Frantz-Josef Land attains almost 1600 m (Gram-Bell Island) and 1950 m (Hayes Island).The Middle Triassic formation consists of dark-gray and black bituminous shale unites with TOC from 1 to 11 %. The average TOC is 1.6 – 2 %. The highest concentrations of organic matter are observed in the Middle Triassic Anisian shale in Svalbard Archipelago, where Middle Triassic shales from outcrops at the Spitsbergen Archipelago are very rich: (S1+S2), attaining 57 mg HC/g rock. The organic matter of Triassic source rocks is mainly humic in the eastern Barents Sea (type III) and mixed in the northern and western Barents (type II and III).

The Lower and Middle Jurassic source rocks are represented by lacustrine and shallow marine shales with good source potential and proven productivity occurred in the Shtokman field. They consists of dark-gray claystones and light-gray coarse-grained siltstones. The mica grains and inclusions of the vegetative detritus are seen at the boundaries of the interlayers. Rock Eval kinetic parameters show the ТОС of the humic-sapropelic type II-II varying within 0.5 - 3.1% (Fig. 8). The Upper Jurassic strata are very rich, but not matured enough in the Barents Sea basins. They consist of dark colored, black shales with high content of organic matter. The Upper Jurassic source rocks have been studied from the Spitsbergen Archipelago, Shtokman and Snohvit gas condensate fields, where core samples contain organic matted of mixed humic-sapropelic type II and II-III with TОС from 1.4 to 28.2 %. The Hydrogen index (HI) varies from 83 to 279 mg HC/g TOC. The source rock samples from the Spitsbergen Archipelago have TOC=2.5-6%. Their HI is 31-158 mg

HC/g TOC. The Upper Jurassic source rock samples from the Snohvit field have TOC -1.5-28% and HI - 61-171 mg HC/g ТОС. The samples from the Shtokman field contain TOC - 8-9.5% and their HI - 360-370 mg HC/g TOC – the highest values for all studied Upper Jurassic samples.

The maturity of the Triassic source rocks is very different, because the depth of the Triassic succession varies from 2-3 km up to 7 km.. In the deepest parts of the Barents Sea these source rocks have already over-matured and passed the oil and gas window. In the other area they can be a good oil and gas source rocks. Based on the available rock sample from Spitsbergen and the Frantz-Josef Land Archipelagos and core data from Barents Sea wells the Triassic strata are matured quite enough to generate hydrocarbons. Most of the core samples of the Triassic source rocks are considered representative of the oil window (Тmax=430-445оС) (Fig. 7). Some samples from the south-west of the Russian Barnets Sea, in the Severo-Kildinskaya -80 well (1410 – 1480 m interval) show immature Middle Triassic organic matter. The migration hydrocarbon index (S1) is low (0.09 – 0.14 mg HC/g rock). The residual generation potential varies from 0.42 to 1.52 mg HC/g rock. Probably the Middle Triassic source rocks had been supplying gas for the huge gas pools in Triassic and Jurassic reservoirs of the Barents Sea.

The maturation of the Lower –Middle Jurassic rocks, defined by Tmax=431˚C, corresponds to the initial stage of the main oil and gas window (Ro = 0.4-0.5 %) (Fig.8). These source rocks have a high generation potential (S1+S2), which varies from 1,54 to 8.96 mg HC/g rock) (Table 2). Upper Jurassic source rocks can be divided into two groups. Group I includes immature source rocks, which samples have low Тmах and high HI. These samples were taken from the Shtokman field and from Severo-Murmanskaya and Arkticheskaya wells. Their average Тmax is 414-417 oC and HI is 362-368. These core samples are considered representative of the thermally immature organic rich source rocks with organic matter of the mixed sapropelic-humic type II. Group II corresponds to poor mature source rocks of the mixed sapropelic-humic type II-III, which are in the beginning of oil window. This group includes samples from Spitsbergen and Snohvit field (Norwegian sector) with the average Тmax and HI are 426 - 473oC and 63 -171 mg HC/g TOC respectively.

Sample No. Rock Age Tmax S1 S2 S3 S1+S

2 PI S2/S3 RC TOC HI OI

1 Claystone J2a1 441 0.18 3.29 0.96 3.47 0.05 3.43 1.78 2.11 156 45

2 Claystone J2a1 443 0.1 1.44 1.19 1.54 0.07 1.21 1.15 1.33 108 89

3 Claystone J2 435 0.08 2.02 0.39 2.1 0.04 5.18 1.14 1.33 152 29

4 Claystone J3-K1

(K1) 427 0.01 0.18 0.18 0.19 0.07 1.00 0.56 0.59 31 31

5 siltsones J2 432 0.25 2.49 0.54 2.74 0.09 4.61 1.24 1.5 166 36

6

claystones and

siltstonesJ1

3

431 0.58 8.38 0.44 8.96 0.07 19.05 2.31 3.08 272 14

Table 2. Rock-Eval data of the Lower-Middle Jurassic samples from the Barents Sea

Fig. 7 Modified Van-Krevelen diagram for the Barents sea Triassic deposits

Fig. 8 Modified Van-Krevelen diagram for the Barents sea Jurassic deposits

The processes of HC generation started in the Barents sea at the beginning of Early Triassic within the deepest parts of the basin, where Palaeozoic source rocks, analogies to the Timan-Pechora basin’s source rocks could generate hydrocarbons. They had almost realized their potential by the Middle Triassic time. Late Triassic is characterized by intense vertical and lateral migration of hydrocarbons (Fig. 9). Hydrocarbons were moving form the deepest parts of the basin to its flanks. Triassic source rocks started generating HC 120 – 100 Ma, in Early Cretaceous. By the Late Cretaceous Triassic source rocks had realized its potential to 90 % in the central part of the South Barents depression. On the flanks these source rocks have just entered the oil window, and their degree of catagenetic conversion has not exceeded 40-50% by the end of Cretaceous period.

Fig. 9. Oil-and-gas kitchen in the South Barents Sea and hydrocarbons migration at the present-day phase.

3. Yamal-South-Kara Petroleum Systems

In the northern West Siberia Jurassic and Cretaceous shales and coaly formations thought to have sourced most known petroleum there. The Palaeozoic and Triassic source rocks were poorly studied. Individual geochemical studies of terrigenous-carbonates from Palaeozoic samples on the Yamal Peninsula showed TOC variations from 0.1-0.2% to 2.6-3.0%. TOC content in the Palaeozoic terrigenous rocks are 0.8-3.5%. The Triassic source rocks strata (Tampey series) are penetrated by a few wells mainly in the north of the West Siberian basin. The most detailed data on the Triassic source rocks were obtained in the Tyumenskaya superdeep well (SG-6). The TOC content in some organic-rich shaly intervals varies from 3 to 5%. However, in most of the area the Palaeozoic and Triassic source rocks occur at great depths and over-matured. Its Rock-Eval index (S1+S2) varies from 0.13 to 0.44 mg HC/g of the rock and НI is 2-34 mg HC/g of TOC.

Lower-Middle Jurassic and Upper Jurassic-Lower Cretaceous source rocks supply the most oil and gas for the northern West Siberia fields. Upper Cretaceous source rocks generate predominantly gas. The source rocks in the Lower-Middle Jurassic strata are shaly-coaly and coaly layers of the Tyumen formation and shales of the Togur formation. They are organic-rich with the average TOC of the mixed type II-III from 1 to 5%; (fig. 10). The Tyumen and Togur formations are thermally mature for oil generation in the most parts of the West Siberia basin. The vitrinite reflectance (Ro %) reached 0.8%. In the Yamal and Gidan peninsular their analogues are the shales and coaly formations of the Bolshekhetskaya stratigraphic unit. The average TOC content in the Lower-Middle Jurassic strata is 1.92%, increasing towards the Kara Sea offshore area. The source rocks contain the organic matter of humic type III). Though, in some samples the organic matter of Type III-II or II is marked. The hydrogen index (HI) varies from 200 to 285 mg HC/g of TOC; Tmax - (445-460о С) correspond to the middle and final stages of the oil window.

The Upper Jurassic marine shales are the principle source rocks for most of the oil and probably of the gas in the West Siberia basin. They comprise organic rich shales of Volgian to Berriassian age (Bazhenov formation). The sediments were deposited in a proximately deep-water marine basin during the most extensive Late Jurassic transgression. The organic matter in the Bazhenov Formation is derived from plankton and bacteria, so the kerogen is of type II (fig. 11). The average TOC content in the formation is 5.1%, increasing in the southern direction to 9-11% (Middle Ob area). Over the most part of the West Siberian basin maturation of the Upper Jurassic source rocks corresponds to the peak of the oil window. The highest maturity is found in the Middle Ob area (Ro = 0.7 – 1.1 %) and in the north of the Nadym-Pur petroleum region (Ro > 1.1 %). Towards the marginal areas of the basin the maturation of the Upper Jurassic source rocks decreases. As the maturity increases, HI decreases from 400-500 mg HC/g of TOC at the initial stage of the oil window to 100-200 mg HC/g of TOC at its final stage. In the northern areas of the basin (Yamal Peninsula), the TOC content in Bazhenov formation increases toward the Kara Sea from 0.9% (Neitinskoye field) to more than 4.0% (Kharasaveyskoye field); HI varies from 230 to 270 mg HC/g of TOC, Tmax=440-460 оС.

Fig. 10 Modified Van-Krevelen diagram for the Yamal peninsula Lower-Middle Jurassic deposits

Fig. 11 Modified Van-Krevelen diagram for the Yamal peninsula Upper Jurassic deposits

The marine Neocomian Achimovskaya and Tanopchinskaya formations are the source rocks for most of the gas fields in the northern Yamal and probably Kara Sea. The source rocks are represented by shales and coaly rocks, with average TOC is about 4-5%. The highest TOC values are measured in shales of the Kharasaveyskoye field (5.6%), the lowest – in the Novoportovskoye field (1.04%). Neocomian source rocks contain humic organic matter of type III and their maturation corresponds to initial stage of the oil window (Тmax = 432-456оС) (Fig. 12).

Albian-Cenomanian strata are productive mainly in the northern areas of the basin, where the giant gas pools associated with them. This interval of the section correlates with the Pokurskaya formation in the central part of the West Siberia basin and with Maressalinskaya formation – in the Yamal-Kara and Gydan region. Both formations are represented by sub-coal-bearing, continental and nearshore-marine deposits. Maximum concentrations of TOC (up to 6.4%) are located in the northern part of the Yamal Peninsula. The organic matter type is clearly established as type III. The Albian-Cenomanian source rocks in the northern areas of the West Siberia are thermally matured for initial stage of oil generation.

Fig. 12. Modified Van-Krevelen diagram for the Yamal peninsula Lower Cretaceous deposits

The main source rocks of the northern West Siberia and their maturation have been used for basin modeling of the offshore Yamal and Gidan peninsulas and adjacent parts of the Kara Sea area. The Jurassic oil and gas source rocks in the Kara Sea offshore area have attained the oil window by the end of the Aptian age (K 1a – 112 Ma). By the end of the Eocene age, the Lower Cretaceous source rocks were also involved into the oil window (Fig. 13). The Albian-Cenomanian source rocks are entering the oil window only at present time; this is shown in Fig. 13. The Lower and Middle Jurassic source rocks entered the oil window in the Hauterivian time (135-130 mln. years ago); at present, they are in the gas-generating stage and apparently are not very interesting as the oil sources. The Upper Jurassic source rocks entered the oil window in the end of the Aptian time (112 mln. years ago); at present, they are in the final oil-generating stage. The Cretaceous source rocks are most prospective in the Kara Sea; they are in the beginning (Albian-Cenomanian rocks) and in the peak (Neocomian rocks) of the oil window, and are the main hydrocarbons’ sources in the Kara - northern Yamal region (Fig.14).

Fig. 13. Evolution of the organic matter maturation (based on the basin modeling results)

Fig. 14. Oil-and-gas kitchen in the South Kara Sea and hydrocarbons migration at the present-day phase.

The Lower and Middle Jurassic source rocks at present have realized their generating potential practically in full everywhere along the studied profile. The Upper Jurassic source rocks have not realized their potential yet in the uplifted areas, like megaswells and other large uplifts in the Kara Sea. Neocomian and Albian-Cenomanian strata have realized just a small pat of their potential, and are the most promising strata to generate new hydrocarbons.

3. Yenisey-Khatanga Basin petroleum system

The Yenisey-Khatanga basin contains small oil and gas fields in Mesozoic and Palaeozoic successions. Mesozoic petroleum systems are associated with the centrsal part of the basin, while the Palaeozoic and Riphean petroleum systems are productive in its flanks. In this study we have evaluated core samples of the Mesozoic source rocks from the wells of the central part of the basin and the Palaeozoic source rocks’ samples from the eastern flank of the Yenisey-Khatanga basin, the Anabara-Khatanga saddle.

The only sample of the Riphean age is represented by a black mudstone with maximum content of TOC - 6.02%. The sample was taken in the Khorudalakhskaya-1 well from 2.8 km depth. The Riphean source rocks are thermally over-matured. Their Tma is 500 оС. The present-day value of the hydrogen index is so low (18 mg HC/g Corg) and their generation potential is 1.71 mg HC/g Corg; the rock belongs to lean source rocks strata. Palaeozoic core samples contain organic matter with TOC from 0.01 – 5.6 %. (Fig. 15).The Cambrian source rocks are represented by mudstones, shales and limestones. They comprise organic matter with TOC from 0.21 to 3.14%, but prevailing values are 0.2-0.3%. The highest hydrogen index for non-matured samples is 38 mg HC/g Corg. Generation potential values (S1+S2) vary from 0.04 to 1.48 mg HC/g Corg with prevailing values <0.2 mg HC/g Corg. The only examined sample of the Carboniferous age was taken in Yuzhno-Suolemskaya-10 well at the depth of 2.4 km. It represents gray pelitomorphic limestone with TOC 0.04%. Its calculated Tmax is 302 оС means that this sample is poorly matured, it has not yet entered the main oil window. It is also confirmed by relatively high hydrogen index HI = 150 mg HC/g Corg; this indicates that sapropelic component is more important in the initial organic matter composition, than it is in the organic substance of Permian strata. Generation potential of this sample is extremely low and is equal to 0.12 mg HC/g Corg.

Fig. 15 Modified Van-Krevelen diagram for the Yenisey-Khatanga Palaeozoic deposits

The Lower Permian 22 core samples of mudstones contain organic matter with TOC from 0.01% to 5.1%. The Lower Permian potential source rocks have been penetrated by wells at the depth from 1140 m in Gurimisskaya-1 well to 3000 m in Vostochnaya-1 well (Lower Kozhevnikovskaya Formation). Maturation of the core samples from the different depth varies a lot. Their calculated Tmax varies from 302 to 534 оС., but the most of the samples are within 435-460 оС interval, which corresponds to the main oil window. Generation potential values (S1+S2) vary from 0.23 to 7.78 mg HC/g Corg. Most of the examined samples have generation potential <2 mg HC/g Corg.

The Upper Permian strata are represented by a single sample of the Misailapskaya formation from Volochanskaya-1 well. Its organic carbon content is equal to 1.93%. In general, the sample is similar to the Lower Permian strata, described before. Currently the Lower Permian strata are in the oil window (Tmax = 444 оС). Present-day hydrogen index HI = 55 mg HC/g Corg, and its value, converted to the beginning of catagenesis, is equal to 110-120; this permits to assume predominantly humus origin of the initial organic matter. Generation potential value is equal to 1.17 mg HC/g Corg. Rocks refer to the category of lean gas source strata. Qualitative type of the organic substance from the Palaeozoic strata, determined using the pyrolytic analysis data, is predominantly humus or mixed sapropelic-humus. The Lower Permian strata have the best quality among Palaeozoic formations.

The Middle Jurassic strata are the best in terms of the oil generating aspects among the Mesozoic formations

(Logatskaya-361, Zapadno-Kubalakskaya-359 wells). The studied Palaeozoic and Mesozoic strata occur at various depths; due to that their organic matter is in different maturation rates stages – from non-matured Tmax=302 оС to strongly-matured Tmax=534оС. Present-day depths of the strata occurrence do not reflect the maturation rate of the organic matter; this is associated with various intensity of erosion during certain stages of the Mesozoic – Quaternary history of the basin development.

Baisn modeling of hydrocarbon generation and migration has been done for the profile, crossing the eastern flank of the Yenisey-Khatanga salt basin, Anabar-Khatanga saddle. Lower Permian source rocks started to generate hydrocarbons in the Early Triassic time within the central parts of the basin; generating of hydrocarbons in the marginal parts of the basin started later – in the Middle Triassic time. By the end of Triassic period, all Palaeozoic source rocks were in the oil window. At present day the most part of the formation is in the oil generating stage (Ro = 0.85-1.15%), and in the central part of its salt basin – in its final stage or in the early stage of gas window (Ro = 1.15 – 2%) (Fig. 16).

Fig. 16 .Present day oil window position.

In the central part of the salt basin, Upper Devonian –Lower Carboniferous and Cambrian oil source rocks attained oil window by Early and Late Permian time. Upper Riphean oil source rocks entered main gas window at the end of Carboniferous period. The most ancient Middle Riphean oil source rocks started to generate hydrocarbons yet in Silurian time. At present, Riphean strata are capable to generate gas only in the marginal parts (Ro = 1.15 – 2%), while their potential is already completely realized in the central part of the saddle. In the north-eastern sector of the profile besides oil source rocks of the Lower Kozhevnikovskaya formation, the Upper Devonian oil source rocks probably are in the final oil-generating stage and can also supply liquid hydrocarbons (fig. 17). The transformation ratio of the organic matter is pretty high. The potential of the Lower Kozhevnikovskaya source rocks grows from the first percents in the area of the Northern Siberian monocline to 90% in the central part of the saddle (Kharatamusskaya Depression).

Due to the absence of regional caprocks and reservoir properties of the given lithotypes, hydrocarbons are distributed over the whole sedimentary stratum according to the modeling results, but the saturation rate does not exceed several first percents. The most interesting are hydrocarbons accumulations in the Lower Devonian sub-salt complex’s carbonaceous-halogen stratum, in the Lower Carboniferous carbonates, and in the Lower Permian terrigene complex, where saturation is 50% and more. All reservoirs are confined mainly to anticline traps. Fault-bounded reservoirs can occur in the area of the salt dome. The vertical migration of hydrocarbon fluids dominates mainly in the central part of the anticline; and by contrast, their lateral migration dominates in the marginal parts (from the deepest central area of the saddle) (fig. 18).

Fig. 17 Evolution of the organic matter maturation based on the basin modeling results (Location of «wells» see on fig. 15)

Based on the modeling the main possible gas accumulations are concentrated deeply in the sub-salt complex, located in the central part of the salt basin. In zones, where hydrocarbons can migrate upwards the section (mainly in the zones of fault tectonics) they refill potential pools of the above-salt complex. The Lower Kozhevnikovskaya formation and the deeper Upper Devonian – Lower Carboniferous siliceous-carbonate strata are the main suppliers of predominantly oil together with gaseous hydrocarbons in the above-salt complex of the central part of the trough. Possible accumulations of hydrocarbons can be expected in the anticline structures; most interesting of them are the uplifts of Belogoro-Tigyanskaya zone and arched uplift, separating the salt basin of the Anabar-Khatanga saddle from the pre-Taimyr fold-thrusted zone. Besides that, fault-bounded traps close to salt stocks can have high oil potential (Nordvik field). In the south-western part of the studied area (the slope of the Anabar anteclise), the potential hydrocarbon leads will be similar to petroleum plays of the Eastern Siberia, where the main source rocks are located in the Riphean complex and in the Middle Cambrian formations.

Fig. 18. The direction of migration.

Conclusions

Although a wide variety of potential source rocks, ranging in age from Proterozoic to Mesozoic, have been identified in the Western Russian Arctic basins, most of the petroleum discovered – the proven petroleum systems - is derived from a few narrowly defined stratigraphic intervals: Devonian, Triassic and, especially, Jurassic are the most important. Palaeozoic petroleum systems have been explored mainly in the Timan-Pechora and Yenisey-Khatanga basins. The Mesozoic petroleum system are very productive in the Kara-Yamal and Barents Sea basins where they supply a huge volume of hydrocarbons. Hydrocarbon generation started long before the present basins’ structural configuration formed, and oil and gas kitchens were associated mainly with extensional parts of the basins. Later phases of rifting and extension affected both the ancient oil and gas kitchens and the younger ones. Inversion caused trapping and affected fluid migration, mixing the petroleum systems.

AcknowledgementsWe would like to thank the Russian-Norwegian collaboration for supporting this work during a period of more

than 5 years. Statoil ASA is acknowledged for funding the Moscow State University and Tromso University cooperation. Thanks Sevmorgeo, SMNG, MAGE and Yuzhmorgeologiya for being allowed to use regional seismic profiles, GAZPROM-VNIIGAZ for core material for this evaluation. We offer our sincere thanks to Anthony Spencer, Erik Henriksen and John K Milne for valuable input in our work.

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