The Timan-Pechora Basin Province of Northwest Arctic Russia:  Domanik – Paleozoic Total Petroleum System

Sandra J. Lindquist

Unfortunately, spud or completion dates are not available for 62% of the well population, but Figure 4 illustrates from the known population the significant amount of drilling that began in the mid 1940s (most early wells classified as outposts) and has continued to present. In recent years, the numbers of wells categorized as new field wildcats and exploratory wells have increased relative to those classified as outposts and development wells.


Geographic and Stratigraphic Location
Oil seeps and tar sands are common in the Timan-Pechora Basin, even within Precambrian (Riphean) rocks of the Timan Ridge (Sobornov and Yakovlev, 1996). Petroconsultants (1996) lists 257 fields within the province (Table 1), but 31 fields have no production or reserve data published. For the Timan-Pechora Basin Province, known ultimate recoverable reserves of nearly 20 BBOE are distributed as 66% oil, 30% gas and 4% condensate. Five fields are significantly distant from the mainland (Figure 1 and Figure 5). The two northernmost fields on Kolguyev Island are likely associated with a different petroleum system in the offshore South Barents Sea Basin (Table 1).

Foredeep basins on the east side of the Timan-Pechora Basin Province are gas dominated, as are both the southwesternmost area along the Timan Ridge and the northern coastal region of the Shapkino-Yuryakha and Lay Swells (northern part of Pechora-Kolva Aulacogen, Figure 1). The southern foredeep (Upper Pechora Trough) contains the province’s largest field – Vuktyl, with nearly 50% of the province’s known recoverable gas – but northeastern foredeep basins (Kosyu-Rogov and Korotaikha) are sparsely explored. The northern Izhma-Pechora Depression contains few fields despite having approximately 100 well penetrations. Offshore Timan-Pechora has both oil and gas fields, and fewer than a dozen offshore exploratory wells have been drilled away from islands.

Hydrocarbons are trapped in Ordovician through Triassic reservoir rocks at 200 to 4500 meter depths (Kiryukhina, 1995). Scenarios for multi-stage hydrocarbon migrations and remigrations are possible, particularly in the Ural foredeeps, because of regionally variable burial history and the province’s repeated tectonism (Bogatsky and Pankratov, 1993).  Most oil is reservoired in tectonically stable areas with stratigraphic traps (Bogatsky and Pankratov, 1993). Conversely, most gas (alone or with oil) is in active tectonic areas where more recent gas charging could have occurred.

Late Cenozoic Uralian uplift probably resulted in cooling and decompression of formation fluids, allowing gas to come out of solution and accumulate in traps (Sobornov and Rostovshchikov, 1996).

Geochemistry of Hydrocarbons(Continued on Next Page)
Timan-Pechora hydrocarbons range from high gravity, low sulfur and low resin oils with paraffin bases to low gravity, high sulfur and high viscosity oils of dominantly aromatic-napthenic compositions (Kiryukhina, 1995). Sulfur content is related to the presence of evaporites, and Kosyu-Rogov (foredeep basin) gases contain H2S. Commonly, oils in stratigraphically older reservoirs have lower density, fewer asphaltenes and more residual components than those in stratigraphically younger reservoirs (Meyerhoff, 1980). Biodegradation occurs in shallow accumulations. Province-wide, oil gravity ranges from 11° -62° API and condensate gravity from 45° -79° API (Petroconsultants, 1996). From the same reservoir and test data, mean and median API gravity is 35° , and GOR has a mean of 393 cfg/bo and a median of 289 cfg/bo (range 7 to 1500 cfg/bo). The higher end of the GOR range is probably the more appropriate characterization for this province.

Oil attributed to Upper Devonian ("Domanik") source rock has the following characteristics (Abrams and others, 1999):

  • Pristane/phytane >1 and <2
  • Smooth distribution of n-alkanes, with a maximum at C11 - C15
  • Saturates/aromatics < or = 1
  • Abundant C28+ 
  • d13C saturates and aromatics @ -29
  • Sulfur content = 1 - 4.5 wt %
  • Normal to low tricyclics with C24 > C26
  • C29 hopanes < or = C30 hopanes
  • Generated at conditions less than peak oil for typical type II kerogens

Hydrocarbons from other source rocks have geochemical distinctions.Ordovician- to Silurian-sourced oils have pristane/phytane = 1; a sawtooth alkane distribution with a predominance up to C19, odd

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U. S. Geological Survey Open-File Report 99-50G