Of the seven fields, the central area’s Shtokmanovskoye, Ludlovskoye and Ledovoye fields – accounting for 97% of the known, ultimately recoverable reserves – produce dry methane gas with a trace of condensate from Jurassic sandstones (fig. 3). Vertical migration paths are required to charge those multi-pay reservoir rocks. 

Shtokmanovskoye, with the most field reserves in the province, contains gas and condensate with 42° -52° API gravity, low sulfur (0.02%), a pristane/phytane ratio of 5 to 6, high C₂₄ tetracyclic terpanes compared with C₂₃-C₂₆ tricyclic terpanes, low C₂₇, and a small sterane/triterpane ratio (Ferriday and others, 1995). The hydrocarbons were generated from marine and terrigenous source rocks at about 0.9 %R_o. The younger and shallower Shtokmanov Callovian accumulation is more biodegraded than the older, deeper Bajocian accumulation, but it is slightly lighter isotopically (d ¹³C of –27.5 to –29 ppt Callovian vs. d ¹³C of –27 to –28 ppt Bajocian). Although this isotopic difference might not be significant, the observation led Ferriday and others (1995) to suggest that the younger and shallower Callovian accumulation contains a contribution from a carbonate source rock such as the Devonian Domanik. The maturation and migration history for such an occurrence would be difficult to explain, even if those source rocks were present.

Dry methane is also trapped in two southwestern fields within Triassic sandstone reservoirs, North Kildinskoye and Murmansk – accounting for 2.8% of the known, ultimately recoverable reserves. A greater lateral component of migration is required to charge those fields from the basin centers. The gas d ¹³C there is characterized by –34 to –37 ppt (Zakharov and Kulibakina, 1997).

Oil and wet gas occur in Triassic sandstones in two southeastern fields at Kolguyev Island near the Russian coastline. Peschanoozer and Tarkskoye fields contain 0.2% of the petroleum system’s known, ultimately recoverable reserves. The oil at Peschanoozer is characterized by approximately 42° API gravity and 2200-2500 cu ft/bbl GOR (Petroconsultants, 1996). The oil is low in sulfur and paraffin and has d ¹³C of –27 ppt; whereas, the gas has d ¹³C of –41 to –42 ppt (Zakharov and Kulibakina, 1997). Gas presence in these basin-margin fields requires a major lateral component of migration from the basin centers. It has been suggested that southward migrating thermal Triassic gas from the South Barents Basin has come into contact with and has dissolved oil from Paleozoic carbonate accumulations, then continued migrating laterally and vertically into Triassic reservoir rocks where the gas subsequently underwent phase differentiation (Clarke, 1999).

Additional gas shows occur in Triassic rocks of the Franz Josef Land islands and in an offshore well west of the Novaya Zemlya archipelago as far north as the southern part of the North Barents Basin (fig. 3). Gas shows also occur in Cretaceous reservoir rocks in wells on the Ludlov Saddle and in the southern North Barents Basin. Two oil shows also have been reported in Cretaceous rocks penetrated in the center of the South Barents Basin and in Paleozoic carbonate rocks somewhere along the west coast of southern Novaya Zemlya. The former could have been sourced from Jurassic shale source rocks at early-stage maturity to oil in the central basin areas and the latter sourced from remnant Devonian source rocks of the northeastern Timan-Pechora Basin Province.