U.S. DEPARTMENT OF THE INTERIOR
U.S. GEOLOGICAL SURVEY
The Timan-Pechora Basin Province of Northwest Arctic Russia: Domanik – Paleozoic Total Petroleum System
Carboniferous reservoirs are limited in reserve-volume importance, but trend diagonally across the province from the southern Izhma-Pechora Depression and Omra Step region northeastward to the coastline at the Pechora-Kolva Aulacogen and Adva-Varandey Zone. Additional Carboniferous reservoirs have been discovered in the Kosyu-Rogov and Korotaikha foredeeps.
Lower Permian reservoirs delineate the largest area of any reservoir rock. They cover an onshore swath similar to the Carboniferous – from the southernmost tip of the province (mostly sandstone) to the most mountain-proximal foredeeps of Kosyu-Rogov and Korotaikha (carbonates) to the offshore (sandstone to the west, carbonate to the east). Kolguyev Island apparently marked the northeasternmost corner of the Paleozoic Timan-Pechora platform (Preobrazhenskaya and others, 1998).
Youngest Upper Permian and Triassic reservoirs (all sandstone and averaging 7 to 9 meters net thickness) are located on anticlines of the northern Pechora-Kolva Aulacogen, the northern Sorokin Swell and offshore on Kolguyev Island (Figure 1). More production approximately overlies the Middle Devonian fairway – along the western-Uralian foredeep margin from just north of the Omra Step northeastward to the foredeep junction with the Pechora-Kolva Aulacogen. Upper Permian and Triassic sandstone genesis ranges from fluvial-alluvial to marine in a SE-to-NW transect (Stupakova, 1992; Oknova, 1993; Kuranova and others, 1998). The entire north-northeastern part of the province – including the Pechora-Kolva Aulacogen, the Khoreyver Depression, the Korotaikha Trough, and the offshore extensions – could be prospective for Triassic stratigraphic and combination traps (Dedeev and others, 1994).
Timan-Pechora siliciclastic reservoirs average 16% porosity and 154 md permeability, and carbonate reservoirs average 13% porosity and 208 md permeability (Petroconsultants, 1996) (Table 2).
For sandstones, average reservoir porosities range from a low of 11.5 % in the Lower Paleozoic reservoirs to a high of 22.5% in Triassic counterparts. The range of maximum sandstone reservoir porosity is 12% (Lower Paleozoic reservoirs) to 28% (Triassic reservoirs). For carbonates, average reservoir porosities range from a low of
9 % in the Lower Paleozoic reservoirs to a high of 15.8% in Lower Carboniferous counterparts. The range of maximum carbonate reservoir porosity is 10% (Lower Paleozoic carbonates) to 28% (Lower Permian reef reservoirs).
For sandstones, average reservoir permeabilities range from a low of 15 md in the Lower Paleozoic reservoirs to a high of 372 md in Upper Devonian counterparts. The range of maximum sandstone reservoir permeability is 15 md (Lower Paleozoic reservoirs) to 4000 md (Upper Devonian reservoirs). For carbonates, average reservoir permeabilities range from a low of 63 md to a high of 930 md, both in Lower Paleozoic reservoirs. The range of maximum carbonate reservoir permeability is 80 md (Lower Paleozoic carbonates) to 1200 md (Upper Devonian reef reservoirs).
Hercynian orogenic siliciclastics are lithic-rich; thus,
Triassic sandstones have somewhat lower average (75 md) and maximum (340
md) reservoir permeabilities than Paleozoic sandstones. Paleozoic carbonate
reef reservoirs contain 53% of known ultimate recoverable reserves (Table
2). Upper Devonian shelf-edge reef fronts are commonly dolomitized,
and best reservoir properties are located near the slope break. Kuznetsov
(1997) provides the example of Pashshor field where net/gross pay ratios
vary from 67-90% in reef-front facies to 13-39% in back-reef facies. In
contrast, Permian reefs have best primary porosity preserved in stacked
lenticular zones at the reef centers.