Nova Scotia sees large resource on deepwater slope

The resource potential of the Scotian slope on a risked basis doubles the gas potential and triples the oil potential for Nova Scotia's portion of the overall Scotian basin.

Oct 16th, 2002

By OGJ editors

HOUSTON, Oct. 16 -- The resource potential of the Scotian slope on a risked basis doubles the gas potential and triples the oil potential for Nova Scotia's portion of the overall Scotian basin, according to the first independent resource assessment for the slope.

The undiscovered potential for the deepwater Scotian slope is estimated at 15 to 41 tcf of gas and 2 to 5 billion bbl of oil and condensate, said the Canada-Nova Scotia Offshore Petroleum Board, Halifax. The board published the report on its website (www.cnsopb.ns.ca).

The evaluation is based on the interpretation of 30,000 line km of 2D seismic data, in which 10 geologic markers were defined, and on comparisons with other deepwater hydrocarbon basins from the North and South Atlantic continental margins. The single greatest challenge was mapping the top and base of the ubiquitous mobile Triassic-Jurassic Argo salt.

The slope covers 80,000 sq km, about 65% of the area of the Scotian shelf. The slope extends 850 km from the US international border in the southwest to the Newfoundland boundary in the northeast. The slope width averages just under 100 km from the shelf edge in 200 m of water out to 4,000 m of water.

In "Hydrocarbon Potential of the Deep-Water Scotian Slope," the board concluded that the slope's predicted hydrocarbon richness per unit area places it within the range of other Canadian frontier basins such as the Labrador, Sverdrup, and Beaufort basins and below the richer proven basins in the Gulf of Mexico, offshore Brazil, and West Africa.

The highest rated conceptual plays are turbidite fans that lie on the floors and flanks of intersalt minibasins and upper slope turbidite fans in a structured regime associated with listric down-to-basin faults and salt features, the board said. The subsalt plays are rated lower, but this is partly a function of poorer seismic imaging of the subsalt strata in the data available to the assessors. The top six plays account for 86% of the total assessment area.

"If some or all of the 12 plays defined in the assessment are eventually proven, the slope region will have a much higher global ranking and approach that of offshore Brazil in hydrocarbon richness per unit area, but with a smaller total area," the board said.

Adding the risked 15 tcf of gas and 2 billion bbl of liquids estimated for the slope gives total shelf and slope potential of 33 tcf of gas and 3 billion bbl of liquids, the board noted. The figures include a risked mean 500 million bbl, or unrisked 1.2 billion bbl, of natural gas liquids.

The overall play adequacies vary from 16% to 64% and average 30% for the 12 conceptual plays identified.

Mean unrisked recoverable values for the 12 play types are:

-- Minibasin flanks, 10 tcf and 1.4 billion bbl.
-- Minibasin floors, 7 tcf and 762 million bbl.
-- Upper slope structures, 6 tcf and 877 million bbl.
-- Upper slope fans, 5 tcf and 330 million bbl.
-- Tertiary suprasalt, 4 tcf and 246 million bbl.
-- Deep structures, 2.5 tcf and 406 million bbl.
-- Salt flanks, 1.5 tcf and 238 million bbl.
-- Other canopy suprasalt, 1.5 tcf and 200 million bbl.
-- Canopy subsalt, 1.7 tcf and 28 million bbl.
-- Minibasin salt crests, 653 bcf and 90 million bbl.
-- Salt crests, 295 bcf and 43 million bbl.
-- Leading edge subsalt, 109 bcf and 31 million bbl.

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