Exploration Opportunities

Taken in its entirety, the Scotian Basin is virtually unexplored given low number of exploration wells (127), their concentration in the productive Sable Subbasin, and the dominant focus on testing the rollover anticlinal plays. While this play has been successful, with five fields currently under production, exploration drilling has accentuated the fact that the timing of hydrocarbon generation and migration pathways is not fully understood. Nevertheless, a large number of undrilled prospects remain in the subbasin in addition to a number of existing discoveries that are undeveloped. The proximity of existing and planned production and transportation infrastructure to many of these prospects and undeveloped discoveries should improve their exploration and development attractiveness.

Several of the ExxonMobil Sable Offshore Energy Project (SOEP) fields - Alma and North Triumph - are now recognized as shelf margin delta complexes located at the top of the Lower Cretaceous Missisauga formation (Cummings and Arnott, 2005, Cummings et al., 2006). They have high in-place gas reserves (>500 Bcf) in excellent quality reservoirs with high flow rates, few to single gas-water contacts, are located in shallow water and at shallow drill depths (~3000 m) (CNSOPB, 2000). These complexes were not deliberately targeted during earlier exploration phases and there remain a number of undrilled structures adjacent to or near these fields. Detailed seismic and lithological studies should help refine the distribution and evolution of shelf margin deltas in the Sable Delta complex, and may reveal additional prospective play fairways.

A continuation of this shelf margin delta play may exist in the deeper water of the Scotian Slope. Paleoenvironmental interpretation of the recent deepwater wells indicates that their Cretaceous successions were deposited in an outer shelf to upper slope setting, and not in deep water as originally interpreted (Kidston et al., 2007). Potential thus exists for a significant number of deltas outboard this broad region. The interpreted high volumes of sands deposited in the Scotian Basin throughout the Jurassic and Cretaceous should be present in this region and encased in thick sealing marine shale that is also recognized as the regional source (Verrill Canyon formation).

Given the abundance of coarse clastics on the outer shelf, it is expected that potential coarse grain, deep water depositional facies exist in the deeper parts of the Scotian Slope. In recent wells, where ever adequate reservoir sands were present they were gas-charged, confirming an active petroleum system exists on the slope. However, the paleogeography of turbidite systems remains poorly defined and hence the distribution of turbidite reservoirs is poorly understood. The search for such reservoirs should be directed towards the large, salt-related anticlinal features on the slope in both Cretaceous and Jurassic successions. Detailed seismic mapping of progradational sequences and linkages to canyon systems should reveal the likely location of coarser grain turbidite deposits. Information from recent wells, now public, can be used to define lithological attributes and better calibrate seismic datasets, thus improving seismic stratigraphic interpretations. In addition, improvements in seismic processing will provide better imaging below salt successions that to date have only been tested by one well. The same holds true for Tertiary slope fans and channels that have only been targeted by two wells. Many other deep water plays have yet to be tested. For example, numerous Jurassic through Tertiary minibasins exist along the 850 km length of the Scotian Margin with excellent potential for traps in sandy slope fans and submarine canyons. Other untested plays include turtle structures, salt diapir flanks and crests, salt canopy supra-salt stratigraphic and structural traps and fold-and-thrust belts at the leading-edge of the salt (Kidston et al., 2002).

The recent discovery and planned development of 1.4 Tcf gas (OGIP) in the Late Jurassic Abenaki carbonate bank margin also holds great promise for future discoveries. Slightly sour dry gas (0.2 % / 2000 ppm) is concentrated in a combined structural and stratigraphic trap within dolomitized, leached and fractured reef margin and reef foreslope facies with highly vuggy to cavernous porosity. Only a handful of wells have tested this play that extends along the edge of the Scotian Shelf for about 650 km to the United States border, and continues along to Florida. A similar succession exists along the edge of the Northwest African margin that remains virtually unexplored. Related plays include low stand by-pass sands (e.g. turbidites), dolomitized oolitic shoals, reef talus / debris aprons, and backreef patch reefs and shoals (Kidston et al., 2005). Several of these plays have been tested adjacent to the Deep Panuke field confirming the play concepts and in several cases with gas shows.

Stratigraphic plays in the Sable Subbasin have yet to be tested. For example, the large A-B Sand reservoir in the Thebaud field is thought to pinch-out far to the northwest of the field adjacent to the Jurassic carbonate bank margin near the Deep Panuke field. These Early Cretaceous fluvial-marine / strandplain sands of the Missisauga formation have good reservoir characteristics, are over-pressured and produce at high flow rates (CNSOPB, 2000). Similar plays may exist elsewhere in this subbasin within known producing Jurassic and Cretaceous intervals.

Several subbasins in the Scotian margin have not been explored for over 30 years. These areas were targeted during the initial exploration cycle to test simpler and easily defined play concepts such as drape over basement structures and salt diapirs. Acquisition of new seismic data coupled with new ideas and play concepts may prove fruitful in long overlooked depocentres like the Orpheus, Mohican and Naskapi Grabens, and Banquereau, Fundy, Sydney and Maritimes Basins. New knowledge and data should illuminate new plays and better define older ones including subsalt plays, salt related structures, anticlinal features, basement fault structures and stratigraphic traps.

References

Canada-Nova Scotia Offshore Petroleum Board, 2000
Technical Summaries of Scotian Shelf Significant and Commercial Discoveries,
Canada-Nova Scotia Offshore Petroleum Board , Halifax, 257p.

Cummings, D.C., and Arnott, R.W.C., 2005
Growth-faulted shelf-margin deltas: a new (but old) play type, offshore Nova Scotia.
Bulletin of Canadian Petroleum Geology, vol.53, no.3 (Sept. 2005), p.211-236.

Cummings, D.C., Hart, B.S., and Arnott, R.W.C., 2006
Sedimentology and stratigraphy of a thick, areally extensive fluvial-marine transition, Missisauga Formation, offshore Nova Scotia and its correlation with shelf margin and slope strata.
Bulletin of Canadian Petroleum Geology, vol.54, no.2 (June 2006), p.152-174.

Kidston, A.G., Brown, D.E., Smith B.M. and Altheim, B., 2005
The Upper Jurassic Abenaki Formation Offshore Nova Scotia: A Seismic and Geologic Perspective.
Canada-Nova Scotia Offshore Petroleum Board, Halifax, 165p.

Kidston, A.G., Brown, D.E., Smith B.M. and Altheim, B., 2002
Hydrocarbon Potential of the Deep-Water Scotian Slope.
Canada-Nova Scotia Offshore Petroleum Board, Halifax, 111p.

Kidston, A.G., Smith, B., Brown, D.E., Makrides, C. and Altheim, B., 2007
Nova Scotia Deep Water Offshore Post-Drill Analysis – 1982-2004.
Canada-Nova Scotia Offshore Petroleum Board, Halifax, Nova Scotia, 181p