Hydrocarbon exploration offshore Nova Scotia began in 1959 and has seen three distinct cycles of activity since that time. A total of 207 wells have been drilled with 127 of these being exploration wells. To date, twenty-three significant and eight commercial hydrocarbon discoveries have been made offshore Nova Scotia with additional wells encountering numerous oil and gas shows. Total 2D and 3D seismic data acquired to date is 400,954 km and 29,512 km² respectively.

Exploration Cycle 1

The initial exploration cycle commenced with the awarding of exploration licences to Mobil Oil Canada for the Sable Island region on the shallow water Scotian Shelf in 1959. Subsequent magnetic and gravity surveys lead to the drilling of the first well on Sable Island in 1967 that confirmed the existence of a thick Tertiary- Mesozoic stratigraphic succession (Sable Delta) and had both gas and oil shows. Further licences were awarded to industry and the seismic coverage expanded to cover most of the margin. Between 1967 and 1978, 71 wells were drilled of which 57 were wildcats, and over 140,000 km of 2D seismic was acquired. A number of play concepts were tested, focusing on easily imaged salt structures using the successful Gulf of Mexico analogues, as well as drape over basement features and the carbonate bank margin. Of the 28 wells drilled in the salt structure play, three significant discoveries were made: Onondaga (Shell, 1969 - gas), Primrose (1972, Shell - oil & gas), and West Sable (Mobil, 1971 - oil & gas).

In 1972, Mobil tested a new play concept involving rollover anticlines associated with down-to-the-basin listric faults in the Sable Subbasin, thus-far the most prolific depocentre in the basin. The Thebaud P-84 well made a major gas discovery in the fluvial-deltaic sandstones of the Early Cretaceous Missisauga and Late Jurassic Mic Mac formations. The next year, another new play concept was tested, with the Mobil Cohasset D-42 well discovering light oil in a subtle drape structure overlying the Jurassic age Abenaki formation carbonate bank margin. At the end of this exploration cycle, additional exploration of the rollover anticline play resulted in significant gas discoveries at Citnalta and Intrepid.

Exploration Cycle 2

The second phase of exploration, 1979-1989, was sparked by the major gas discovery in 1979 at Venture by Mobil and Petro-Canada just east of Sable Island. This was a continuation of the rollover anticline play with the Venture D-23 well encountering multiple Cretaceous and Jurassic sandstone reservoirs with very high flow rates (e.g. 22.6 MMscf/d, 278 Bbls/d condensate). The Venture well discovered in a single well about the same total amount of gas that had been found to date in the Sable Subbasin.

Throughout the 1980s, Mobil, its partners and other companies delineated existing discoveries, drilled deeper to new gas-charged overpressured reservoirs (e.g., Venture, Thebaud), and drilled other anticlinal structures. New significant gas discoveries were made at South Venture, West Venture, Olympia, West Olympia, Arcadia and South Sable (Mobil), Glenelg, Alma, North Triumph, Uniacke, Eagle (Shell), Banquereau (Petro-Canada) and Chebucto (Husky-Bow Valley). Shell's light oil find in Early Cretaceous sands within a shallow drape structure at Panuke and Penobscot confirmed on-trend extensions of the earlier Mobil Cohasset discovery. Three deepwater wells were drilled to test possible Tertiary and Cretaceous turbidite fan plays but were unsuccessful. At the end of this second cycle (that was ended due to the precipitous fall in oil and gas prices), 54 wells were drilled and 15 significant discoveries confirmed.

Exploration Cycle 3

The third exploration cycle was a two-prong campaign with drilling on the shallow Scotian Shelf and deepwater Scotian Slope. The former was initiated by the announcements to develop the light oil discoveries at Cohasset and Panuke in late 1989 by LASMO (Cohasset-Panuke Project), and six gas fields in the Sable Island area in 1996 by Mobil, Shell and partners (Sable Offshore Energy Project). Several exploration wells were drilled by LASMO to test related and nearby structures, with more light oil found at Balmoral in 1991.

In 1998, PanCanadian (now EnCana), the new operator of the Cohasset-Panuke Project, drilled beneath Panuke and made a discovery of slightly sour gas in dolomitized and leached limestones of the Late Jurassic Abenaki reef margin. From 1999-2005 a number of follow-up wells were drilled to define the areal extent of the Deep Panuke gas field. In November 2006 EnCana filed the Deep Panuke Development Plan Application and stated that the field had 28.9 E9M3 (1027 Bcf) of mean in-place gas with mean recoverable reserves of 18.6 E9M3 (659 Bcf). Deep Panuke is scheduled to begin production in the fall of 2011. In 2001, EnCana drilled an exploration well (Queensland M-88) in the vicinity of Deep Panuke to test for by-passed sands in front of the carbonate bank and encountered a thin low quality gas sand which demonstrated the viability of this play concept. In 2001 EnCana also drilled Southampton A-25 to test for hydrocarbons in Missisauga sands trapped in a fault dependent closure. Southampton encountered reservoir quality sands but all zones were wet.

From 2000-2004 Mobil (now ExxonMobil) and partners initiated an exploration program to test a number of large rollover anticlinal structures in the vicinity of their Sable Gas Project. Two of these wells (Adamant N-97 & Cree I-34) encountered gas pay in a number of the fluvial deltaic sands of the Missisauga formations, however these zones were not deemed to be commercial. In 2001, Shell drilled Onondaga B-84 primarily to test for lower Missisauga deltaic sands trapped against the flank of a salt dome. In the B-84 primary target interval only a few poor quality gas bearing zones were encountered. Other explorers such as Canadian Superior unsuccessfully tested the Abenaki carbonate play at Marquis, but did encounter a few low to modest quality gas bearing zones at Mariner.

In the late 1990s, large areas of the deepwater Scotian Slope were licenced by industry, and following the acquisition of large volumes of regional 2D and 3D seismic data, six wells were drilled between 2002 and 2004. Four of the six deepwater wells were targeting large anticlinal features related to salt withdrawal. The initial well results were encouraging, with Marathon discovering a total of 27 m of net gas pay in Annapolis G-24, and Chevron encountering several thin, gas bearing, reservoir sands at Newburn. The other two wells targeting salt withdrawal features Balvenie (Imperial) and Crimson (Marathon) failed to encounter any significant gas bearing reservoir sands. EnCana drilled an interpreted Tertiary fan on the western portion of the Scotian Slope at Torbrook that in hindsight was determined to be a slump feature. They also drilled a large anticlinal subsalt feature at Weymouth. Both Torbrook and Weymouth failed to encounter any reservoir sands. For additional information on the results of deepwater drilling offshore Nova Scotia refer to the CNSOPB publication, Nova Scotia Deepwater Post-Drill Analysis 1982-2004, October, 2007. No exploration wells have been drilled offshore Nova Scotia since December 2005.

Exploration Overview

Taken in its entirety, the Scotian Basin is virtually unexplored given low number of exploration wells, their concentration in the Sable Subbasin, and the dominant focus 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 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 (>14 EPM3 / 500 Bcf) in excellent quality reservoirs with high flow rates, few gas-water contacts and are located in shallow water and at shallow drill depths (CNSOPB, 2000). These complexes have not been deliberately targeted and there are a number of undrilled structures 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 may also act as hydrocarbon source rocks.

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 filled with gas, confirming an active petroleum system exists on the slope. However, to this point the paleogeography of turbidite systems is 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. 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 drilled by two wells. Many other deep water plays have yet to be tested. For example, numerous Jurassic through Tertiary minibasins exist along the Scotian Margin with excellent potential for traps in sandy slope fans and submarine. Other untested plays include numerous 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 39.6 E9M3 (1.4 Tcf) of gas in the Late Jurassic Abenaki carbonate bank margin also holds great promise for future discoveries. Slightly sour dry gas 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. 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.

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.