NOVA SCOTIA CANADA: THE NEXT PLAY
Nova Scotia’s geological subbasins
Opportunities in Sable subbasin and deepwater
Offshore Nova Scotia has a significant amount of prospective offshore land available as a result of the completion of the third exploration cycle. These lands lie in the Sable, Abenaki and Shelburne Sub-basins, along the Abenaki Carbonate Bank, as well as the Deepwater Slope region, with prospective lands also available in the Orpheus Basin.
Two other basins, the late Triassic Fundy Basin and the Sydney Late Carboniferous (sag) Basins, contain petroleum opportunities but are less understood and therefore riskier than other offshore basins (only two wells in each).
The Scotian Basin comprises a series of connected depocentres initially formed during the rifting stage that preceded the breakup of the Pangea supercontinent, which started during the middle Triassic.
The basin’s history records the entire sequence of Atlantic-style rifting and formation on the wide offshore margins, with maximum sedimentation during the late Jurassic and Cretaceous. This entire basin is still at a relatively immature stage of exploration.
On the shallow shelf, situated on the Abenaki Carbonate Bank, PanCanadian (now EnCana) discovered the Deep Panuke field in 1998. The discovery was followed by five successful and two unsuccessful delineation wells. The successful wells all tested in excess of 50 MMcfd on DSTs, with net pay values ranging from 30 to 100 m.
On the deepwater slope, an undelineated Upper Cretaceous gas discovery was made by Marathon in 2002 with its Annapolis G-24 well in 1,700 m of water.
Details of the petroleum potential for four areas in the Scotian Basin follow, where large tracts of federal lands are available for nomination in fall 2007.
SABLE AND ABENAKI SUB-BASINS
The Sable and Abenaki Sub-basins have been the focus of much of the petroleum exploration over the past 40 years. To date, 23 gas and oil discoveries have been made in the offshore Nova Scotia region, mainly in these sub-basins near Sable Island.
Most of these discoveries involve rollover anticlinal structures associated with down-to-basin growth faults. Reservoirs are deep and overpressured in structures near Sable Island, with shallower and normally pressured reservoirs south of Sable Island along deltaic distal margins.
The overpressured reservoirs occur in sandstones of the Upper Jurassic Mic Mac and Lower Cretaceous Mississauga Formations. More than 115 m of net gas pay within 15 reservoirs have been recorded in one well in Venture field-the largest discovery to date.
Gas in the normally pressured sands is situated in the upper member of the Mississauga Formation. Gas also occurs in several additional reservoirs, including the Upper Cretaceous Wyandot (chalk) and Dawson Canyon (deltaic) Formations, and Middle Cretaceous Logan Canyon (deltaic) Formation, indicating further potential in many different play trends.
DEEPWATER SLOPE
Marathon Oil spudded a well in 1,674 m of water to test its Annapolis prospect. The B-24 well experienced a well control incident caused by an influx of gas believed to be from the shallow, Late Cretaceous Wyandot chalk. The well was abandoned and immediately repositioned. The Annapolis G-24 well was drilled to a planned TD and encountered about 30 m of net gas pay over several zones.
Marathon’s third exploration well, Crimson F-81, was drilled basinward, 9.5 km from the Annapolis discovery, but it was unsuccessful. Four more modern deepwater wells were drilled by three different operators to the west of the Annapolis discovery, but with little success so far. However, these wells demonstrated that there is an active petroleum system present. Successes in other deepwater passive margins around the world, including the Gulf of Mexico, offshore Brazil and West Central Africa, have spurred this exploration in the deepwater.
Industry has recognized that the Nova Scotia slope shares the same geological attributes as other successful exploration and producing Atlantic Margin deepwater regions. These attributes include production in the adjacent up-dip, shallow-water region (Scotian Shelf SOEP Project), a large, ancient, sand-rich delta system (Sable Delta), and a mobile salt substrate (Argo Fm.)
JURASSIC CARBONATE BANK
The Abenaki Carbonate Bank developed along the ancient rift margin hinge-line in the Middle Jurassic. The bank displays several margin profile types, ranging from steep escarpment to ramp-like. These attributes were used to divide it into three segments: Panuke, Acadia and Shelburne.
Seven play types have been identified across the Abenaki platform and margin and several have been tested, though in some cases by a single well. The Panuke Segment is the best understood of the three and is where a commercial oil project (the Cohasset-Panuke Project) and the Deep Panuke offshore gas development project are located.
This region is relatively undisturbed by erosion and faulting and is juxtaposed against the prolific Sable Delta, which contains all but two of the 23 discoveries to date, and is the site of the current offshore gas production. The Abenaki Bank margin was first drilled in 1973. The target had structural closure at depth; and although the Abenaki carbonates were wet, an up-hole oil discovery was made in overlying draped sands of the Cretaceous Logan Canyon Formation.
This discovery became the Cohasset-Panuke oil project that produced 44 MMbbl of light gravity 55º API crude from 1992-1999. These types of low-relief simple-closure fields are very attractive due to the high productivity of the sandstones, location in shallow water and in moderate metocean conditions.
Eight more wells were drilled in the 1970s along the Bank margin. The next well PanCanadian (EnCana) drilled was from the existing Panuke oil production platform, which resulted in the Deep Panuke gas discovery in 1998.
The Acadia Segment was penetrated by three wells drilled between 1970 and 1980. This region displays a more complex geological history than the Panuke segment, involving faulting, erosion and salt disruption. A noteworthy aspect of this segment is that all three wells drilled in this area (Bonnet, Albatross and Acadia) encountered degrees of lost circulation, indicating potentially good porosity/permeability zones.
SHELBURNE SUBBASIN
The Shelburne subbasin in the area of the Abenaki Bank margin was a major center of deposition in the southwestern portion of the Scotian Basin. This sub-basin saw rapid deposition throughout the Jurassic, and lesser infill during the Cretaceous and Tertiary, resulting in a cumulative thicknesses of 12 km.
The Abenaki Carbonate of the Shelburne Segment is unexplored, with no wells and only some older regional seismic coverage. Seismic shows a faulted, rimmed carbonate platform with a steeply dipping foreslope. To the northeast, seismic shows the carbonate margin buried by a thick Cretaceous section, with listric down-to-basin faults very close to the bank edge and foreslope.
Thick salts are also present in the deepwater portion of this sub-basin. The 12 plays identified by CNSOPB’s 2002 Deep Water Scotian Slope Resource Assessment are associated with the salt and provide many exploration opportunities. A continuous 3D seismic dataset will be necessary to fully evaluate these opportunities prior to drilling a well.
ORPHEUS BASIN
The Orpheus Basin forms a structural trough on the northern Scotian Shelf, widening and plunging eastward from nearshore to the Laurentian Sub-basin. Interpretations of industry seismic and magnetic data indicate that the northern margin of the basin coincides with the boundary between the Appalachian Avalon and Meguma terrains.
The northern margin of the basin is bounded by the eastern extension of the Cobequid-Chedabucto fault with about 3 km of vertical displacement. The southern margin consists of a series of discontinuous faults antithetic to the Cobequid-Chedabucto fault. Thick sedimentation into this basin was received during pre-breakup time and was filled by Middle Jurassic time.
The rift-fill sequence of the basin was comprised of mostly Triassic to Jurassic Mesozoic sediments, which were deposited unconformably on a basement comprised of various lithologies and age, including meta-sedimentary, meta-volcanic, igneous intrusive, siliciclastic, carbonate and evaporate rocks.
Seven exploratory wells were drilled in this basin in the 1970s, primarily on structures at the basin margins or on poorly defined salt structures.
SYDNEY BASIN
The Sydney Basin is visible in outcrop sections onshore in eastern Cape Breton and is believed to extend offshore as far as southwestern Newfoundland. The offshore portion of the basin consists of at least four major half-graben extensional sub-basins bounded by a series of northeast-trending and southeast-dipping faults. These sub-basins are primarily filled with early Mississippian Horton Group alluvial fan deposits of red bed conglomerate, sandstone and shales.
Three wells were drilled in the basin in the 1970s: North Sydney P-05 and North Sydney F-24 were drilled offshore, and Birch Grove No.1 onshore. The offshore wells were drilled on the prominent North Sydney anticlinal structure. Both wells encountered gas shows but generally have porosities less than 10% and low permeability.
Hunt Oil’s intentions to explore this area signaled the only activity for the area during the past 30 years. Hunt recently acquired a seismic program but surrendered the lands without drilling a well. 
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