Exploration History
Exploration History
The Call for Bids NS14-1 area is located along the northeastern portion of the deep water Scotian Slope. Due to its water depth and limitations of drilling and production technologies, the region was excluded from the initial exploration in the 1960s that was centred around Sable Island. As more and better quality geoscience data were obtained, and technologies and geologic knowledge improved, exploration extended to increasingly greater water and subsurface depths.
A second phase of exploration was initiated in the late 1990s generated by the acquisition of several comprehensive regional 2D seismic surveys, e.g. TGS-Nopec, Western Geco, etc.). Parcels were nominated by industry with a number of exploration licenses later issued. Additional 2D seismic programs and a single 3D survey (Encana “Stonehouse”) were acquired. Seven wells were drilled in 2001-2004 in the central Scotian Slope west of the Call area with generally disappointing results (Kidston et al. 2007). Following this, the existing exploration licenses were allowed to lapse and reverted back to the Crown. In 2011 and 2012, most of the deep water Crown lands in the western half of the Scotian Slope were acquired by Shell and BP respectively.
Table 1 lists details on the wells in and adjacent to the Call region, and are shown in Figure 1. The wells are sorted by their proximity to the respective parcel, and include information on hydrocarbon shows, TD formation, play type, basin, operator, and spud date. Table 2 ranks the information by spud date, Table 3 by subbasin, and Table 4 summarizes all significant discoveries and shows. A list of all of the available seismic data, well data, and interpretation reports is available in the Data section of this Call package. Note that except for Tantallon M-41, the remaining 12 wells are all outside the Call parcels on the shallow Scotian Shelf, but are included in all tables due to their local and regional relevance.
Nine shelf wells tested gravity-driven structural closures bounding or above the South Griffin Ridge, and sought reservoir development in thick delta slope and shallow marine sand / carbonate successions of the Missisauga, Mic Mac and Abenaki formations. Three wells in the Prirose field west of the Call parcels tested a large shallow salt diapir seeking hydrocarbons in the draped chalks of the Wyndot formation, and deeper sandstones of the Logan Canyon and Missisauga formations on its flanks.
The Dauntless D-35 well (1971) is the oldest of 12 wells drilled outside of the Call region’s northern boundary. It was operated by Mobil and tested a large, moderate relief faulted anticlinal feature on the easternmost portion of the Scotian Shelf (Nova Scotia waters). This elongated anticline trends northeast-southwest with fault closure on its long margins and structural closure on the remainder. The northern fault extends up to the Barremian O-Marker with the hanging wall succession showing moderate growth in the deeper Jurassic strata. The southern fault displays a similar architecture with additional growth in the both the Jurassic Mic Mac and Abenaki, and sub-O-Marker Missisauga section. In addition, this fault displays motion up into the Eocene. A crestal fault bisects the closure medially though has modest growth and does not extend beyond the top of the Jurassic.
Closures were mapped in the Missisauga, Mic Mac and Abenaki, with ~112 km2 at the Mic Mac level. The Missisauga was relatively thin with porous fluvial sandstones. The Jurassic Mic Mac formation was likewise thin and composed mostly of tight limestones. The Abenaki carbonates were mudstones with some porous oolitic and sand intervals with the well ending in Oxfordian limestones. No significant hydrocarbon shows were present in the well.
Sauk A-57 (1971) was another of the early wells drilled on the western Scotian Shelf. Shell drilled an hourglass-shaped, fault-bounded rollover anticline. The north bounding fault penetrates into the Early Cretaceous Logan Canyon formation, with simple closure for the remainder of the feature. Closures are developed in the Upper Missisauga (O-Marker) to Late Jurassic Mic Mac (Top Jurassic; ~70 km2) formations. Porous, fluvio-deltaic sands of both formations were encountered, though deceased with depth. The well bottomed in tight oolitic limestones of the Abenaki formation (Kimmeridgian; top Baccaro member). No hydrocarbon shows were encountered.
Shell’s Primrose N-50 well (1972) resulted in one of the early exploration successes in the Scotian Basin. It tested a large, shallow salt diapir with simple structural closure over its crest as defined by the Wyandot formation chalks. A condensed stratigraphic succession was drilled composed of a much thinned Wyandot chalk, Dawson Canyon shale interval, Logan Canyon formation fine grained porous sandstones and shales, Iroquois formation porous dolomites and dolomitic shales (caprock), and ending in Argo formation salts. Significant hydrocarbon shows were present and tested in Wyandot (gas and condensate), Logan Canyon (gas and condensate) and Iroquois (oil and gas) formations (Tables 4.1 – 4.4). The Wyandot tests were preceded by acidization and showed pressure depletion during testing.
This discovery was immediately followed-up with two delineation wells; A-41/1a-41A (1972) and F-41 (1973). The A-41 well was drilled northeast of N-50 and near the diapir flank to test a separate crestal fault-bounded compartment. Gas was present and tested at the top of the Wyandot and present a zone in the Logan Canyon formation. It was then whipstocked to test deeper horizons in closure against the diapir (1a-A-41A) and penetrated a thick succession of fluvial-deltaic and shallow marine sandstones on the Logan Canyon and Missisauga formations. While gas was present and tested in the Wyandot, no significant shows were found in the deeper strata and the well was stopped at the top of the Missisauga formation. The F-41 well was positioned north of the N-50 well and also in a separate fault-bounded crestal fault compartment. Gas was again present in the Wyandot and tested, and the underlying Logan Canyon and Iroquois formations were much-thinned and without shows. The well drilled a thick Argo salt section and was terminated in the same.
The Primrose Field is defined as a Significant Discovery. The majority of the gas reserves are in the Wyandot formation, and oil in the Iroquois formation. Smith et al. (2014) have calculated the field’s total mean (probabilistic) gas-in-place and oil-in-place at 305 Bcf (8.64 e9m3) and 3.53 MMbbls (0.561 e6m3) respectively. Field total mean recoverable gas is determined to be 129 Bcf (3.65 e9m3) gas, 0.723 MMbbls (0.115 e6m3) condensate, and 1.06 MMbbls (0.169 e6m3) oil. The field remains undeveloped. Complete information on this Significant Discovery, including petrophysical and resource assessments, can be found in Smith et al. (2014).
The Mobil-Texaco Sachem D-76 well (1975) was another of the early wells drilled to test a feature above the yet-unrecognized deep basement South Griffin Ridge. The structure is a mostly fault-bounded, low relief anticline with little growth in the targeted Missisauga and Mic Mac formations. Small isolated closures are on the hanging walls of associated with tow en echelon bounding faults. The two bounding the Sachem closure do not extend beyond the top of the Jurassic suggesting that like the Dauntless well this was a region of stability post-Jurassic. However, the most outboard third fault is steeper and extends far up into the top Tertiary, though again with very modest amounts of growth.
The upper Missisauga formation contained a mix of fluvial and shallow marine sandstones, oolitic limestones and shales. The middle Missisauga was composed almost entirely of ~240m porous (12-20%), stacked fluvial channel sandstones. A single, very low (<1% TGU) gas show was present at the top of the formation over which is ~100m of shale and siltstone. Trace to minor(<1% TGU) gas shows were present at the top 125 m of the Mic Mac formation in thin sandstones with good to poor intergranular porosity. The remainder of the formation to TD was dominated by micritic limestones with minor amounts of shale and fine to medium grain sandstone. The latter are generally tight though those with ~6% have trace gas shows (<1% TGU).
The Petro-Canada Banquereau C-21 (1982) was one of the first of several wells drilled on the eastern Scotian Shelf following the discovery of the large Venture gas field in 1979. It was drilled on the southwestern flank of a large anticline and discovered significant quantities of natural gas, as well as having a number of gas shows throughout the well. The well went into overpressue conditions and bottomed at 4991 m in Verrill Canyon formation shales of earliest Cretaceous age. The Banquereau field was declared a Significant Discovery by the CNSOPB in 1985.
The Banquereau structure is a low relief, narrow, elongate anticlinal feature bounded to the north by a major, southeast-dipping, down-to-the-basin fault, and exhibits both fault and rollover related closure. Original mapping interpreted maximum closure at the top Missisauga formation O-Marker interval of about 22 km2 with crest is near its centre and maximum vertical closure of approximately 70 m. However, recent study (Smith et al., 2014) reveals that effective net closure, based on log analysis, ranges between 7.7 km2 and 12.8 km2. The bounding fault reveals growth in the Late Jurassic to lower Early Cretaceous successions, and simple late-phase motion in the Tertiary. The bounding faults sole basinward into the deep Jurassic age marine shales of the Verrill Canyon formation.
Potential reservoir sands in the Naskapi and Missisauga consist of isolated sequences of delta front, channel and strandplain-shoreface depositional facies in a shaIe-dominated marine setting. Well data indicates that these coarsening upward progradational sands are very fine to medium grained, well sorted, siliceous and variably argillaceous. The reservoir characteristics of the gas sands are fair to good with effective average porosities ranging from 12-17% and permeabilities 0.1-20 mD based on well logs and drillstem test results.
A number of high mud-gas readings were recorded in sands of the Logan Canyon and Missisauga formations, as well as fracture and fault zones in Verrill Canyon formation shales. Significant gas accumulations were encountered in three porous, hydropressured sand zones; two near the top of the Naskapi member (Zones 1 & 2, Naskapi member, Logan Canyon formation), and one at the top of the Missisauga formation (Zone 3). DST #2 (Zone 3, Missisauga) tested 23.4 MMcf/d gas & 100 bbls/d condensate, and DST #3 (Zone 1, Naskapi) 0.8 MMcf/d gas. Zone 2 was not tested. The reservoir sands demonstrated sustained flow on tests, and therefore the field was designated as a Significant Discovery.
Smith et al. (2014) have calculated the field’s mean (probabilistic) original gas in-place to be 270 Bcf (7.65 e9m3), with mean recoverable reserves of 172 Bcf (7.66 e9m3). The field remains undeveloped. Complete information on this Significant Discovery, including petrophysical and resource assessments, can be found in Smith et al. (2014).
The North Banquereau I-13 (1982) was Petro-Canada’s immediate follow-up to the C-21 discovery and drilled to test a large structure in the fault block adjacent to and north of the C-21 discovery. The North Banquereau structure is a moderate relief, fault bounded anticline with simple closure to the east with approximately 46.5 km2 of closure at the Barremian O-Marker level. The bounding faults extend into the base Tertiary and some earlier growth in the Mic Mac succession. The I-13 well targeted these potentially overpressured upper Jurassic sandstones as well as those of the overlying Missisauga formation based on C-21’s positive results.
Fair to good porosity in the Missisauga fluvial and shallow marine sandstones. One thin sand with gas pay over water was encountered in the Lower Missisauga. The middle member had increasing shale and thin very fine grain delta front sands. The expected upper Mic Mac formation was not present; instead was approximately 800 metres of Verrill Canyon shales with minor siltstones and sandstones. The top of overpressure was penetrated within the section, and a number of very high gas shows were observed in slightly porous overpressured sandstones and fault/fracture zones. The underlying lower Mic Mac had several minor oil shows in thin, slightly porous sands at the top of the formation. A DST at the base Missisauga and another at the top of the Mic Mac were unsuccessful due to mechanical failure. The well was ended at 5188 m in a mixed succession of mostly tight oolitic limestones and shallow marine sandstones.
The third Petro-Canada well in the region was Southwest Banquereau F-34 (1983) drilled on a rollover anticline located 24 km southwest of C-21. Thin gas pay over water was encountered in the Lower Missisauga. This structure more proximal to the interpreted Sable delta complex and would test potential siliciclastic and carbonate reservoirs in the Missisauga, Mic Mac and Abenaki formations. The anticline was the largest of several in a large northeast-southwest trending fault-bounded anticline with faults extending up into the Tertiary succession. It is essentially fault-bounded on all sides with several modest offset fault splays extending away from the north-bounding fault. Approximately ~42.5 km2 of closure was defined by the operator at the Barremian O-Marker level, i.e. base of the upper Missisauga formation. The well was offset from the structural crest and would test potential siliciclastic and carbonate reservoirs in the Missisauga, Mic Mac and Abenaki formations.
The well penetrated a thick, well developed Missisauga formation composed of shallow marine sandstones with fair to good porosity. Minor gas shows were present in a few Missisauga and Verrill Canyon sands though five DSTs were attempted to test three hydropressured gas-bearing zones in the Missisauga. One of these was a 10 m thick sand located at the base of a ~100 m shale interval beneath the carbonate O-Marker. DST#3 (4332.0-4342.0 m) tested 0.6 MMcf/d confirming the presence of gas in the zone. Sandstone facies of the Mic Mac formation were not developed, with outer shelf shale facies of the Verrill Canyon formation dominating. A few isolated, thin (10-15m) porous sands developments were present in this section and the well ended at 6303m in the Verrill Canyon.
Louisbourg J-47 (1984) was drilled by Home Oil to evaluate Late Jurassic fault-bounded anticline. The primary target was the deltaic and shallow marine sandstones of the Mic Mac formation, with the secondary being similar successions in the conformably overlying Late Cretaceous Missisauga formation. The J-47 well penetrated over 1800m of Jurassic section and tested 5 MMcf/d of gas from Mic Mac formation sandstones.
The Louisbourg structure is located on the northern margin of the NE-SW trending South Griffin Ridge, a deep basement feature that parallels the current shelf break (CNSOPB, 2013). The feature has modest structural relief covering an area of 22 km2 at the top of the Mic Mac formation, and over 60 km2 in the middle of the formation. It is bounded to the northwest and southeast by Late Jurassic faults and has dip closure at its east and west ends with growth observed in the Jurassic successions.
The approximately 1000 m thick Missisauga formation is dominated by deltaic and channel sandstones, with the lower member mostly delta front and shallow marine sand facies. Several minor hydrocarbon shows were present in the formation with one tested with the RFT recovering gas and condensate. The targeted Mic Mac formation is about 1800 metres thick and carbonate-rich with many thick, tight limestone intervals alternating between delta front and shallow marine sandstone successions. The sands generally have porosities less than 10% and most are either wet or tight. Four gas shows were noted in the 4350-4555 m interval where sand porosities are better (10-15%). Two cores in the interval revealed dead oil staining with a slow pale yellow streaming cut.
A 12.5 m thick sandstone at 5786.5-5799.0 m, with 3 m of net gas pay was evaluated by DST #1B (5785.7-5799.5m). However, there were mechanical problems and operational issues with the test. The interval was tested using overbalanced mud that plugged the zone’s perforations that greatly compromised confirmation of the reservoir’s productivity. Subsequent engineering analysis by the operator indicated that recovered hydrocarbons probably reached the well bore via a small channel in the cement and/or a micro-annulus. The DST’s probable flow rate was calculated at 5.0 MMcf/d. Assuming that all the completion parameters were optimal, it was calculated that the potential absolute open flow rate (AOF) would have been 28.75 MMscf/d. Bow Valley/Husky’s South Griffin J-13 well (1984) tested a moderate relief, deep, fault-bounded anticline along the same fault trend as the Banquereau wells but much further to the east and near the edge of the Pleistocene Laurentian Channel. The reservoir target was Mic Mac formation deltaic to shallow marine sandstones intercalated with delta front and marine shales and shallow marine limestones.
Similar to other wells along this trend, South Griffin is affected by the regional basement ridge that bears its name. The J-16 well is located near the southern edge of the ridge where a significant amount of Late Jurassic down-to basin faulting occurs above the hingeline fault that drops out into the deep water province. Two closure intervals were mapped: approximately 12 km2 of independent closure at the Upper Jurassic (Mic Mac) seismic horizon, and a larger (~20 km2) fault-controlled closure at a deeper intra-Mic Mac horizon.
The J-16 well drilled through two crestal faults before reaching the targeted Mic Mac formation. The 1300 m thick section was composed of a succession of siliceous, medium to fine grain fluvial-deltaic and minor marine sandstones with moderate to good porosities, and poor porosity oolitic limestones that increase in thickness with depth. Surprisingly, there is a very limited amount of shale in the Mic Mac, composing less than 5% of the succession.
There were several minor hydrocarbon shows present in the well, most within the overlying Missisauga formation. Here, several modest gas peaks were observed in well sorted, fine to medium grain sandstones with poor porosity that had some staining and fluorescence. Asphaltic and bituminous material was present in the 4150-5160 m Mic Mac interval with associate spotted staining. Four modest gas peaks and sample staining were present in fair to poor porosity sandstones in the lower part of the Mic Mac. A single core was attempted but not completely recovered, and no formation testing was undertaken. Top of overpressure was penetrated at about 5023 m, and the well bottomed in limestones and marls of the Mic Mac/Abenaki succession at 5911 m.
The Home Oil Citadel H-52 (1985) well was the last of the eastern outer Scotian Shelf wells drilled, testing a large (~39 km2) fault-bounded rollover anticline 20 km southwest of and along strike with the older Sauk A-57 well. Unlike several of the previously described wells, the faults do not extend up beyond the top of the Mic Mac formation (~Top Jurassic) inferring a later tectonic stability here that possibly predated hydrocarbon generation and migration from Tithonian source rocks. Mapped closures all relied on a combination of fault and simple structural closure with faults assumed to seal.
H-52 was drilled to evaluate potential reservoir zones in the Mic Mac and Abenaki formations, with overpressure encountered at the top of the Mic Mac (~4800m). High amplitude reflections in the Abenaki were interpreted as thick limestone sequences with downlap features terminating north of the structure’s bounding fault. Clastics of the lower portion of the Mic Mac formation onlap and extend over the ridge with the upper Mic Mac eventually burying and draping over it. Growth faulting occurs above the ridge and soles basinward.
Except for the top Mic Mac, reservoir quality was generally poor in the H-52 target sequences. Mic Mac distal delta front sandstones were generally tight (carbonate and siliceous cement) though where minor porosity existed had fair dry gas shows. Occasional similar shows occurred in the mostly tight oolitic to fossiliferous shallow marine transgressive limestones. Modest gas shows in sandstones displayed a relative increase with depth and increasing overpressure, though only a few minor gas peaks were present in the tight limestones. The well TD was stopped at 5666 m in early Kimmeridgian age limestones (Abenaki formation equivalents) and abandoned without testing.
The Shell-PCI Tantallon M-41 (1986) was the last well drilled in the eastern Scotian Basin region and first in deep water. It is located south of the Banquereau Bank outboard of several shelf wells on the east side of the Late Jurassic to Late Cretaceous Sable delta complex. The structural anomaly is a large, low-relief rollover anticline on the downside of a down-to-basin listric fault based on 2D seismic from the early- to mid-1980’s. It was presumed to be well defined though lacking the degree of fault offset observed at the Evangeline H-98 well located on the west-central part of the Scotian Slope. Tantallon’s target objectives were outer deltaic/shallow marine sandstones, and equivalent slope turbidite sands of the Early Cretaceous upper Missisauga and lower Logan Canyon formations (Cree Member).
The well was drilled to 5602 m TD ending in the distal equivalent shale section of the lower Missisauga formation (late Valanginian). The target intervals consisted primarily of shale with a few generally thin, poor quality sandstones and siltstones. No gas kicks or abnormal pressures were encountered in the well. A 14m thick very fine to fine grained sandstone with a fining-upward gamma ray profile was penetrated in the upper Missisauga Formation equivalent (5207-5021 m, Late Hauterivian). The sand was generally tight with porosity <10%, except for two thin (0.5 m) intervals with 11% porosity. Water saturations (Sw) were calculated to be about 60%, and it is possible that the sand has some gas charge though most of the sand’s low porosities (<10%) makes the Sw calculation more interpretive.
Subsequent regional mapping of the Hauterivian K130 seismic horizon (~ base O-Marker) does not display Tantallon’s closure but instead reveals a low saddle between two highs (OETR, 2011; Plate 5-3-8b). This saddle corresponds with a positive relief bathymetric nose, and negative relief embayments for the bounding highs. It therefore appears probable the earlier closure is an artefact of seismic processing.
Complete geoscience information on the Tantallon M-41 well can be found in the Call package DATA Section.
References
CNSOPB, 2013
Geological context and parcel prospectivity for Call for Bids NS13-1: Seismic interpretation, source rocks and maturation, exploration history and potential play types of the central and eastern Scotian Shelf.
Canada-Nova Scotia Offshore Petroleum Board Call for Bids NS13-1, 66p.
http://www.callforbids.ca/sites/default/files/inline-pdf/cfb_ns13_summary-final_for_web_2.pdf
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.
http://www.cnsopb.ns.ca/sites/default/files/pdfs/Deep_Water_Post_Drill_Analysis_2007.pdf
Offshore Energy Technical Research Association (OETR Association), 2011.
Play Fairway Analysis Atlas - Offshore Nova Scotia.
Nova Scotia Department of Energy Report, NSDOE Records Storage File No. 88-11-0004-01, 347p.
http://www.novascotiaoffshore.com/analysis
Smith, B.M., Makrides, K., Altheim, B. and Kendell, K., 2014
Resource Assessment of Undeveloped Significant Discoveries on the Scotian Shelf.
Canada-Nova Scotia Offshore Petroleum Board, 186p.
