Search goes on for more light oil in western Newfoundland

Feb. 15, 1999
A light oil discovery in the first deep well drilled in western Newfoundland has sparked new interest in this prospective oil province of eastern North America. This article reviews the latest round of hydrocarbon exploration, including three exploration wells, and new models for structural trapping, reservoir development, and source rock maturation. Newfoundland's west coast lies in the Humber Zone1 of the Canadian Appalachians. Shallow wells drilled in the 19th and early 20th centuries on
John Weissenberger
Mark Cooper
PanCanadian Petroleum Ltd.
Calgary
A light oil discovery in the first deep well drilled in western Newfoundland has sparked new interest in this prospective oil province of eastern North America.

This article reviews the latest round of hydrocarbon exploration, including three exploration wells, and new models for structural trapping, reservoir development, and source rock maturation.

Hydrocarbon exploration results

Newfoundland's west coast lies in the Humber Zone1 of the Canadian Appalachians.

Shallow wells drilled in the 19th and early 20th centuries on the Port au Port Peninsula and at Parsons Pond (Fig. 1 [208,919 bytes]) produced small quantities of oil used locally. Seeps and bitumen staining in rocks occur on Port au Port Peninsula, Two Guts Pond, Parsons Pond, Humber Arm, and Port aux Choix.2

Golden Eagle in the 1960s drilled two dry holes on Shoal Point, the latter encountering minor quantities of oil. Unocal drilled the only deeper well farther south in the Carboniferous/Devonian Anguille Group in the 1970s.

Since 1991, abundant seismic data have been acquired onshore and offshore Western Newfoundland, initially by Hunt Oil, Mobil Oil, Marathon, and Norcen Energy. PanCanadian became a partner with Hunt to explore the play in September 1994, before the first well was spudded. Four wells have now been drilled, three of which are discussed below.

Port Au Port 1

The Port au Port 1 well was planned to test a small onshore closure identified with limited seismic data ( Fig. 2 [153,399 bytes]).

The play concept involved a Lower Ordovician carbonate platform reservoir3 with source rocks in the coeval basinal facies4 5 that had been thrust onto the platform during the Middle Ordovician (Taconic orogeny; Fig. 3 [226,910 bytes]). The structural traps were the result of footwall shortcuts developed when the extensional faults of the Laurentian margin were inverted during the Devonian Acadian orogeny.

Seal was provided by tight limestones of the Table Point formation and shales of the Goose Tickle Group. No previous wells had tested this play concept in Western Newfoundland (Fig. 4 [175,308 bytes]).

PanCanadian participated in this venture to reduce Hunt's exposure in a high risk exploration project. The strategy was clear: to test the basic play concept at relatively low cost onshore prior to testing the much larger structure mapped offshore along trend (Fig. 2). The principal risks were:

  1. The presence of the structural trap at the onshore location;
  2. Reservoir quality in the Ordovician/Cambrian carbonate platform; and
  3. The efficiency of hydrocarbon fill of the structures, from the known mature source kitchen in Port au Port Bay.
Port au Port 1 was spudded in the Catoche formation and drilled uneventfully until it encountered flows of salt water, in the Roundhead Thrust hangingwall, from clean quartz sandstones with porous streaks (Hawke Bay formation, 64 m of 12% porosity). Analysis showed the fluids to be meteorically recharged formation water.

A 615 m section of predominantly granitic Grenville basement was drilled above the Roundhead thrust (Fig. 4). In the footwall the most significant thickness and facies changes occurred between the top of the Lourdes formation and the base of the St. George Group. The Lourdes formation was significantly thicker (180 m) in Port au Port than at outcrop (75 m) due to the well's greater distance from the eastern onlap edge. The Goose Tickle Group is thinner in the well (185 m) than at nearby outcrops (at least 1,000 m),6 because the well is on the footwall of the Roundhead thrust.

The Aguathuna formation beneath the St. George unconformity alternately took large volumes of mud and then flowed hydrocarbons into the wellbore, causing several days of well control problems. On logs the Aguathuna formation appeared to be oil bearing with porosities of up to 10% (mean 9%) and potential net pay of 33 m. The FMS log appeared to show caverns, initially interpreted as karst beneath the St. George unconformity.

This interval produced oil at maximum rates of 1,750-2,400 b/d with a 25% water cut at pressures of 25 Mpa. Well control and lost circulation problems impeded drilling through the remainder of the St. George Group. Most dramatic losses of circulation were in the Watts Bight formation from 3,910-55 m, where 5,450 bbl of whole mud was lost to the formation.

Logs of this Watts Bight interval indicated high porosities (up to 30%; mean 14%) but no hydrocarbons. Low sonic velocity and large caliper response suggested the development of three large cavernous voids and anomalously high density response-considered indicative of sulfide mineralization lining the void walls. The zone produced formation water at 1,500-4,000 b/d at a pressure of 40 Mpa.

Casing was set at 4,198 m and the well deepened into the Hawke Bay formation to test the porous stringers seen in the hangingwall of the Round Head thrust. The formation was tight and wet, however, with maximum porosities of 5%.

The well produced a cumulative volume of 5,012 bbl of oil and 2,737 bbl of water on production test over 7 days at variable rates with a decrease in rate and pressure seen by the end of the test. The origin of this drop in productivity is unclear from the test and build-up data. It could be due to wax or salt precipitation around the perforations or it could reflect depletion of a small accumulation. The well is currently suspended.

Long Point M-16

Hunt and PCP directionally drilled this well from the northern tip of Long Point (Fig. 1) eastwards to validate a license held by Mobil Oil Canada, allowing Hunt and PCP to earn a 37.5% interest; Mobil retained 25%.

The well was spudded in the Lourdes formation, in the roof sequence of a triangle zone.7 The triangle zone could be due to imbrication of either Humber Arm allochthon rocks; Cambro-Ordovician platform strata; or allochthon, platform, and basement rocks.

The well cut 76 m of Lourdes formation above the Tea Cove thrust. Beneath the thrust were a series of folds and imbricates within the Humber Arm allochthon. Unstable shales caused severe hole problems, resulting in two fishing operations for lost bottomhole assemblies; one was never recovered (but was clearly visible in the wellbore wall on electric logs).

Poor hole conditions created problems in interpreting the stratigraphy and geometry of the Humber Arm allochthon in the M-16 well, due to caving contamination in biostratigraphic samples and poor quality logs. Biostratigraphy, FMS dip, and image data were used to interpret stratigraphy and structure. Three distinctive FMS "image facies" were correlated biostratigraphically and showed a general downward increase in age but some significant downhole shifts to younger ages, implying either fold or thrust repetition.

The dip (15° NW) and elevation above regional of the platform suggests a basement-involved compressional fault, perhaps similar in origin to the Round Head thrust, located NW of the wellbore (Fig. 5 [252,618 bytes]).

St. George's Bay A-36

A-36 was drilled to test the offshore extension of the footwall structure beneath the Round Head thrust tested by Port au Port 1. The top of the Ordovician carbonate platform was prognosed to be around 1,200 m higher than in Port au Port 1.

Complicated offshore geology in the St. George's Bay basin includes a Carboniferous succession above an erosional unconformity truncating the Round Head thrust (Fig. 6 [292,250 bytes]). To the south the footwall is poorly imaged seismically, making southern closure the key risk factor.

The well penetrated about 500 m of Carboniferous before crossing the unconformity into the Upper Winterhouse formation in the footwall of the Round Head thrust (Fig. 6). The platform top was on prognosis, but the Table Point formation was 70 m thick, indicating the well did not penetrate the footwall as close to the Round Head thrust as Port au Port 1.

No significant porosity was seen in the Aguathuna, Catoche, and Boat Harbour formations, although live oil stain was seen in cuttings throughout. The Watts Bight formation contained a 14 m zone with cavernous porosity development (net 8 m of 12.9% porosity). On FMI logs, this was interpreted as zebra dolomite. This zone produced a gas kick on penetration, but logs indicated the zone was wet. The Cambrian Hawke Bay formation contained 31 m of 10% (mean) porosity but calculated wet on logs.

Play element summary

Trap configuration The successful structural trap configuration tested to date is the footwall shortcut anticline developed by Acadian inversion of Ordovician platform collapse extensional faults ( Fig. 7 [157,910 bytes]). The potential fairway is defined to the east, north, and south by the eastern thrust edge of the Humber Arm allochthon-beyond this the reservoir section is at surface. The western edge coincides with the western limit of Acadian inversion-clearly seen on the offshore seismic data.

Reservoir targets

The primary target reservoir is the Cambro-Ordovician carbonate platform (Upper Cambrian Port au Port Group through Lower Ordovician St. George Group). It comprises a platform interior setting-the correlative margin was caught up in the Appalachian orogen. It includes thrombolitic, pelloidal, and skeletal wackestones/packstones; and cryptalgal or fenestral mudstones occuring in shallowing upward cycles 1-5 m thick.

Two third-order, unconformity-bounded sequences occur in the potential reservoir section,8 both roughly 250-300 m thick. The lower sequence comprises the upper part of the Port au Port Group-beginning in stacked, small-scale peritidal cycles in the Middle Berry Head, which represents minimum accommodation on the platform. The upper boundary is a regional unconformity (1-2 million year hiatus) in the Upper Boat Harbour formation.

The second, younger third order sequence comprises the uppermost Boat Harbour through Aguathuna formations, bounded by the Boat Harbour unconformity at the base and the St. George unconformity at the top. The latter is a major, 8 million year depositional hiatus present throughout east and southeastern North America ("Knox unconformity," 476-468 ma). Both sequences have a basal part consisting of thin, dominantly peritidal cycles; the middle is somewhat thicker, mostly subtidal cycles; the upper portion is again dominantly peritidal.

Dolomitization is critical in porosity/permeability development and preservation. Abundant dolomite is present in the Port au Port outcrops, but there is little apparent reservoir. Dolomitized subtidal lithofacies yield 5% porosity and permeability of 0.06 md in medium gray, fine to medium crystalline dolomites, with irregular dissolution vugs ranging from 2 mm to 20 mm in size. Peritidal dolomites are invariably tight.

There is some dissolution at the St. George unconformity,3 but no apparent porosity creation at or below the unconformity surface, nor dramatic karst as described by Kerans9 (Ellenburger formation of West Texas). By contrast, the platform section in the footwall of the Round Head thrust encountered several porous zones in the Port au Port 1 well as described above.

The Long Point M-16 well had poorer reservoir. Only the Watts Bight formation showed some porosity (13 m of 7%) with white dolospar. The St. George's Bay A-36 well encountered a largely dolomitized but tight interval at the top of the platform (Fig. 6) and one cavernous zone in the Watts Bight formation (2,440-55 m).

We believe the dominant reservoir quality creation mechanism was hydrothermal dolomitization, linked to the area's tectono-stratigraphic history. Some subaerial and subaqueous erosion of the platform occurred during the foundering of the platform (Taconic; Arenig/Llanvirn), the movement of hydrothermal fluids (Acadian; E.-M. Devonian) caused development of cavernous, mineralized porosity.

Fluids likely migrated along major faults, to the highest topography (e.g. Aguathuna formation) below a permeability barrier, ultimately the mudstones and shales capping the platform. Hydrothermal fluids would have followed preferentially porous and permeable units in the platform (e.g. Watts Bight formation), connected to fault conduits.

Hydrocarbon charge

Good source rock potential is known in the Humber Arm allochthon, with organic rich (high TOC) shales. 5 10 The oil in Port au Port 1 was typed to Ordovician source rocks. 11 Drill cuttings from the three Hunt/PCP wells were examined for vitrinite reflectance, conodont color alteration index, graptolite reflectance, and acritarch color. These show increasing maturity with depth (consistent with surface samples), suggesting maximum burial of the platform prior to the Acadian orogeny. Outcrop maturity data from the Humber Arm allochthon (southern shore, Port au Port Bay) indicates that the strata are in the oil window.

Future activity

PanCanadian is optimistic about the hydrocarbon potential of the West Newfoundland basin and the play types described. In early February, PanCanadian and partners spudded a well in the inversion structural fairway. It is hoped that the well, located on the tip of Shoal Point, Port au Port Peninsula, will encounter the most significant oil pool yet found in the basin.

Acknowledgments

We acknowledge the support of our co-workers, Doug Hostad and Derek Gillespie of Hunt Oil, Calgary, Don Rae and Elizabeth Clark of Mobil Oil Canada, Henry Williams and Elliott Burden of Memorial University, Newfoundland, and Ian Knight of the Newfoundland Geological Survey.

References

  1. Williams, H., Appalachian orogen in Canada, Canadian Journal of Earth Sciences, Vol. 16, 1979, pp. 792-807.
  2. Department of Energy, Hydrocarbon potential of the western Newfoundland onshore area, Government of Newfoundland and Labrador, Department of Energy Report, 1989, 20 p.
  3. Knight, I., James, N.P., and Lane, T.E., The Ordovician St. George unconformity, northern Appalachians: the relationship of plate convergence at the St. Lawrence Promontory to the Sauk/Tippecanoe sequence boundary, GSA Bull., Vol. 103, 1991, pp. 1,200-25.
  4. James, N.P., and Stevens, R.K., Stratigraphy and correlation of the Cambro-Ordovician Cow Head Group, western Newfoundland, GSC Bull. 366, 1986, 143p.
  5. Fowler, M.G., Hamblin, A.P., Hawkins, D., Stasiuk, L.D., and Knight, I., Petroleum geochemistry and hydrocarbon potential of Cambrian and Ordovician rocks of western Newfoundland, Bull. of Canadian Petroleum Geology, Vol. 43, 1995, pp. 187-213.
  6. Quinn, L., 1995, Middle Ordovician foredeep fill in western Newfoundland, in Current Perspectives in the Appalachian-Caledonide orogen, Hibbard, J.P., van Stall, C.R., and Cawood, P.A., eds., Geological Association of Canada Special Paper 41, 1995, pp. 43-63
  7. Stockmal, G.S., and Waldron, J.W.F., Structural and tectonic evolution of the Humber zone, western Newfoundland, 1: Implications of balanced cross sections through the Appalachian structural front, Port au Port Peninsula, Tectonics, Vol. 12, 1993, pp. 1,056-75.
  8. Knight, I., and James, N.P., Stratigraphy of the Lower Ordovician St. George Group, western Newfoundland: The interaction between eustasy and tectonics, Canadian Journal of Earth Science, Vol. 24, 1987, pp. 1,927-51.
  9. Kerans, C., Karst-controlled reservoir heterogeneity in Ellenburger Group carbonates of West Texas, AAPG Bull., Vol. 72, 1989, pp. 1,160-83.
  10. Sinclair, I.K., A review of the Upper Precambrian and Lower Paleozoic geology of western Newfoundland and the hydrocarbon potential of the adjacent offshore area of the Gulf of St. Lawrence, Canada-Newfoundland Offshore Petroleum Board, GL-CNOPB-90-01, 1990.
  11. Fowler, M.G., personal communication.

The Authors

John Weissenberger initially worked at Imperial Oil on Devonian exploration projects. After joining PanCanadian in 1994 he worked on reservoir and stratigraphic aspects of Devonian through Triassic plays in the British Columbia foothills and on western Newfoundland. He is the carbonate specialist at PanCanadian, working on exploration and development projects, conducting training, and pursuing practical research applications in carbonate sequence stratigraphy. He has a BSc degree in geology from the University of Western Ontario, MSc degree from Universite de Montreal, and a PhD degree from the University of Calgary. E-mail: [email protected]
Mark Cooper initially taught geology in London and at University College, Cork. He moved to BP in 1985 and worked on structurally complex basins worldwide, including assignments to Calgary and Bogota. He joined PanCanadian Petroleum as structural specialist in 1994, working on the foothills of the Canadian Rockies, western Newfoundland and the Gulf of Mexico.

He has published over 40 papers, co-edited with G.D. Williams a book on inversion tectonics, and is an advisory editor for the Journal of the Geological Society of London. He has a BSc degree in geology from Imperial College, London, and a PhD degree from Bristol University.

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