Canada's Mackenzie Delta: Fresh look at an emerging basin

Nov. 3, 2003
The Beaufort Mackenzie basin (BMB) is emerging as a major source for the future supply of North American energy demands.

The Beaufort Mackenzie basin (BMB) is emerging as a major source for the future supply of North American energy demands. Although there has been virtually no oil and gas activity in the BMB during the 1990s, the basin has always been promoted for its significant resource potential.

Recent developments, which range from newly acquired 3D seismic surveys to a complete overhaul of previous exploration data, have significantly advanced the understanding of the basin's potential. Of particular importance is recognition of several new world-class play types for the BMB.

These new plays, in conjunction with major advances in the development of a proposed Mackenzie Valley pipeline, innovations and cost reductions in Arctic drilling operations, and a tight North American gas market, have inspired a new phase of exploration that reaffirms the BMB as an emerging and favorable petroleum province.

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The Mackenzie Delta is located in the Northwest Territories of northern Canada. The Mackenzie River flows into the Arctic Ocean roughly 350 miles east of Prudhoe Bay on the Alaska North Slope (Fig. 1).

The Mackenzie River drainage basin is the second largest drainage in North America covering an area of 700,000 sq miles. The river discharges into the Arctic Ocean at a rate of 10,000 cu yd/sec. This compares to the largest North American river system, the Mississippi River, with a drainage area of 1,250,000 sq miles and a discharge rate of 23,000 cu yd/sec.

Mackenzie stratigraphy

Mackenzie Delta deposition began after Early Cretaceous rifting of the Canada basin (current day Arctic Ocean). Initial sedimentation during the Upper Cretaceous was restricted to deep marine organic rich muds of the Boundary Creek and Smoking Hills formations.1

As Laramide mountain building advanced northward, major progradational pulses of sedimentation ahead of the mountain front resulted in the deposition of 7-10 miles of Tertiary section.

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Five major deltaic sequences, the Fish River, Aklak, Taglu, Kugmallit, and Iperk (Fig. 2), have been mapped throughout the BMB. The Taglu and Kugmallit currently contain the majority of discovered reserves.

Exploration history

Exploration drilling began in the BMB in the mid 1960s following the discovery of Alaska's Prudhoe Bay.

Over the next 25 years, 189 exploration wells (59 offshore and 130 onshore) were drilled, resulting in the declaration of 48 Significant Discovery Licenses (SDLs). Of these discoveries, 29 SDLs are located offshore with a total reserve estimate of 3.0 tcf of gas and 1.5 billion bbl of oil.

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The remaining 19 SDLs are located onshore with a total reserve estimate of 6.0 tcf and 250 million bbl (Fig. 3). The current total estimate of potential recoverable reserves in the Beaufort Mackenzie basin stands at 54 tcf offshore and 13 tcf onshore.2

These reserve estimates demonstrate the commercial importance of the BMB, particularly in view of current North American gas supply. With the potential for a Mackenzie Valley pipeline coming onstream as early as 2008, the BMB is well positioned to emerge as an important source of gas.

These factors have combined to initiate a resurgence of exploration and development activity in the BMB since 1999. Three years of federal and Inuvialuit licensing has resulted in the issue of 20 new exploration licenses (ELs) covering 3 million acres.

Since 1999, industry has acquired 15 new 3D seismic surveys along with several thousand miles of new 2D data. Seven new wells have been drilled resulting in at least two new significant discoveries.

A fresh look

Analysis of the new 3D seismic in conjunction with a renewed evaluation of all previous exploration data have resulted in the identification of several new Tertiary play types for the BMB and have clarified numerous long-standing difficulties with complex structural and stratigraphic interpretations.

New plays

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Of the new plays, particular interest is focused on the recognition of a large shale diapir in the western BMB. Tightly folded anticlines, previously mapped using older 2D seismic data, have been reinterpreted and mapped as shale diapirs using newly acquired 3D data (Fig. 4).

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This particular diapir appears to have initiated as the core of hangingwall beds overlying a Paleocene Eocene growth fault that soled into underlying Upper Cretaceous mobile shales (Fig. 5). This shale unit, comprised of overpressured clays and mudstones, was likely mobilized upwards during late Laramide compressional tectonism to form the developing central core of the diapir (Fig. 6).

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Compression continued until the end of the Eocene, at which time shale mobilization ended. The local area overlying the diapir remained as a positive feature well into the Miocene. This was followed by Late Tertiary crestal collapse likely related to dewatering of the shale core. Play potential associated with shale diapirism in the western BMB occurs within Tertiary-aged sediments flanking, onlapping, and overlying the shale core (Fig. 7).

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Flanking sediments are early to middle Eocene Taglu distal delta front sands and shales with transitional to deepwater turbidites of the Paleocene Aklak. Late Eocene turbidite deposits of the Richards's onlap and pinch out onto the flank of the diapir.

Oligocene distal deltaic deposits of the Kugmallit drape the crest of the structure. AVO analysis indicates multiple levels of gas charged sands flanking and overlying the diapir complex.

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A second new play concept in the western BMB involves a large canyon-filling channel-levee-fan succession of the Late Eocene Richards sequence. 3D data constrained with biostratigraphy reveal a fairly extensive canyon system with the potential for significant coarse-grained turbidite deposits. Flattened 3D data reveal basal canyon scour followed by aggrading channelized sheet sands deposited at the base of slope (Fig. 8).

Total canyon thickness is on the order of 3,000 ft, and the amalgamated width is 10 miles. The canyon-filling play consists of multiple stacked and offset channel-levee-fan successions exhibiting combined structural drape and stratigraphic pinch-out traps. AVO analysis indicates probable gas-charged sands within this upper Richards complex. Worldwide analogs include recent major discoveries at Girassol field off Angola,3 Zafiro field off Equatorial Guinea,4 Bonga field off Nigeria,5 and numerous examples in the deepwater Gulf of Mexico.

New stratigraphic interpretation

3D seismic interpretation, in conjunction with biostratigraphic data from multiple sources, has significantly clarified previous stratigraphic interpretations.

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The illustrated example demonstrates how 2D seismic interpretation suggests faulting of limited to no displacement within the Richards formation (green horizon, Taglu—blue horizon). New 3D data have imaged a much larger fault displacement at around 1.5 sec, revealing the magnitude of tectonism and stratigraphy within this interval (Fig. 9). 3D seismic sequence stratigraphic analysis was also instrumental in defining and mapping two significant events within the Richards; a widespread Lower Richards unconformity and the previously discussed Upper Richards canyon incision.

Biostratigraphic subdivisions within the BMB have been significantly improved following a quantitative re-analysis of existing data sets and a re-sampling of raw source material from selected wells.

Of particular importance has been the 'pinning' of a specific shale unit within the Early Eocene Taglu sequence by the recognition of a newly documented foram, C. galgheria.6 Furthermore, correlations throughout the Late Eocene Richards have been vastly aided by the recognition of four key biostratigraphic subdivisions.7

Overall, these analyses have helped clarify the stratigraphy of several complex Tertiary aged sequences within the BMB. This process has also assisted in the identification of deepwater turbidite equivalents and defined new reservoir potential for the Richards and Mackenzie Bay sequences.

New geochemical interpretation

The BMB's hydrocarbon potential has been enhanced by a re-examination of the basin's geochemistry.

Historically, the Richards formation was identified as the primary source for Tertiary oil accumulations. This association was based on analyses done by Brooks,8 9 who established a link between a Tertiary oil biomarker 24-28 bisnorlupane and its occurrence in Richards's kerogen.

Since the Richards, in general, has only marginal organic richness and thermal maturity, Brooks interpretation placed severe limitations on the amount of hydrocarbon generated in the BMB. Snowdon et al.10 recently recognized 24-28 bisnorlupane in the Lower Eocene Taglu, thereby broadening the Tertiary source potential and generating capacity. The common occurrence of gas in the delta along with the relatively high TOC coaly sections in other more mature sections of the stratigraphic column also point to a much richer source potential for the BMB than the Richards alone.

Modeling of existing source rock data indicates that the primary source intervals for the Tertiary BMB are likely to be the Paleocene Aklak and Early to Mid Eocene Taglu. Local contributions also occur from the Late Eocene Richards, the Oligocene Kugmallit in the northern portion of the basin, and the Lower Tertiary Fish River and the Upper Cretaceous Smoking Hills/Boundary Creek to the south.

All of these source rocks, except the Upper Cretaceous Smoking Hills/Boundary Creek, are Type III coals or coaly intervals with sequence-average TOCs from 1.5% to 4.5% and Hydrogen Indices up to 450 kg/t.

In light of these new findings, the BMB's geochemical prospectivity has been transformed from a source limited Richards's hydrocarbon system to a rich and mature Tertiary system.

Operational innovations

Recent innovative operating technologies have decreased drilling time, increased environmental safety, and significantly reduced costs.

Arctic class, purpose-built drilling rigs and modern bit technology have resulted in an average reduction in drilling time of 30%, thus opening up the potential for multiple wells per winter drilling season using only one drilling rig. Large service rigs have been utilized for shallower onshore wells to reduce mobilization costs.

New technologies, such as encapsulated mud pits, have greatly reduced potential environmental impact. In the offshore, innovative drilling and well control systems may dramatically decrease well costs and lengthen drilling seasons, while maintaining strict environmental safeguards.

Basin status

The BMB has witnessed a significant resurgence in oil and gas exploration activity over the previous 4 years.

This activity has been driven by the basin's large untapped resource potential in a current environment of tight North American gas supply and favorable commodity price. These conditions have also played a significant role in the rekindled effort towards the development of the Mackenzie Valley natural gas pipeline.

Though it is still early in this current cycle of exploration, significant enhancements have been made in understanding the basin's complete hydrocarbon potential. Newly acquired seismic surveys, particularly 3D data, have clearly imaged new play types that have the potential to equal or exceed the resource size of previously discovered fields in the BMB.

These 3D data sets have also allowed for a more comprehensive understanding of the basin's sequence stratigraphic setting and have been decidedly effective in identifying new play fairways and reservoir intervals. In conjunction, a complete re-analysis of geochemical data illustrates the overall richness of the BMB's hydrocarbon system and supports a greatly expanded range of prospectivity. This combination of new exploration data, new and significant play types, cost effective operational innovations, a developing infrastructure and growing North American gas demand have established the BMB as an important and emerging petroleum province. F

References

1. Dixon, J., Dietrich, J. Snowdon, L.R., Morrell, G., and McNeil, D.H., "Geology and petroleum potential of Upper Cretaceous and Tertiary strata, Beaufort-Mackenzie area, Northwest Canada," AAPG Bull., Vol. 76, 1992, pp. 927-947.

2. National Energy Board of Canada, "Probabilistic estimate of hydrocarbon volumes in the Mackenzie Delta and Beaufort Sea discoveries," 1998.

3. Beydoun, W., Kerdraon, Y., Lefeuvre, F., Bancelin, J.P., Medina, S., and Blienes, B., "Benefits of a 3DHR survey for Girassol field appraisal and development, Angola," The Leading Edge, 2002, p. 1,152.

4. Shirley, K., "Equatorial Guinea on fast track", AAPG Explorer, January 2003.

5. Chapin, M., Swinburn, P., van der Weiden, R., Skaloud, D., Adesanya, S., Stevens, D., Varley, C, Wilkie, J., Brentjens, E., and Blaauw, M., "Integrated seismic and subsurface characterization of Bonga field, offshore Nigeria," The Leading Edge, November 2002, pp. 1,125-1,131.

6. McNeil, D.H., 2000 unpublished consultant reports, pers. comm.

7. Dolby, G., 2002 unpublished consultant reports, pers. comm.

8. Brooks, P.W., "Unusual biological marker geochemistry of oils and possible source rocks, offshore Beaufort-Mackenzie delta, Canada," Organic Geochemistry, Vol. 10, 1986, pp. 401-406.

9. Brooks, P.W., "Biological marker geochemistry of crude oils and condensates from the Beaufort-Mackenzie basin," Bull. of Canadian Petroleum Geology, Vol. 34, 1986, pp. 490-505.

10. Snowdon, L.R., Stasiuk, L.D., Robinson, R., Dixon, J., Dietrich, J., and McNeil, D.H. (2001 unpublished consultant report, pers. comm.), "Organic geochemistry and organic petrology of a potential source rock of Early Eocene age in the Beaufort-Mackenzie basin."

Bibliography

Graue, K., "Mud Volcanoes in Deepwater Nigeria," Marine and Petroleum Geology, Vol. 17, 2000, pp. 959-974.

The authors
Christopher L. Bergquist ([email protected]) is an exploration geologist with Devon Canada-Frontiers. He has worked 25 years in exploration and development, both clastics and carbonates. He started with Gulf Oil in the Gulf of Mexico, West Africa, and Canada, then consulted internationally, and currently is with Devon Energy in the Beaufort Mackenzie basin, where he has 10 years' overall expertise. He has a BA in earth sciences from Dartmouth College.

Peter Graham is geologist-frontiers with Devon Canada Corp. He has worked various plays in carbonates and clastics in Alberta, British Columbia, Northwest Territories, Yukon, and the Beaufort Mackenzie basin with Ranger Oil, Anderson Exploration, and Devon. He has BSc degrees in geology and zoology from the University of Calgary.

Dennis Johnston is a geologist-frontiers with Devon Canada. He has been employed with service companies and with Canadian Hunter Exploration Ltd. and Petro-Canada, working on the Western Canada basin, Canada east coast offshore, North Sea, Beaufort Mackenzie basin, and Alaska North Slope. He has a PhD from the University of New Brunswick, an MSc from Memorial University of Newfoundland, and a BSc from the University of Calgary, all in geology.

Keith Rawlinson is geophysicist-frontiers with Devon Canada Corp. He has worked various plays in multiple geologic and geographic environments throughout the world as well as Western Canada and the Beaufort Mackenzie basin. His main expertise areas are Tertiary basins and deltas from onshore to deep water environments. He has BSc degree in Engineering from Queens University in Canada.