November 1997 Vol. 218 No. 11  Drilling/Production

Steven S. Bell,  Engineering Editor

Hibernia field presents technical challenges

Quoting from the president of Hibernia Management and Development Co. Ltd. (HMDC), “Hibernia is the pioneer development for the emerging Canadian East Coast offshore oil industry.” Indeed it is. At a pre-production budget of U.S. $4.4 billion, well costs of $1 billion and life field operating costs of $2.6 billion, for a total developing/operating cost of $8 billion, (excluding transportation), Hibernia is one of the costliest developments in the history of the oil industry. But HMDC owners Mobil Oil Canada (33.125%), Chevron Canada Resources (26.875%), Petro-Canada (20%), Canada Hibernia Holding Corp. (8.5%), Murphy Oil (6.5%) and Norsk Hydro (5%) believe it is worth the hefty price.

Hibernia field is located off the Newfoundland coast in 262-ft waters, Fig. 1. Its development design includes an innovative concrete gravity base structure (GBS, towed to location in June) that has a 50-ft thick ice belt that can withstand the impact of multi-million-ton icebergs. The GBS has 64 well slots, and it supports process and accommodation modules, two drilling rigs, a coiled tubing unit and two wireline units. It has the capacity to store 1.3-million bbl of oil in a 279-ft high caisson.

The field consists of two main reservoirs of early Cretaceous age—Hibernia and Avalon, Fig. 2. Total oil in place is estimated at just over 3 billion bbl (2 billion bbl for Avalon, 1.4 billion bbl for Hibernia), of which 615 million bbl are estimated to be recoverable. Also, the field contains about 3.5 Tcf gas in place, and all production that is surplus to fuel needs will be reinjected into the Hibernia reservoir.

Extended-reach drilling techniques will be used to access targets in both reservoirs, Fig. 3. A combination of waterflooding and produced gas reinjection will aid production and maximize recovery. Water injection capacity on the GBS is currently 150,000 bwpd, but can be upgraded to 225,000 bwpd. Production will average about 20,000 bopd from individual Hibernia field wells.

First oil is scheduled for December this year. Production will peak late in 1999 at 135,000 bopd and continue for about six years, accounting for 10–15% of Canada’s light crude output.

Reservoir development. The Hibernia sandstone is located at an average depth of 12,136 ft. It contains most of the field’s recoverable reserves—515 million bbl. Hibernia output is a high-GOR (1,200–1,700 scf/STB) liquid containing a light, sweet, 32–34°API oil, with a sulfur content by weight of 0. 4–0.6%, similar to West African crudes, such as Cabinda and Escravos.

The reservoir is a multi-layered sandstone with good lateral continuity, similar to Brent (North Sea) sands. Permeability averages about 500 md, with porosity ranging from 15 to 18% over a 197- to 262-ft net pay interval. All of the potential well locations can be accessed by platform wells with current extended-reach drilling technology. The most highly deviated wells are expected to exceed 29,500-ft measured depth and 19,600-ft horizontal displacement.

Monobore completions (5½ and 7 in.) will be installed for selected well conformance control, see Fig. 4. Reinjected gas will contact about 1/3 of the oil in place, while the other 2/3 will be waterflooded. Water and gas breakthrough are expected 1–4 years after initial injection. No artificial lift is anticipated.

The Avalon sandstone is a completely different situation. Highly faulted and laterally discontinuous, the formation is at an average depth of 7,872 ft. Initial development will rely on extended-reach platform wells, with several targets exceeding 24,600-ft horizontal displacement. These targets will be challenging due to shallow reservoir depths relative to the Hibernia formation. Sub-horizontal or multi-lateral wells will be used almost exclusively, with the possibility of subsea developments to reach some Avalon extensions.

The Avalon reservoir is also shalier than Hibernia, which increases the potential for diagenetic effects (calcite modules, precipitates). Permeability ranges from 100 to 200 md, and porosity from 18 to 20%. The entire formation will be waterflooded, although artificial lift will probably be required, with gas lift being the first option.

Results of appraisal drilling at Hibernia, along with 3-D seismic data, provided detailed information about the Hibernia reservoir, but limited insight into the complex stratigraphy of Avalon. While recoverable reserve estimates of 5% (100 million bbl) are conservative, and dedicated drilling will not begin until late 1999 or 2000, Avalon could contain significant upside potential.

Hibernia’s degree of success relative to its massive development costs will not be certain for a few years, but will likely depend largely on HMDC’s unique alliance with several companies, Fig. 5.

Goodbye. This is my final issue as Engineering Editor of World Oil. Nearly five years of editorial experience has been an extremely valuable tool for me. As a petroleum engineer with time served in the field, working for a major international oil and gas magazine has greatly enhanced my oral and written communication skills, which are critical assets to engineers today. Which is why I would encourage every engineer (or any other technical professional) that reads this column to write and present and/or publish at least one paper in their career. It’s a humbling experience at first (trust me, it helps to have an English or journalism major with good editing skills handy), but also a very rewarding one. It could help your career out in ways you cannot imagine.

Copyright © 1999 World Oil
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