The pace of oil development off Canada's east coast is accelerating with two projects under way.
Onshore site preparation has been in progress for more than a year on a 55.2 billion (Canadian) project to develop Hibernia oil field on the Grand Banks off Newfoundland.
A number of major contracts have been awarded, and others will be let this spring. Fabrication of several major components, including a concrete gravity base structure (GBS), is about to begin. A work camp that will house 3,000 people is near completion.
The field, with reserves of 525-650 million bbl down from early estimates of as much as 1 billion bbl, is scheduled to go on production late in 1996.
First sustained commercial oil flow from a Canadian offshore field is to get under way this spring from the smaller Cohasset-Panuke project off Nova Scotia, 25 miles southeast of the Sable Island natural gas area (OGJ, May 6, 1991, p. 64).
Several other fields classified as significant discoveries on the Grand Banks-Terra Nova, Hebron, and Whiterose, for example-are still being evaluated as potential commercial producers.
Success of the $700 million Cohasset-Panuke development, known as the Copan project, will be watched closely as a pattern for smaller field development in the area.
It has taken 13 years for Hibernia, 196 miles east of St. John's, Newf., in water depth of 262 ft, to reach the development stage. Chevron Canada Resources Ltd. drilled the Hibernia P-15 discovery well in 1979. The first seismic surveys in the area were conducted in 1965 by Mobil Oil Canada Ltd., a lead partner in the development project.
Hibernia development was made possible now, despite uncertain oil prices, by a binding agreement between governments and commercial partners signed in September 1990 covering financial terms for the project. Ottawa is providing substantial assistance with grants and loan guarantees.
The project has been justified on the grounds of crude oil self-sufficiency for Canada in view of declining conventional onshore reserves and advances in offshore technology, as well as an economic stimulus for Canada's depressed Atlantic region.
Project development is supervised by Hibernia Management & Development Co. Ltd. (HMDC), formed by the four company combine of interest owners. HMDC is staffed by specialists seconded from the interest partners and by other staff hired for the project.
Participants are Mobil Oil Canada Properties 28.125%, Petro-Canada Hibernia Partnership 25%, Chevron Canada Resources 21.875%, and Gulf Canada Resources Ltd. 25%.
State owned Petro-Canada, which is in the process of privatization, wants to sell a minority share of its Hibernia interest.
Ottawa will not have a role in operation of the project but is contributing $1.04 billion in funding to the venture. Another $106 million in government funds will come from an offshore development fund shared by Ottawa and the Newfoundland government and an offshore technology transfer fund.
Government support, including federal loan guarantees of as much as $1.66 billion to the interest partners, will total about $2.7 billion.
That total likely will be reduced by an agreement signed between governments and companies last November under which commercial lenders will take some of the project financing risk.
As much as 25% of the debt guarantee provided by Ottawa, to a maximum of $415 million, may be replaced by project financing from a syndicate with Canadian Imperial Bank of Commerce as agent bank.
Operating costs during the 18 year life of Hibernia have been estimated at $10.6 billion. Another $3.5 billion will be spent to upgrade and replace equipment.
COMPANY COSTS, ROYALTY
Industry's share of costs includes $1.13 billion by Mobil, $1.004 each by Gulf and Petro-Canada, and $879 million by Chevron. The total preproduction cost is estimated at $5.163 billion. Each interest partner is working on the basis of their own project economics and oil price forecasts.
The group will pay Ottawa a net profits interest equal to 10% of net revenue, subject to oil price indexation. Payments will begin after repayment of all guaranteed loans and interest assistance loans.
The Newfoundland government will receive gross, net, and supplementary royalties under a three-tier structure.
Hibernia partners will pay contractual royalties and a nominal statutory royalty of 1ct/bbl, which is deductible from contractual royalties.
Each member of the combine will pay a production based contractual royalty. A gross royalty payable to Newfoundland will be 1-5% of their transfer revenue. Gross royalties will equal 1% of transfer revenue and will increase by 1% every 18 months to a maximum of 5%.
A net royalty equal to 30% of a group member's net transfer revenue from the project becomes operative at project payout. This occurs when total cumulative costs, including a return allowance of 15% for the project, equal cumulative gross transfer revenue. After payout, members pay the greater of 30% of net transfer revenue or 5% of gross revenue.
If crude prices are less than $30/bbl in 1987 U.S. dollars, the gross royalty will be reduced by the proportion that the price of Hibernia crude is less than $30/bbl. Indexation of the gross royalty will occur only during the years of repayment of the loans guaranteed by the federal government.
A supplementary royalty will be equal to 12.5% of a member's net revenue in addition to the 30% net royalty. Supplementary royalty will be calculated on the same basis as net royalty except that eligible costs will include a return allowance equal to 18% plus inflation.
PRODUCTION SYSTEM
The field will produce from two Cretaceous reservoirs-Hibernia sandstones at 11,483 ft and Avalon sandstones at 8,200 ft.
The production system will draw on North Sea experience and new technology using advanced computer assisted design systems and document imaging technology for engineering work. It will include the GBS platform, a crude oil loading system, subsea production facilities, and three double hulled, ice reinforced shuttle tankers to transport crude to an onshore terminal.
The GBS will be able to store 1.3 million bbl of crude, or almost 2 weeks of production.
An initial plan to offload crude from GBS storage to tankers using two articulated loading platforms has been changed. The general configuration will be retained but a submerged offshore loading system will be used. It consists of a base mounted on the sea floor and a riser to carry crude from the platform and through the system loading hose connected to the tanker.
The system is similar to the Ugland Kongsberg Offshore Loading System in use in Statfjord field off Norway.
Hibernia production will begin late in 1996 with a peak flow 110,000 b/d in 1998 and a maximum system design capacity of 150,000 b/d.
The massive gravity base and modules for the topside components will be fabricated at Bull Arm, Trinity Bay, on the northeast coast of Newfoundland about 93 miles northeast of St. John's.
The Bull Arm site will contain all facilities required to meet the needs of a fair sized, self-contained town. Construction is almost complete on accommodations for about 3,000 workers at Bull Arm.
A drydock scheduled for completion this spring will be used for initial construction work on the GBS. The system will have a total weight of 600,000 metric tons under tow and 1 million metric tons after ballasting.
Ballasting will require 185,000 cu m of concrete and 50,000 metric tons of reinforcing steel. It will be towed to deeper water after initial construction for completion to its full height. The gravity base system will have a height of 364 ft, diameter of 354 ft, and a 279 ft high caisson.
A special feature of the system will be 16 "teeth" built into the outer wall of the caisson to absorb the impact of icebergs. A ground wave radar system is under development at St. John's to provide early detection of icebergs. Once detected, tow vessels can divert icebergs from direct impact with the platform. Icebergs weigh 200,000-500,000 metric tons and can weigh as much as 1 million metric tons.
Concrete skirts 6 1/2 ft deep will be added to the underside of the base to enhance the stability of the platform on the seabed.
State of the art trailering and skidding technology will be used to handle components at the Bull Arm site to eliminate costly crane/lifting systems.
Construction of topside modules for drilling, processing, and accommodation is to begin in June 1992. HMDC will place orders for three shuttle tankers in April 1993. Plans call for three 120,000 dwt vessels, each with a capacity of about 700,000 bbl.
Completion and assembly of the topside modules is scheduled for April 1994. They will be mated with the GBS a year later. The completed base and modules will be towed to Hibernia field in August 1995.
The first of 83 development wells is slated for spudding in April 1996, with start of production the following October. Hibernia partners forecast a production life of 18 years from that point for the Hibernia reservoirs.
KEY CONTRACTS
HMDC has awarded several key contracts for the project. About 55-60% of total spending of $5.2 billion prior to production will go for Canadian goods and services, with much of the work allocated to Newfoundland companies.
Newfoundland Offshore Development Constructors (Nodeco) won a $1.2 billion contract for the GBS. Members of the Nodeco joint venture are Atlas Construction Inc., Montreal, Concrete Products (1982) Ltd., St. John's, Doris Engineering, Paris, Janin General Contractors Ltd., Montreal, and McNamara Construction Co./George Wimpey Canada Ltd., St. John's and Toronto.
A $360 million contract for topsides engineering, procurement, and project services went to Newfoundland Offshore Contractors (NOC). Partners in NOC are Aker Engineering AS, Oslo, BFL Consultants Ltd., St. John's, Brown & Root International Inc., Toronto, Monenco (Shawmont), Calgary, and SNG Group, Montreal.
A $350 million contract for design, procurement, and construction for the topsides site facilities and fabrication only of the wellhead module and topsides mounted components (helideck, flare boom, main lifeboat station, and auxiliary lifeboat station) went to the PLC-Aker Stord-Steen-Becker joint venture. Joint venture partners PLC Industrial Constructors Inc., Edmonton, Aker Stord AS, Steen Contractors Ltd., Toronto, and Becker Contractors Ltd., St. John's.
Components whose contracts are still to be awarded include four super-modules: process, mud, utility, and service/quarters; three topsides mounted components: east and west drilling derricks, drillers' office, and pipe rack; and the offshore loading system and pipelines.
GRAVITY SYSTEM
HMDC Pres. B.D. (Bobby) Kimberlin said Hibernia partners chose the GBS production system after studying a number of other options, including a floating system.
Kimberlin, formerly with Mobil North Sea Ltd., London, said the gravity system, well tested in the North Sea, is better for safety, concerns about operating in an iceberg prone area, and oil storage.
Preliminary design work on the gravity system was done by Doris Engineering. The work has now moved to Newfoundland.
Use of advanced document imaging technology permits engineering drawings to be worked at a number of locations, for different work groups to share information, and for all drawings to be updated to as built status as the work proceeds. A computerized project management system tracks procurement and engineering requirements.
Kimberlin said the modular design of the topsides units of the production platform eliminates the need for a main frame support, the first time this self-supporting design will be used in an offshore platform. The design eliminates the need for heavy lift systems and reduces the weight and costs for the project.
INNOVATIONS
R.D. Owen, general manager for the project, acknowledges that Hibernia is part of a Canadian offshore industry in its first stages compared with the North Sea, where more than 100 fields have been developed in the past 25 years. But he noted Hibernia will introduce a number of design and engineering innovations, such as the modular approach for topsides components.
Owen said, "Our original concept called for a topsides that consisted of a modular support frame and 16-20 smaller modules in the 1,000-2,000 metric ton range. The total weight of that topsides deck would have been about 44,000 metric tons, and the modules would have been installed by heavy lift crane barges.
"The current design is an integrated deck structure consisting of five main modules and seven smaller topside mounted structures. In essence, each of the five supermodules, joined together, forms the total structure of the topsides. However, they are fabricated as five individual modules that will each be substantially completed onshore at several fabrication facilities."
Owen said the new design will meet all requirements but will be about 9,000 metric tons lighter than the original proposal.
It will save money on structural steel, permit a high degree of inshore completion, and use of multiwheeled trailers instead of heavy lift equipment to install the supermodules on the assembly pier.
The project manager said Hibernia represents one of the most extensive applications undertaken in Canada of three dimensional, computer assisted design.
"By digitizing the engineering layouts, we are able to see our plans in 3D," Owen said.
"This enables us to achieve a clash-free design in the engineering phase and should lead to savings of time and cost during fabrication and construction. It also allows us to store and retrieve, alter, or otherwise manage the tens of thousands of engineering drawings in the form of computer data."
Another relatively new technology, document imaging, scans hard copy engineering drawings and other documents for entry into the computer system where they can be worked on, updated, or stored as data files.
Another system, an integrated project management data base, allows anyone authorized to work on the project, regardless of their location, to tap into the system and access the latest engineering and project management information.
The group expects to award contracts for the supermodules in April. Spending in 1992 will be about $1 billion, including the cost of materials and contracts for fabrication.
Some engineering work is behind schedule, and some of a 3 month time cushion built into the project at the start has been used up.
But the job is on schedule to complete facilities at the Bull Arm work camp by April.
Work on the gravity base drydock is essentially complete, and work has started on the concrete pour for the base skirts. Crews will start pouring concrete for the base in March or April.
COPAN PROJECT
Hibernia will be the largest offshore Canadian project undertaken for the foreseeable future. But the Copan project to develop Cohasset-Panuke fields will be the first to land a steady flow of crude.
Partners Lasmo Nova Scotia Ltd., a unit of Britain's Lasmo plc; and provincially owned Nova Scotia Resources Ltd. will produce first oil this spring. Initial cost estimates for development and production of about $565 million made in 1989 are reported to have increased since then.
The two fields are 5 miles apart and 25 miles south of Sable Island's gas fields off Nova Scotia. There are no immediate plans to develop Venture and other natural gas fields in the area because of a surplus of onshore gas.
Copan will produce from early spring to late fall to avoid winter storms.
The first production well was spudded last year. The 12 well development is designed to produce about 30,000 b/d of oil with a life of about 7 years and a high production to reserves ratio. Lasmo recently increased its estimate of recoverable reserves to 49 million bbl from 35 million bbl on the basis of a reappraisal of seismic and drilling data.
The adjacent Balmoral field also will be placed on production.
The Copan system will include the Rowan Gorilla III jack up rig as a drilling and production unit in Cohasset field, a loading buoy, storage tanker, and shuttle tanker.
Mobil drilled the Cohasset D-42 discovery well in 1973 and tested small amounts of light crude. A Cohasset step-out by Petro-Canada in 1984 tested condensate from six zones at a combined rate of 29,000 b/d. Shell Canada Ltd. drilled the Panuke B-90 discovery well, and Petro-Canada drilled a successful step-out in 1987.
Lasmo and the Nova Scotia government recently signed a royalty agreement for the project. The government will receive 2% of net profits in the initial years and 30% of net profits after payout.
OTHER FIELDS
Among other fields off eastern Canada, development of Terra Nova, Hebron, and adjacent fields are expected to follow the Copan project, subject to economics.
Petro-Canada found Terra Nova in 1984. It is 213 miles east of St. John's in 310 ft of water. Eight step-outs have been drilled. Petro-Canada, which is operator and has a 44% interest, said more delineation drilling may be required. Unitization negotiations are under way among interest holders, and partners continue studies of development costs.
Petro-Canada believes Terra Nova could go on stream as early as 1997, subject to government and Regulatory approvals. Development costs are estimated at $2 billion for an average production rate of 100,000 b/d for 12 years from reserves estimated at 300 million bbl.
Development would be based on floating production technology.
Norcen Energy Resources Ltd., Calgary, reports negotiations are under way with potential partners for development of Hebron field, about 23 miles from Hibernia.
Wayne Newhouse, Norcen senior vice-president, said the field could be placed on stream as early as 1995 with a $500 million development program. Newhouse declined to identify potential partners in the development but said the talks involve farmouts by working interest owners to other companies. The Norcen official said more drilling will be required to confirm seismic data.
The discovery well was drilled in 1981, and there has been no drilling on the structure since then. Partners in the original well were Gulf Canada Resources Ltd., Mobil, Petro-Canada, and Chevron. Norcen acquired Gulf's 20% Hebron interest in 1986.
There are no firm plans to develop Whiterose field, northeast of Hibernia. Bow Valley Industries Ltd., Calgary, a partner in Whiterose, said discussions are under way among participants to resolve ownership disputes.
Several successful delineation tests have been drilled in Whiterose since testing of the 1985 Whiterose N-22 discovery, which found an estimated 200-300 million bbl of reserves.
Bow Valley has a working interest of about 18% in the field. Other interests include Husky Oil Ltd., which recently changed ownership. Gulf, Petro-Canada, Mobil and Norcen also have interests.
Bow Valley shot 2,200 line miles of seismic surveys on the adjacent Breton block in 1990 and plans to drill there before yearend 1992. A floating production system is being studied for Whiterose.
While development off eastern Canada is moving ahead, exploration has fallen sharply in the past 3 years. That's because oil prices slumped, and federal incentive programs designed to promote frontier exploration were reduced or canceled.
Drilling amounted to an average eight wells/year, mainly on the Grand Banks, during 1980-88. The pace dropped to one well in 1989, one in 1990, and two wells last year.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
