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83-5E
EAST COAST
OFFSHORE
OIL AND GAS DEVELOPMENT
Prepared by:
Sonya Dakers, Lynne C. Myers
Science and Technology Division
Revised 7 August 2001
TABLE
OF CONTENTS
ISSUE DEFINITION
BACKGROUND
AND ANALYSIS
A. Exploration
1. A Historical Perspective
2. Environmental Impact
3.
Icebergs, Storms and Safety
4. Jurisdictional Disputes
B. Development
1. The Impact of Oil and Gas Development
2. Development off Nova Scotia
3.
Hibernia Development
a. Introduction
b. History
c. Recent Developments
4.
Other Development on the Grand Banks
CHRONOLOGY
SELECTED
REFERENCES
EAST COAST OFFSHORE
OIL AND GAS DEVELOPMENT*
ISSUE
DEFINITION
The discovery of important
accumulations of oil and natural gas in the east coast offshore region
promises major economic and strategic benefits to Canada.
In particular, two important
finds – the Venture natural gas field and the Hibernia oil field
– spurred unprecedented oil and gas activity in Atlantic Canada in
the 1980s in spite of a long-standing jurisdictional dispute between the
federal government and Newfoundland. In March 1984, the Supreme
Court of Canada ruled on the legal question of ownership, opening the
door for exploration to proceed but without Newfoundland’s agreement.
After further negotiations, a federal-provincial agreement on the
joint management of offshore oil and gas development, similar to that
already in place with Nova Scotia, was signed in February 1985.
Exploration and development
are bringing benefits to the region, for example, local employment, the
building of oil and gas transmission systems, and the construction, supply
and servicing of rigs and production platforms. However, they also bring
a number of potential problems. One is the safety of offshore drilling
activities, given the severe climatic conditions in which drill rigs operate.
Another concerns the socio-economic impact of oil and gas development
on the region in terms of demand for goods and services, infrastructure,
and employment and training. The pace of development will be crucial
in optimizing local business and employment opportunities and minimizing
disruption of services.
Conflicts between the new
oil and gas industry and the historically all-important fishing industry
will have to be resolved as will the effects of development on marine
resources.
BACKGROUND
AND ANALYSIS
A. Exploration
1. A Historical
Perspective
The widely accepted theory
of plate tectonics holds that the sedimentary basin off Canada’s
east coast was once part of Europe. Because this area apparently
shares a close geological link with the North Sea, it is not unreasonable
to find that it shares some of its hydrocarbon potential as well.
To date, the United Kingdom’s part of the North Sea alone has revealed
some 22 billion barrels of recoverable oil. These favourable
geological prospects prompted the start of oil and gas exploration off
the east coast of Canada in 1966. Although early drilling results
were not spectacular, there were numerous tantalizing “shows”
of oil and gas. The prospect of success, coupled with developments
in the North Sea oil fields, encouraged the exploration companies to return
year after year to continue their modest drilling programs.
The first well was drilled
on the Grand Banks of Newfoundland in 1966 and a show of natural gas was
found. The Scotian Shelf area off Nova Scotia was first explored
in 1967, the Gulf of St. Lawrence in 1970, the Labrador Shelf in 1971,
the East Newfoundland Shelf in 1974 and the Bay of Fundy in 1975.
Although many wells showed traces of oil and/or gas, the first major gas
field – the Venture field off Sable Island – was not discovered
until 1979. It is now estimated that Venture contains natural gas
reserves in excess of 72 billion cubic metres (approximately 2.5 trillion
cubic feet). On a national scale, in a country with established
natural gas reserves of 4 trillion cubic metres, this discovery may
not appear especially large; however, its location, in the one region
of Canada dependent on imported oil for most of its energy needs, is of
particular strategic significance.
The Venture discovery was
followed within months by the announcement that a significant oil field
had been found on the Grand Banks, namely the Hibernia field, which was
originally estimated to hold recoverable reserves of 175 million cubic
metres (1.1 billion barrels). With further delineation, this
estimate has since been reduced to approximately 140 million cubic metres
(884 million barrels). The discovery of Hibernia represents
a find of national importance, given the fact that established Canadian
reserves of conventional crude oil from the Western Canada Sedimentary
Basin are in decline.
News of Hibernia set off
a round of increased exploration activity in the east coast offshore region,
particularly in the Jeanne d’Arc Basin where Hibernia is located.
Whereas between 1966 and 1979, investment in the search for hydrocarbons
off Canada’s east coast totalled about $300 million, exploration
companies spent $442 million in 1981 alone. Coincident with the
Petroleum Incentive Program (PIP), put in place in 1982 and phased out
beginning in March 1986, companies spent $4.5 billion on exploration within
this region. Although only eight or nine wells were completed each
year between 1978 and 1982, a total of 21 wells were completed in 1983
and another 23 wells in 1984 when rig activity was at its peak.
Beginning in November 1986, the pace of activity slackened in response
to world crude oil price fluctuations, so that by the 1989 season only
two wells were completed. One resulted in a new discovery of
natural gas and oil. Canada Oil and Gas Lands Administration reported
that, as of 1989, the estimates of east coast offshore discovered resources(1)
were 258.9 million cubic metres (1.6 billion barrels) of oil and
condensate as well as 313.4 billion cubic metres (11 trillion cubic feet)
of natural gas. Only one well was drilled in 1990. Activity
rose slightly in 1991 with seven exploratory wells, five of them off Newfoundland.
The first five production wells were also drilled off Nova Scotia in that
year. No drilling activity off Newfoundland occurred in 1992 or
1993. Off Nova Scotia, three production wells were drilled in 1992
and seven in 1993. After a drought in drilling activity of about
four years, several companies announced plans to drill exploratory wells
in 1997. In 1999, three exploratory wells and four delineation wells
were drilled offshore Newfoundland and nine geophysical programs were
carried out. The renewed interest in the east coast offshore has
now expanded beyond the Jeanne d’Arc Basin to the Flemish Pass area.
Activity continued at a high level into 2000-2001, with seven geophysical
studies being carried out and two delineation wells and two exploratory
wells being drilled. The sale of new leases was brisk, bringing
the total outstanding commitment for exploration to $629 million for offshore
Newfoundland. Exploration offshore of Nova Scotia also continues,
with four exploration wells, two delineation wells and 12 geophysical
programs being completed in (fiscal year) 2000-2001.
2. Environmental
Impact
Although potential environmental
problems are of concern anywhere oil and gas development occurs, the fishing
grounds on the Grand Banks, the Scotian Shelf and the northern waters
off Labrador are especially vulnerable. The Hibernia region is also
an important fish spawning ground and fish larvae are known to be very
susceptible to even slight traces of pollution.
During the exploration phase,
drilling fluids, drill cuttings and water associated with oil and gas
deposits are released into the sea. Some of the additives contained
in drilling fluids are toxic to marine organisms. Control must be
exercised over the quantities and types of wastes released by exploration
operations if damage to the fishery is to be minimized.
A second major environmental
concern is the possibility of a well blowout. The potential for
serious environmental impact is reinforced by the severe winter weather
conditions and the presence in some areas of an impenetrable cover of
pack ice. Such conditions could delay efforts to cap a well, thereby
increasing the magnitude of environmental damage. In fact, two blowouts
occurred in the area in 1984 – in two gas wells being drilled in
the Venture field off Sable Island. The first well was brought under
control ten days after the initial incident in March 1984; the second
well, which blew in September 1984, was only permanently capped and abandoned
in July 1985. As predicted, weather conditions hampered attempts to assess
and to rectify the situation. It was fortunate that low-sulphur
gas, rather than crude oil, was flowing uncontrollably from the wells.
Environmental pollution
of quite a different nature has presented a problem in the North Sea and
could occur in the east coast region. Supply vessels and service
boats have been known to dump large chunks of unwanted machinery overboard
as they travel to and from rigs. This debris, lying on the bottom,
can damage fish nets dragged along the sea floor. In one instance,
it cost the oil companies $60 million to clean up a section of the North
Sea fishing grounds which had been littered with such garbage.
These environmental concerns
are not restricted to the exploration phase; they could be compounded
during the development and production phases. Strictly enforced
regulations and constant vigilance will be necessary if environmental
damage is to be minimized.
3. Icebergs, Storms
and Safety
Photographs taken with sophisticated
sonar “cameras” show deep trenches and furrows crisscrossing
the seabed off Canada’s east coast. Trenches up to 15 metres
deep, 200 metres across and three kilometres long bear mute testimony
to the passage of massive icebergs (known as iceberg scouring).
These icebergs, which can weigh up to 50 million tonnes and tower like
skyscrapers above the water, are one of the most serious threats to offshore
activities. The presence of icebergs and “bergy bits”
(smaller chunks of ice which have broken away from the main iceberg),
as well as fierce Atlantic storms featuring high winds, freezing spray,
snow and low visibility, testify to the extreme conditions under which
exploration and development are taking place.
February is a particularly
bad month for drilling, and there is some debate as to whether winter
operations should be allowed at all. The winter of 1982-1983, for
example, was exceptionally severe. The International Ice Patrol
reported 120 iceberg sightings south of 48°N in February 1983. The
average, since 1900, is nine for this month. One method used to
remove the threat that icebergs pose to drill rigs is to tow them away
from the general area of the rig. This becomes impossible, however,
when the presence of an iceberg near a rig coincides with high winds and
rough seas. Such a combination of conditions is not unusual and,
in fact, occurred in February 1983 when the West Venture rig drilling
in the Hibernia field found itself with about ten icebergs and many bergy
bits in the vicinity. Regulations call for the rig to cease drilling,
secure the drill hole, and move out of the area if icebergs come within
a red alert zone. The West Venture attempted to do this but, because
of rough seas, the ten anchors which keep it in place over the drill site
could not be pulled. None of the 84 people on board could be evacuated
by helicopter or by service vessel, due to the weather conditions.
Fortunately for all concerned, the storm passed; if necessary, the icebergs
could have been towed away and people could have been evacuated by helicopter.
This episode is indicative of the hazards of operating in the offshore.
A new type of drill rig,
which is dynamically positioned instead of anchored, was introduced in
July 1983 in an effort to alleviate some of the difficulties experienced
by the West Venture. The Sedco 710, a $150 million semi-submersible
rig, was custom-built in Japan in a joint venture between Petro-Canada
and Sedco Inc. of Dallas. Positioned over the drill hole by powerful
computer-guided thrusters, it is more mobile than the anchored rigs and
so can quickly move out of the way of icebergs.
Drilling rigs are equipped
with radar systems designed to locate and monitor the movement of icebergs.
When weather permits, overflights are carried out on a regular basis with
sightings being made visually and with radar. A high sea state decreases
the effectiveness of both types of detection; in bad weather, flights
often have to be cancelled. A third method of iceberg detection
involves vessel ice patrols. These depend on line-of-sight detection
and are therefore influenced by visibility and sea state.
A tragic accident early
in the course of offshore exploration brought home the dangers faced when
working in such a challenging environment. In February 1982,
severe weather conditions combined with other factors to cause the worst
disaster ever to strike the Canadian offshore oil and gas industry.
On 15 February 1982, the drill rig Ocean Ranger sank 280 kilometres
southeast of St. John’s, Newfoundland, in 85 metres of water.
All 84 crew members were lost in this tragic accident. The meteorological
records show that waves as high as 26 metres (85 feet) and winds as high
as 90 knots (104 mph) hammered the rig the day it went down.
A Royal Commission headed
by Chief Justice T.A. Hickman of the Supreme Court of Newfoundland investigated
the accident and issued its 400-page report in August 1984. It concluded
that a chain of events which included a severe winter storm, design inadequacies
and lack of knowledgeable human intervention caused the loss of the Ocean
Ranger and its crew. The rig capsized and sank after seawater had
entered the ballast control room through a porthole smashed during the
violent storm; this caused the ballast control system to malfunction.
The Commission concluded that, despite this occurrence, if the crew had
simply shut off the electrical supply and shut the deadlights (steel shields
designed to protect the portholes), the rig would have survived the storm.
Instead, the crew, who did not properly understand the ballast system,
reactivated it and thereby inadvertently let more water into the port
portion – leading to the eventual capsizing of the rig and loss of
the entire crew.
The Commission felt that
the ballast control system was too complicated, the crew inadequately
familiar with its operation, and the rig insufficiently equipped with
lifeboats and survival gear. In addition, testimony before the Commission
revealed inadequacies in the emergency evacuation training that crew members
had received. A second 693-page report, issued in July 1985, contained
70 recommendations on methods to improve east coast offshore safety.
Even before the Royal Commission
reports were issued, the federal and provincial regulations were changed
to strengthen the safety systems on drill rigs. All rigs are now
required to carry 200% lifeboat and survival suit capacity, and all employees
must take a Marine Emergency Duties course.
According to the federal
government, 85% of the recommendations had been totally or partially implemented
by April 1986. The last of the recommendations were implemented
with the passage of Bill C-58, An Act to amend the Oil and Gas Production
and Conservation Act, which received Royal Assent on 23 June 1992.
Despite these and other efforts to upgrade safety measures on oil drilling
rigs, the fact remains that the east coast offshore can present a very
inhospitable environment for human activities.
4.
Jurisdictional Disputes
The most contentious issue
which faced the east coast offshore oil and gas industry in its early
years was the question of who owns the offshore resources – the federal
or provincial government. Although the question of jurisdiction
varies from province to province, nowhere was it more contentious than
in Newfoundland.
The legal aspects of this
historical federal-provincial dispute are set out in some detail in the
archived Current Issue Review 80-8E, Offshore Mineral Resources:
Legal Aspects.
B. Development
1. The Impact
of Oil and Gas Development
Oil and gas development,
not exploration, will have the greatest impact on the economy and the
social fabric of Atlantic Canada in the coming years. Exploration
expenditure does affect the local economy to a great extent, and is more
likely to be seasonal and is much less “permanent” than the
development and production stages. Nonetheless, many of the issues
discussed in this section are applicable to the exploration phase as well.
To be very concise in quantifying
the future impact of oil and gas development on the Atlantic region, one
word will suffice – massive. As exploration increases and
gives rise to development and production, the local requirements for goods
and services will soar. The long list will include:
-
drill rigs, drilling
fluids and drill pipes;
-
food for the rig crews
and for supply ships and their crews;
-
engineering, geological
and biological researchers and their ships as well as their equipment
and provision needs;
-
warehouse facilities
and port facilities;
-
housing and schools
for the families of those working the rigs and supply vessels;
-
people and equipment
to supply essential meteorological information; and
-
new sophisticated communications
and data processing equipment.
This tremendous need for
human resources, goods and services provides an opportunity for the Atlantic
provinces to turn their economies around. But if too much expansion
takes place too fast, can the society cope with the changes? Can
local human resources fill the requirements of the new industry and can
local companies grow fast enough to meet demand? If development
comes quickly and demands cannot be filled locally, the oil and gas industry
will look elsewhere and the region will lose out on these opportunities.
There is also great interprovincial rivalry to capture as much of the
offshore service industry as possible.
The Province of Newfoundland,
for example, has a “Newfoundland first” policy whereby companies
are required by law to give preference to local labour, goods and services,
and local supply contractors where these are competitive in terms of price,
quality and deliverability. In addition, under current Newfoundland
regulations, future development plans must first be approved by the energy
minister and will then be thrown open to public scrutiny and debate.
There is even provision for a waiting period if development appears to
be moving faster than local capabilities can handle. Companies have
been complying with the requirements, and the participation rate for local
labour has been very high in some categories (varying from 55% for seismic
operations to 71% for support staff). The province carried out a
study entitled “The Economic Impact of Future Offshore Petroleum
Exploration,” identifying the areas in which the province could improve
its share of the economic impact and the means by which local participation
could be maximized. Two areas identified for further development
were the provision of infrastructure (port facilities and air bases) and
indirect services such as catering and electronic instrument servicing.
The potential for economic development in Newfoundland related to Hibernia
and other oil and gas development is tremendous. The Canada-Newfoundland
Offshore Petroleum Board reported that in the year 2000, spending related
to work in the Newfoundland offshore totalled $1.4 billion, bringing
the cumulative total since 1966 to $13.6 billion. At the end of
2000, a total of 3,100 people were employed directly in petroleum-related
activity, and 86% of them were residents of the province. Total
operating costs during the life of the project are estimated at an additional
$11.5 billion.
In Nova Scotia, the Canada-Nova
Scotia Offshore Petroleum Board (CNSOPB) is responsible for ensuring that
Nova Scotians and other Canadians have full and fair access to the employment
opportunities offered by offshore oil and gas development. Under
the regulations to the legislation that established the Board, any company
applying for work authorization must file a Canada-Nova Scotia Benefits
Plan before approval will be given. The efforts have proven successful,
with thriving petroleum-related businesses being established. Many
of these companies are members of the Offshore/Onshore Technologies Association
of Nova Scotia (OTANS). The goals of benefits plans have been met,
and even exceeded in some cases. For example, the Cohasset oil project
(discussed in the following section) – the first commercial offshore
oil project in Canada – reported that over its seven years of operation,
78% of the people employed were from Nova Scotia, 12.5% from other parts
of Canada and only 9.5% were non-Canadian. The Sable Island natural gas
project, also discussed in the following section, reports cumulative employment
to December 2000 as 54% Nova Scotian, 11% other Canadian and 35% non-Canadian.
2. Development
off Nova Scotia
The signing of the management
and revenue-sharing agreement between Ottawa and Nova Scotia in March
1982 gave Mobil Oil of Canada the green light to proceed with its development
plans for the Venture gas field. Under the direction of federal
and provincial government officials, Mobil prepared a socio-economic impact
statement (SEIS). The SEIS included a great deal of information
such as: a project description (offshore structures, pipelines,
the gas plant, etc.); the economic context of the project (regional population,
labour force, employment impact); projected land requirements; housing
implications; infrastructure and community service needs; and socio-cultural
implications. For each of these subjects, the company described
the existing situation, the anticipated impacts, and the possible mitigative
measures to minimize the project’s adverse effects or enhance its
positive effects.
There had been no guarantee
as to when production could start, even though a significant step was
taken in December 1984 with two agreements to sell Venture gas to utilities
in the northeastern United States. Although the Venture discovery
well showed great promise, disappointing results from delineation wells
cast a different light on the project.
In July 1985, Venture partners
Mobil Oil, Petro-Canada, Nova Scotia Resources and Texaco applied to the
National Energy Board (NEB) to export 8.5 million cubic metres per day
of natural gas to New England beginning in 1990. Nevertheless, the
Venture sponsors never finalized this application nor did they supply
the NEB with detailed reservoir data that would have confirmed a commercially
viable project.
The project remained stalled
at this stage until June 1995. Further exploration and delineation
had shown a projected three trillion cubic feet of recoverable gas reserves.
The project’s consortium then launched a pre-development assessment
of the Sable Offshore Energy Project – an expansion of the former
Venture project – and submitted a development application in the
spring of 1996. The consortium [composed of: Mobil Oil (50%);
the operator, Shell Canada Limited (35%); Imperial Oil Limited (9%); and
Nova Scotia Resources Limited (6%)] proposed to produce 400 million cubic
feet a day of gas and 20,000 barrels a day of natural gas liquids.
The first well in the project was drilled in the spring of 1998, and drilling
will continue over the next 25 years as the field is fully developed.
In early September 1999, laying of the subsea pipeline from the
location of the first production platform to the landfall at County Harbour,
Nova Scotia, was completed. Natural gas and natural gas liquids
pipelines to Cape Breton are also in place. The Point Tupper Fractionation
Plant and the Golboro Gas Plant are completed, and three offshore production
platforms are installed on-site. The Sable Island Offshore Project
began production on 31 December 1999, on time and on budget.
The natural gas produced from this area is serving markets in Nova
Scotia, New Brunswick and the northeastern United States via the Maritime
and Northeastern Pipeline, and its lateral lines.
A proposal to produce 30,000
barrels a day of light crude oil by mid-1992 from two small oilfields
at Cohasset and Panuke, west of Sable Island, received regulatory approval
12 September 1990. The $565-million COPAN project represented
the first commercial oil production off the east coast of Canada, bringing
with it 380 jobs a year during construction and another 260 during the
expected six-year life of the project. The original project leader,
Lasmo Nova Scotia Ltd., sold its 50% interest in the project to PanCanadian
Petroleum Ltd. in 1996. A Crown corporation, Nova Scotia Resources,
holds the remaining 50% interest. In July 1992, the first 500,000
barrels of light oil were shipped by tanker to Mobile, Alabama.
After its takeover, PanCanadian
continued exporting 500,000 barrels of oil twice a month to European and
U.S. buyers, drawing from the 18,000 barrels of light oil a day it was
pumping from nine wells. By late December 1999, the COPAN project
reached the end of its economic life. Original estimates had
projected that total production from the project would be about 35 million
barrels. However, improvements in technology over the life of the
project resulted in a total production of more than 44 million barrels
of light, sweet crude. The wells were decommissioned throughout
2000, but parts of the infrastructure will be kept for use in further
exploration work. In fact, discovery of a resource of one trillion
cubic feet of natural gas in a deeper structure at the Panuke site (hence
the project name Deep Panuke) is now being developed. Pan Canadian
plans to file its Benefits Plan and Development Plan Application with
the CNSOPB by the end of 2001, and to start production of 400 million
cubic feet/day by 2005.
3. Hibernia Development
a.
Introduction
Development of the Hibernia
field has presented certain unique problems. For one, Hibernia is
in the Grand Banks, an environment much more hostile than the area off
Sable Island. In addition, Hibernia is a deep-water development
(76-78 metres) compared to Venture’s 22 metres.
This makes the choice of production and transportation systems more difficult
and, it is estimated, three times as expensive for Hibernia. Venture
will involve the use of relatively simple off-the-shelf technology, while
Hibernia has required development of new technologies. Even so,
the Hibernia oil field began production in November 1997.
b. History
One of the first steps in
bringing Hibernia into production was the naming of a Federal Environmental
Assessment Review Office (FEARO) Panel in March 1985. The Panel
held public hearings on the Environmental Impact Assessment in October
and, in its report released in mid-January 1986, approved Hibernia development.
However, at the same time, the Panel set out 50 detailed recommendations
on how this should proceed.
On 24 June 1986, the Canada-Newfoundland
Offshore Petroleum Board approved the Development and Benefits Plans for
Hibernia. Negotiations on fiscal matters and on tax and royalty
levels began between Mobil and its partners, and the governments of Canada
and Newfoundland. The company sought a federal loan guarantee of
$1 billion.
On 18 July 1988, the federal
government announced the details of an agreement reached with the four-company
consortium to develop the Hibernia field. The deal involved a combination
of a $1.04 billion federal capital grant, a $1.66 billion federal loan
guarantee, $300 million in federal interest assistance, $175 million
in temporary financing, $95 million from the Canada-Newfoundland Offshore
Fund, and $11 million from the Newfoundland government along with
tax exemptions and tax reductions. The project was estimated to
cost $5.2 billion with an additional $3.3 billion required for production-related
spending. The target date of 31 March 1989 for finalizing the details
of the agreement was repeatedly postponed, and agreement was not achieved
until 14 September 1990. Production of 125,000 barrels a day
was originally slated to start in 1992 and last for 18 years.
In fact, Hibernia oil destined for the U.S. market finally began flowing
in November 1997.
The federal and Newfoundland
governments negotiated with the consortium to ensure that two of the five
newly-designed rig modules were built in Newfoundland. Newfoundland
would like to promote itself as an offshore-rig building centre.
The province eventually agreed that one rig module, instead of two, and
some ancillary work would be completed in the province. Much of
the work on the four other modules, worth up to $300 million, was
supposed to be set aside for Canadian companies. Newfoundland expected
to receive 10,000 person-years of work over the six-year construction
period. Federal Minister of Fisheries John Crosbie announced in
September 1991 that $3 million in training funds would go to prepare
Newfoundlanders for jobs on the Hibernia project.
Before federal legislation
authorizing $2.7 billion in grants and loan guarantees was passed
on 6 November 1990, interim financing of $95 million from the
Canada-Newfoundland Offshore Development Fund was obtained to meet the
September 1990 target for issuing construction tenders.
In November 1991, the federal
government negotiated an agreement with the consortium that provided for
25% of its loan guarantee to be picked up by private lenders if certain
economic criteria were met once production began.
Subsequent to project go-ahead,
one of the four members of the consortium, Gulf Canada Resources Ltd.,
put up for sale half of its 25% interest in the project. Then, in
February 1992, it withdrew from the project altogether. The consortium
was then made up of Mobil Oil, Petro-Canada, and Chevron Canada.
Mobil was contributing $1.1 billion, Petro-Canada $1 billion,
Chevron $879 million, and the federal government’s contribution
was $1 billion. Gulf’s promised $1 billion had, of
course, been withdrawn. So far, the consortium had spent $450 million.
Newfoundland and Canada
had agreed to indemnify the partners for 75% of their costs for proceeding
with the project beyond 15 May 1992 if a replacement for Gulf could not
be found and the project had to be shelved. On 15 January 1993,
the federal government announced that a new agreement had been reached.
Murphy Oil of El Dorado, Arkansas, would take 6.5%, Mobil Oil and Chevron
would increase their interest by 5%, and the Government of Canada would
acquire an 8.5% interest which would be held by the Canada Hibernia Holding
Corporation (a newly formed subsidiary of the Canada Development
Investment Corporation). The government was also offering the three
partners interest-free loans of up to a total of $132 million. The
project was now said to be viable at then-current oil prices of between
$20 and $30 a barrel.
In April 1994, Petro-Canada
announced a cost overrun of $1 billion and a delay of six months in the
construction schedule as a result of the project’s engineering design
complexities. NODECO (Newfoundland Offshore Development Constructors)
was replaced by Norwegian Contractors, a consortium that had been overseeing
NODECO since the fall of 1993.
In October, the management
company moved the electrical part of the offshore contract from Marystown,
Newfoundland, to the Saint John Shipyard in New Brunswick. This
resulted in 300-400 job losses for Marystown. M.I.L. Davie Inc.,
a competitor, disputed this decision, claiming it violated the Hibernia
Benefits Plan. The government of Canada announced in December that
no legal remedy was available in the case of such a violation. It
requested a review of the implementation of this benefits plan.
By the end of June 1997,
$5.4 billion had been spent on the project, of which $4.0 billion
was spent in Canada. About $2.6 billion of the amount spent
in Canada was spent in Newfoundland.
Shipyards in Korea and Italy
were awarded contracts to build four of the five supermodules – used
to house crew and drilling equipment – that sit atop the drilling
platform. The fifth was built in Newfoundland by a Canadian-Norwegian
consortium. (This $350-million contract is worth more than the other
four put together.) Pouring of the concrete for the base of the
drilling platform began in April 1993. Design changes and slow construction
delayed the schedule for towing the concrete and steel base to a deep-water
site. The original cost estimate of the gravity base of $1.2 billion
also rose by 30%. In the end, the modules in place on the assembly
pier were mated to the rig’s concrete base in early 1997.
On 23 May 1997, the
completed gravity-based structure began its nine-day tow 500 kilometres
to its final offshore location where it sat 224 metres high on the
ocean floor in 80 metres of water. Once installed on-site in June
1997, more than 400,000 tonnes of iron ore ballast were added to the gravity
base over a 30-day period. Installation of the offshore loading
system, which transfers crude oil to the tankers, took place at the same
time. Drilling of the first production well began on 28 July
1997 and the second well was started on 1 August. Production,
which will involve about 1,000 jobs, began on 17 November 1997.
The Hibernia project reached
another milestone in March 1998, when the Bull Arm construction site was
handed over to the provincial government for the sum of $1.00. All
parties had agreed that this handover would take place once Hibernia production
reached three million barrels of oil loaded on to tankers.
The three-million-barrel mark was reached in February. The site
has already been leased to a company that is building topside modules
for the floating production vessel to be used in the Terra Nova project
discussed below.
c. Recent Developments
By the end of the year
2000, a total of 22 wells had been drilled in the Hibernia reservoir –
12 production wells, six water injection wells and four gas injection
wells. In the calendar year 2000, a total of 52.8 million barrels
of oil were produced at an average rate of 144,653 barrels per day.
Another significant event
for the Hibernia site in 2000 was the start of limited production from
the Avalon Ben Nevis Reservoir which is located about 1,300 metres above
the Hibernia Reservoir, the site of all production to date.
This reservoir is a more geologically complex one; as a result, some
development work is still required to ensure that its full extent and
potential are known. Additional drilling is continuing in 2001 and
the Hibernia Management and Development Company will file a revised development
plan by the end of 2002.
4. Other Development
on the Grand Banks
In December 1995, a consortium
led by Petro-Canada announced it would be proceeding with the next major
Newfoundland development, the Terra Nova field, which is estimated to
contain 300-400 million barrels of oil. The project’s expected
cost is $4.5 billion, with production averaging approximately 115,000
barrels per day over a period of 15-20 years, starting in 2001.
Located 350 kilometres southeast of St. John’s, Terra Nova
is the second-largest oil reservoir on the Grand Banks after the Hibernia
field.
The development at Terra
Nova will make use of a Floating Production Storage and Offloading (FPSO)
facility, rather than a fixed gravity-based structure (GBS) which is being
used for Hibernia production. The choice of the floating system
was determined by three factors: more extreme weather conditions,
more numerous icebergs, and deeper water at the Terra Nova location.
Hull fabrication for the FPSO started in August 1998, at the Daewoo shipyards
in South Korea. The vessel, which would form the “shell”
of the completed FPSO, left Korea in December 1999 and arrived in Bull
Arm, Newfoundland in February 2000. At Bull Arm, the topside modules
were installed and all final equipment hook-up and commissioning took
place. This process was delayed for a number of technical and labour-related
reasons but was finally completed in the summer of 2001. In early
August 2001, the completed FPSO set sail from Bull Arm bound for the Terra
Nova field.
The level of activity in
the Newfoundland offshore led a number of oil companies to construct a
transhipment terminal at Whiffen Head, on the isthmus connecting the Avalon
Peninsula to the rest of Newfoundland. The facility, which began
with three tanks each with a capacity of 500,000 barrels of oil, receives
oil by tanker from Hibernia. The oil is stored temporarily and is
then taken away by second-leg tankers to market.
The first tanker unloaded
at Whiffen Head in October 1998. By March 2000, 72 tankers
had been received from the Hibernia field and the terminal had transferred
in and out approximately 45 million barrels of oil. Newfoundland
Transhipment Limited, owners of the terminal, announced in January 1999
that two additional 500,000 barrel storage tanks would be added, to accommodate
additional oil coming from the Terra Nova field. This Phase II
construction has been completed and a sixth tank is under construction
and expected to be in operation in May 2002. Even further expansion
is anticipated as other offshore reservoirs are developed.
As Terra Nova reached
the production phase, a development application was filed, in January
2001, for yet another Newfoundland offshore oil field – White Rose.
A consortium, led by Husky Oil, has plans for a $1.5-billion offshore
oil mega-project to tap the White Rose field, located east of Hibernia
and northeast of Terra Nova. The field has an estimated discovered
resource base of 283 million barrels of crude oil, along with 76.7 billion
m3 of natural gas and 15.3 million m3 of natural
gas liquids. Delineation drilling started in August 1999 and
is continuing. Public hearings on the application are underway
and a final decision on the development application is expected near the
end of 2001. If it is given the go-ahead, production could start
as early as the end of 2003. The White Rose development will
use the same FPSO technology as is being used at Terra Nova rather than
the more costly gravity-based structure (GBS) in use at Hibernia.
CHRONOLOGY
7 June 1966 - The first
well was drilled in Canada’s east coast offshore, on the Grand Banks.
Nov. 1978 - June 1979 -
Drilling at the Venture D-23 well off Sable Island resulted in a major
gas discovery. The Venture field was estimated to contain 72 billion
cubic metres (2.5 trillion cubic feet) of gas.
May-November 1979 - A major
oil discovery was made at the Hibernia P-15 well on the Grand Banks.
Subsequent drilling revealed an oil field containing an estimated 115
million cubic metres (720 million barrels) of oil.
12 February 1982 - The government
of Newfoundland submitted the question of ownership of offshore resources
to the Supreme Court of Newfoundland.
15 February 1982 - The drill
rig Ocean Ranger, working in the Hibernia field, sank with a loss of all
84 crewmen.
2 March 1982 - The “Canada-Nova
Scotia Agreement on Offshore Oil and Gas Resource Management and Revenue
Sharing” was signed.
March 1982 - The Canada
Oil and Gas Act was proclaimed, establishing the Canadian Oil and
Gas Lands Administration (COGLA) to administer development on Canada Lands.
The east coast offshore was included in the definition of Canada Lands,
angering Newfoundland, which also claimed ownership of offshore resources.
29 June 1982 - The Petroleum
Incentives Program Act received Royal Assent. This program provided
exploration incentives to companies meeting certain Canadian ownership
requirements and exploring on Canada Lands.
17 February 1983 - The Supreme
Court of Newfoundland handed down its ruling, stating that the ownership
of offshore resources rests with the federal government.
8 March 1984 - The Supreme
Court of Canada ruled that the federal government has jurisdiction over
the mineral and other natural resources of the Hibernia field off the
coast of Newfoundland.
30 June 1984 - Legislation
authorizing the Canada-Nova Scotia Agreement on Offshore Oil and
Gas Resource Management received Royal Assent.
11 February 1985 - Canada
and Newfoundland signed the Atlantic Accord, a long-term agreement on
the joint management of offshore oil and gas development.
30 October 1985 - A new
offshore tax credit regime of $150-250 million a year was announced.
17 June 1986 - The Canada-Newfoundland
Atlantic Accord Implementation (Newfoundland) Act received Royal Assent.
24 June 1986 - The Canada-Newfoundland
Offshore Petroleum Board announced approval of Hibernia Development and
Benefits Plans.
1 October 1986 - The Government
of Canada eliminated the Petroleum and Gas Revenue Tax.
25 March 1987 - The Canada-Newfoundland
Atlantic Accord Implementation Act received Royal Assent.
29 May 1987 - The Canada-Nova
Scotia Offshore Petroleum Resources Accord Implementation (Nova Scotia)
Act received Royal Assent.
21 July 1988 - The Canada-Nova
Scotia Offshore Petroleum Resources Accord Implementation Act received
Royal Assent.
February 1992 - Gulf Canada
Resources Inc. withdrew from the Hibernia project.
23 June 1992 - The Oil
and Gas Production and Conservation Act received Royal Assent.
15 January 1993 - The Government
of Canada announced an agreement to proceed with Hibernia under a new
partnership arrangement.
17 November 1997 - First
production of oil from Hibernia took place.
24 September 2000 - Hibernia
production passes 100-million-barrel mark.
4 August 2001 - Terra
Nova Floating Production, Storage and Offloading (FPSO) platform set sail
for the offshore field.
SELECTED
REFERENCES
“Canada-Nova Scotia
Agreement on Offshore Oil and Gas Resource Management and Revenue Sharing.”
2 March 1982.
Government of Newfoundland
and Labrador, Department of Development and Petroleum Directorate.
Economic Impact of Future Offshore Petroleum Exploration.
May 1981.
Reference Re Property
in and Legislative Jurisdiction Over the Seabed and Subsoil of the Continental
Shelf Offshore Newfoundland. Supreme Court of Canada, 8 March
1984, N. 17096, 61 pages.
Royal Commission on the
Ocean Ranger Marine Disaster. The Loss of the Semisubmersible
Drill Rig “Ocean Ranger” and its Crew, Report #1.
August 1984, 400 pages.
Website for Canada-Newfoundland
Offshore Petroleum Board – http://www.cnopb.nfnet.com
Website for Hibernia –
http://www.hibernia.ca
(1)
“Resources” are volumes of hydrocarbons, expressed at 50% probability
of occurrences that are deemed to be technically recoverable, but have
not yet been delineated and have unknown economic viability. “Reserves”
on the other hand, are volumes that have been proven by drilling, geophysical
data, etc., and can be recovered using available technology under current
economic conditions.
* The original version of this Current
Issue Review was published in May 1983; the paper has been regularly
updated since that time.
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