Newfoundland and Labrador gear up for post-pandemic expansion
The outlook for Canada’s East Coast, principally offshore Newfoundland and Labrador (NL), has improved considerably during the last 12 months. At this time last year, the closure of Terra Nova field had been avoided at the last minute, yet, there was still no decision on re-starting the West White Rose development project, including finishing construction of its massive concrete gravity structure (CGS).
The turn-around begins. The Canadian government on April 6, 2022, approved the environmental assessment of the Bay du Nord development project, as recommended by the Impact Assessment Agency of Canada. Back in August 2021, the Impact Assessment Agency had concluded that the Bay du Nord development project, with appropriate mitigations, “…is not likely to cause significant adverse environmental effects….” But federal officials still evaluated the situation for another seven months. In early December, the federal government gave itself an extra 90 days to assess the project’s environmental impact. Then came another 40-day extension to mid-April. Thankfully, the approval came.
It should be noted that the federal government has been supportive of the offshore, particularly during the pandemic, when it provided C$75 million to the industry through the emissions reduction fund. That fund was managed by Energy Research Innovation NL. In addition to this, the federal government on Sept. 25, 2020, announced C$320 million in funding to be administered by the NL province, to support direct and indirect employment in the Newfoundland and Labrador oil and gas sector, and activities that generate environmental and co-benefits. This Oil and Gas Industry Recovery Assistance Fund provided $41.5 million in funding (50% of total costs) to maintain near-term jobs and protect the option of re-starting the West White Rose Project.
Thus, with Bay du Nord merely waiting for an FID from Equinor, and Terra Nova and West White Rose on track again, plus additional activity in existing fields and exploration drilling picking up, the short-to-medium term looks very promising for NL’s offshore sector.
“This is a really exciting time for the energy industry in Newfoundland and Labrador,” said Energy NL CEO Charlene Johnson. “I truly believe our province’s immense potential cannot be overstated.”
Geoff Cunningham, Vice President of Operations at A. Harvey & Company Ltd, which services offshore supply boats in St. John’s harbor, certainly agrees with that sentiment. “Certainly, things are a little more optimistic here, to say the least, versus the quick, negative turnaround we had with Hibernia stopping drilling, the Terra Nova FPSO going out of service, and all those things that occurred in 2020. Before all that happened, we were projecting a pretty positive outlook, and then the wheels fell off. But it certainly seems like things have turned around here.”
“We should begin to see a period of increased activity for the NL offshore,” concurs Paul Barnes, Director, Atlantic Canada and Arctic, at the Canadian Association of Petroleum Producers (CAPP). “Prior to the pandemic, there were over $4 billion in exploration work commitments in the offshore. Covid and the collapse in oil prices led to delays and, in some cases, cancelled exploration programs. But there is certainly a more positive outlook now for the industry, and we are seeing two exploration programs proceeding this year and expecting at least two more next year. Part of the reason for work proceeding is certainly the improvement in the markets (companies have capital to expend again), but the positive announcements recently on the Bay du Nord project and West White Rose likely play a part as well.”
A jolt from Europe. Also playing a role in the growth picture for NL’s offshore sector is the energy shortfall situation resulting from Russia’s invasion of Ukraine in February of this year. It has prompted new concerns in many countries about energy security and potentially could give Newfoundland a greater role in global oil supplies.
“There’s no question that the terrible events in the Ukraine and the whole European concern for supply has changed a lot of people,” noted Cunningham. “I think the general community is probably saying, ‘hmmm, we’ve got to be conscious of the fact that we need security of energy.’ There’s no question about that. But we’re still not sure what that means for us (NL).”
CAPP’s Barnes agrees. “Energy security has become a significant issue with the Russian invasion of Ukraine,” he notes. “NL exported oil to seven European countries last year, and demand is expected to continue increasing for the foreseeable future, even as we work to advance the role of other forms of energy, including renewables, in helping to supply some of that demand.”
With the above factors and thoughts in mind, what follows is an update on existing fields, ongoing developments, and exploration efforts throughout the NL offshore sector.
Offshore NL, the province has four developed oil fields. Hibernia, White Rose (including North Amethyst) and Hebron are producing oil, while Terra Nova is expected to resume production by the end of 2022. A fifth field, West White Rose, is under development, and a sixth field, Bay du Nord, is likely to be developed. Accordingly, provincial offshore oil production averaged 257,534 bpd in 2021, down 9.6% from 2020’s level. By comparison, first-half 2022 output averaged 244,087 bopd. This compares to the first full year of production in 1998, when Hibernia field averaged 65,000 bopd.
Bay du Nord. The Bay du Nord discovery, operated by Equinor (65%), is in the Flemish Pass, offshore Newfoundland and Labrador, Fig. 1. The Bay du Nord project consists of several oil discoveries in the Flemish Pass basin, some 500 km (311 mi) northeast of St. John’s in Newfoundland and Labrador, Canada. The first discovery was made by Equinor in 2013, followed by additional discoveries in 2015, 2016 and 2020.
During June 2022, bp became Equinor’s partner in the core field, when it acquired the 35% interest held by Cenovus Energy. Confirmed discoveries during 2020 in adjacent exploration license EL1156, Cappahayden (Equinor, 60%; bp, 40%) and Cambriol East (Equinor, 60%; bp, 40%) are potential tie-ins in a joint project development. The Bay du Nord discovery is at a water depth of approximately 1,170 m (3,838 ft), while the new discoveries are at an approximately 650-m (2,133-ft) water depth.
Equinor is considering developing the Bay du Nord field, using an FPSO (see rendering on first page) that also is suited for tie-back of adjacent discoveries and future prospects. The operator says that “optimization of the Bay du Nord development project is ongoing to make it more robust for future market and evaluation, to include the confirmed new discoveries” at Cappahayden and Cambriol East in adjacent license EL1156. Two additional wells have been spudded this summer at the Cambriol East and Sitka sites. For details on these wells, please see the Exploration Drilling section of this article.
Back on April 6, 2022, the Government of Canada approved the Bay du Nord environmental assessment. This clears the way for Equinor to make a final investment decision (FID) on the project. Equinor has said they will make a FID decision in the next couple of years.
West White Rose. To the relief of many professionals in the NL offshore industry, operator Cenovus Energy announced on May 31, 2022, the restart of the West White Rose Project in the Jeanne d’Arc basin.
Readers may recall that major construction was halted during March 2020, including work on the concrete gravity structure (CGS), due to the Covid 19 pandemic, Fig. 2. The project was later placed under review. During this period, operator Husky Energy combined with Cenovus Energy (effective Jan. 1, 2021). The combined company now operates as Cenovus Energy. Current ownership of the field is Cenovus (56.375% and operator), Suncor (38.625%) and provincial firm OilCo (5.0%).
“While the project was in preservation mode for much of the interval, we were able to progress certain scopes of work, including completion of the helideck, flare tower, living quarters and lifeboat stations at the Kiewit Offshore Services yard in Marystown, NL,” said a Cenovus spokesperson. Those components were shipped to Kiewit’s facility in Ingleside, Texas, during September 2021 for eventual integration with the main topsides structure, which is being fabricated in that yard.
Work preparing the sites for a complete restart is underway, with full construction due to resume in 2023. This would include completing the concrete pour for the concrete gravity structure (CGS) in the assembly yard at the Port of Argentia. First production from West White Rose is now forecasted for 2026.
Terra Nova. Discovered in 1984, Terra Nova was the second oil field to be developed on the Grand Banks offshore Newfoundland. Terra Nova is situated about 350 km (217 mi) southeast of the NL coastline. Production from the field began in early 2002, using the Terra Nova FPSO vessel, Fig. 3. This was the first development in North America to use FPSO technology in a harsh weather environment, featuring sea ice and icebergs. In its first year of output, beginning Jan. 20, 2002, Terra Nova produced 111,183 bopd from six wells. In comparison, during its last year onstream in 2019, the field produced just 6,065 bopd over 352 days, with several wells producing intermittently.
The last three years have been a tumultuous period for Terra Nova field and its namesake FPSO. Back in May 2019, the Terra Nova joint venture owners (Suncor Energy, 37.675%; ExxonMobil Canada, 19%; Equinor, 15%; Cenovus Energy, 13%; Murphy Oil, 10.475%; Mosbacher Energy, 3.85%; and Chevron, 1%) approved plans to repair and upgrade the FPSO, extending the vessel’s productive life to approximately 2031. Accordingly, production at Terra Nova was halted during December 2019, and the FPSO was taken off station and moored temporarily off NL, before traveling to its scheduled upgrade at drydock in the Ferrol, Spain, shipyard.
Yet, various challenges nearly cancelled the project. In particular, the Covid-19 pandemic caused a work stoppage at the Spanish shipyard. By late 2020, when work per the original timetable should have been completed, the vessel was still moored in the water near St. John’s in a dormant state. There were great fears in the St. John’s oil and gas community that Terra Nova might be abandoned and never produced again.
However, in June 2021, such a fate was avoided, when a last-minute restructuring agreement saved the field and its FPSO. As part of the agreement, the number of interest-holders was pared down to just three, including Suncor (48% and operator), Cenovus Energy (34%) and Murphy Oil (18%). Most importantly, the agreement set a course for potential restoration of production at Terra Nova.
Accordingly, in September 2021, the new ownership group finalized its new structure, as well as agreeing to move forward with the Terra Nova Asset Life Extension Project (ALEP), which is expected to extend production life by approximately 10 years and produce an additional 70 MMbbl of oil for the partnership. “The Asset Life Extension Project has the potential to provide many benefits to the economies of both Newfoundland and Labrador and Canada in the form of taxes, royalties and employment,” said a Suncor spokesperson.
The FPSO underwent maintenance work at Bull Arm, NL, in late 2021, prior to sailing to dry dock in Ferrol, Spain. A safe return to operations is anticipated before the end of 2022.
Hibernia. Canada’s first offshore oil field continues to produce reliably from wells tied to a gravity-based structure (GBS) platform, 25 years after it achieved first oil in 1997, Fig. 4. Discovered in 1979, Hibernia Field is situated about 300 km (186 mi) east southeast of St. John’s, Newfoundland and Labrador. During the last two months of 1997, when Hibernia first went onstream, output was 28,272 bopd from two wells. In its first full year of output, the field produced 65,206 bopd from eight wells. By comparison, in the first half of 2022, the veteran field averaged 114,812 bopd from 37 active wells. The shareholders of the operator, Hibernia Management and Development Company Ltd. (HMDC), include ExxonMobil Canada (33.125%), Chevron (26.825%), Suncor (20.0%), Canada Hibernia Holding Corporation (8.5%), Murphy Oil (6.5%), and Equinor Canada Ltd. (5.0%).
HMDC continues to complete drilling rig upgrades and refurbishments which will address obsolescence, enhance the platform’s capability and increase its reliability. It will position HMDC to potentially unlock resources that could enable more than another decade of drilling operations. “HMDC is increasing Hibernia drilling capability through automation and remote support technology, which will enable access to more resources and keep Hibernia competitive for future investment,” said an HMDC spokesperson.
On June 24, 2022, the staff of the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) updated the most likely Estimated Ultimate Recovery (EUR) for Hibernia field. The proven and probable (2P) EUR for Hibernia field is now 1.812 Bbbl of oil, based on data acquired from drilling and production activities along with an updated, long-term drilling schedule. The previous 2P EUR from 2014 was 1.644 Bbbl.
White Rose. Per an announcement made last fall, and contingent upon the restarting of work on the West White Rose project (which occurred on May 31, 2022), Cenovus has announced that it will reduce its stake in the original field, White Rose, to 60% from 72.5% and to 56.375% from 68.875% in the satellite extensions. Suncor increased its ownership in White Rose from 26.125% to 38.625%. The Newfoundland and Labrador government holds the remaining 5% interest.
Discovered in 1984, White Rose field sits approximately 350 km (217 mi) southeast of the Newfoundland coast, on the eastern edge of the Jeanne d’Arc basin, and is approximately 50 km (31 mi) from both Terra Nova and Hibernia fields. Following the example of Terra Nova field, White Rose is the second harsh environment development in North America to use an FPSO vessel, the SeaRose, Fig. 5.
White Rose went onstream during November 2005 and produced 49,317 from three wells over a 50-day period. By comparison, during 2021, the last year for which complete information could be found, the field produced 15,819 bopd.
North Amethyst. In 2003 and 2006, exploration drilling in and around White Rose field led to the discovery of a new accumulation, North Amethyst. It also resulted in an increase in understanding of two oil pools that are part of the existing project: West White Rose and the South White Rose Expansion.
North Amethyst represents the first satellite expansion to the White Rose project and was estimated, by the Canada-Newfoundland and Labrador Offshore Petroleum Board, to hold 68 MMbbl of oil. Located approximately 6 km (3.7 mi) southwest of the SeaRose FPSO, North Amethyst is also the first near-field tie-back offshore Canada.
Oil first began flowing from the site on May 31, 2010, from a single well. That well went on to average 2,325 bopd for the balance of that year. A second well came on in September 2010 and averaged 787 bopd for four months. By comparison, C-NLOPB figures indicate that production from North Amethyst during the first half of 2022 averaged 4,474 bopd from six active wells.
On April 26, 2022, the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) updated its most likely Estimated Ultimate Recovery (EUR) for North Amethyst. Last updated in 2018 at 64 MMbbl of oil, the EUR for the entire accumulation is now estimated by the C-NLOPB to be 70 MMbbl of oil.
Hebron. This oil field sits in the Jeanne d’Arc basin, 340 km (211 mi) southeast of St. John’s. The field was first discovered in 1980, and it is estimated to be capable of producing more than 700 MMbbl of recoverable resources. The water depth at Hebron field is 93 m (305 ft). Ownership includes ExxonMobil Canada (35.5%), Chevron (29.6%), Suncor (21%), Equinor (9%) and provincial firm OilCo (4.9%).
The platform’s gravity-based structure (GBS) consists of reinforced concrete, designed to withstand sea ice, icebergs and meteorological and oceanographic conditions. The GBS is designed to store approximately 1.2 MMbbl of crude oil. Bull Arm was the primary construction site for the GBS. It supports an integrated topsides deck (Fig. 6) that includes a living quarters and facilities to perform drilling and production. A substantial portion of the topsides was engineered and fabricated in NL, and the integration was performed at the Bull Arm site.
Construction of the GBS began in 2012, and the structure was towed out from drydock to a deepwater construction site during 2014. The completed platform was towed out to the field site in 2017, and first oil was produced later that year, with output averaging 22,270 bpd over 35 days. During its first full year of production, Hebron averaged 61,692 bopd, compared to 134,346 bopd during first-half 2022. In 2020, the Hebron platform and field achieved 1,000 days of production, and the 100-millionth barrel of oil was produced.
“In 2021, we expanded on the original success of the Hebron Onshore Control Room and are now fully operational from onshore,” said an ExxonMobil Canada spokesperson. “In addition to the remote drilling support center, we now have eight positions (16 people) supporting Hebron from onshore. This enabling technology provides greater flexibility and increases opportunities for technicians, who may not have been in a position to travel offshore, to now support our operations.
In line with higher oil prices and an improved regulatory outlook for the province, exploration drilling activity offshore NL is set to expand. Already this year, Equinor has spudded two additional wells this summer at the Cambriol East and Sitka sites. In early June, an appraisal well was spudded on behalf of Equinor by Seadrill’s West Hercules semisubmersible (Fig. 7) on the Cambriol discovery. The well was completed on July 24 without further comment. Two days later, the same rig spudded the Sitka O-02 exploration well at the Sitka prospect and was drilling ahead, as this article was being prepared during first-half August.
Meanwhile, in line with its plans to drill one exploratory well offshore NL in second-half 2022, ExxonMobil Canada spudded the Hampden K-41 wildcat in early July under EL1165A, re-entering an earlier well that the company had started drilling in May 2020, but which it had not completed at the time. Back in November 2021, Stena Drilling signed a contract with ExxonMobil Canada for use of its Stena Forth drillship for this particular well. The drillship was mobilized from a previous drilling assignment in the eastern Mediterranean Sea. ExxonMobil Canada, as this article was being finished, had completed the well and advised it will evaluate the results from the drilling program to determine next steps.
At the same time, other exploration drilling projects are on the horizon. BP proposes to conduct an exploration drilling program within four exploration licenses (ELs) in the West and East Orphan basins. Located between 343 and 496 kms offshore NL, exploration drilling could begin as early as 2023 with a single well, pending regulatory approvals. bp is said to be sitting on one of NL’s largest offshore prospects, called Cape Freels locally and known within bp as Ephesus. If oil is struck in this area, the reservoir size is expected to be roughly the same as Marlim field, offshore Brazil, which is about 2.8 Bbbl. If that happens, says Energy NL’s Johnson, “it has the potential for four FPSOs in one area.”
Also on the horizon, potentially, is Woodside Energy drilling a wildcat. The parcel in question was held by BHP Petroleum, which had been going through a merger that was just completed earlier this year. Accordingly, not much has been said by Woodside, although the original plan was to drill an exploration well at some point during 2023. It should be noted that BHP had bid the highest amount of money for any offshore parcel in NL’s history—C$621 million.
SEISMIC PROGRAM/LEASING ROUNDS
For more than a decade, a wide-ranging seismic acquisition program has been carried out for the province by PGS and TGS through the auspices of provincial firm OilCo. Over this timeframe, TGS and PGS have spent a combined C$500 million in NL’s offshore. According to Energy NL, the program has produced leading geophysical data and has allowed significant understanding of the world-class prospectivity offshore NL. It is the association’s belief that the data available through the seismic program have led international companies to commit to over $4 billion in investment in NL’s offshore during the last six years.
On Jan. 6, 2022, the NL provincial government announced that it would “pause” the program. NL Premier Andrew Furey and provincial Minister of Industry, Energy and Technology Andrew Parsons explained that the province has a backlog of data to go through, and that there is enough data available to support some upcoming bidding rounds. Furey and Parsons assured the local industry that this would only be a pause and not a cessation. They declared that this pause in the seismic program would save C$20 million in the provincial budget.
There is hope in St. John’s that the provincial government will restore the program sometime in 2023, especially given the excellent track record of seismic data leading to good lease sales and awarding of promising exploratory blocks.
OilCo CEO Jim Keating showed the worth of the NL seismic program last June when, during his speech to Energy NL’s annual conference in St. John’s, he suggested that three or four new producing fields are possible within the next 10 years. He particularly extolled the virtues of a new prospect called Blue Jacket, in which several operators have expressed interest. Keating referred to Blue Jacket as possibly being the next Bay du Nord, calling it “a prospect like no other.” Additionally, Keating said Blue Jacket is one of 20 prospects discovered during the NL government-funded seismic program over the last decade that have 1.0-Bbbl potential.
Leasing rounds. Currently open, the 2022 East Coast Canada Call for Bids (lease sale map in Fig. 8) is expected to emulate the success of the recent Eastern Newfoundland bidding rounds, according to seismic/geophysical firm TGS. Since 2018, over C$1 billion of successful bids have been submitted in this region by several exploration companies.
TGS says that in partnership with PGS, it holds the most comprehensive collection of subsurface data covering acreage being offered in the Newfoundland bidding round areas. These data include 2D and 3D seismic data, interpretation studies and well data. The Long Range 3D, Tablelands 3D, N. Tablelands 3D, NE Newfoundland 3D, and the newly acquired Cape Anguille 3D cover highly prospective parcels of the 2022 Eastern Newfoundland bidding round area. A comprehensive 5X5 km grid covers highly prospective parcels of the 2022 South Eastern Newfoundland bidding round area.
The 2022 call for bids will close in November 2022, with licenses to be awarded to successful bidders in January 2023.
A FAR LOOK FORWARD
While there is little doubt that the NL offshore sector can look forward to a growth spurt in the next several years, it does leave open a question about the longer-term future. We find that there are variable opinions as to what could happen.
Energy NL’s Johnson remains highly optimistic. “Our province has an abundance of developed and undeveloped energy resources,” she notes. There is immense global interest in not only our lower-carbon oil and gas product, but also in our potential for wind, hydrogen, hydroelectricity, biomass, solar, and wave/tidal resources in the province. Newfoundland and Labrador has the experience and expertise in the energy industry, and we are ready to leverage our global opportunities, as we strive to be leaders in the renewable energy evolution.”
At A. Harvey & Company Ltd, Cunningham is trying to remain optimistic for the long term. “As a company, we’re taking a cautious view for now. We’re really not sure whether this whole transition is going to overshadow the continuing need for oil and gas. We certainly think that oil is going to be around for a long time, but we’re just a little concerned about what our role in it is going to be as a province.
“What’s after Bay du Nord is ultimately my question.”
We also asked CAPP’s Barnes about the fact that when environmental approval of Bay du Nord was announced, Steven Guilbeault, the federal Minister of Environment and Climate Change, strongly hinted that it might be the last federal approval for an oil project offshore NL, given increasingly tight environmental regulations. Is this, we asked, a significant concern, and if yes, what can the NL government and offshore industry do, to counter potential federal resistance to additional projects?
“We look at this as an opportunity, rather than a challenge or concern,” said Barnes. “Bay du Nord has proven that NL can develop project concepts that can meet the federal government’s expectations and help contribute to Canada achieving its climate commitments, while working to help provide responsibly produced energy to the world. If we can do it with that project, and I believe NL can, then we can do it again, which points to a very bright future for the province. We don’t think this is about federal government resistance.
“We have to work together,” continued Barnes, “industry, and both levels of government—to come up with collaborative solutions to the challenges facing this country and the world. Our industry sees itself as part of the energy transition. We are working on technology and innovation to reduce emissions from our own operations, and our industry is investing in renewables and other energy forms. It will take all of us, working together, to reach Canada’s true potential as a leader in the global energy evolution.”
Editor’s note: This article is the latest installment in a partnership between World Oil and the Atlantic Canada Opportunities Agency, dating back to second-half 2015. Look for additional articles in future issues.
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