Operating companies that have been active in Atlantic Canada have teamed up to speed drilling programs that could lead to additional production offshore Newfoundland and Labrador.

Though the Jeanne d’Arc basin is the only producing basin offshore Newfoundland and Labrador, there are several prospective areas where exploration efforts are ongoing. (Image courtesy of CNLOPB).

Though it is an out-of-the way area that has only three offshore fields in production, Newfoundland and Labrador is a region people are talking about.

Alan Brown, vice president of East Coast Canada for Petro-Canada, is one person who has positive things to say about Atlantic Canada. “Having come back here after 10 years away, I see a genuine and justifiable sense of optimism,” he said. “I think people see challenge and opportunity and not just near-term financial gain on the horizon.”

Some of that optimism is based on the agreement signed in late August to move forward with the Hebron field development. The new project on the books will bring more industry to the province and will add another producing field to the portfolio that today includes Hibernia, Terra Nova, and White Rose. For a small province in a remote harsh-environment area, one more development is big news.

The remote location, which initially looks like a liability, actually gives the region a competitive edge, Brown said, because it is a relatively new petroleum province. “Some folks might say that lack of longevity means we don’t know what we’re doing, but quite the opposite is true. I think we know exactly what we’re doing, and the beauty of it is that we have new things to do. We’re not trying to squeeze the last 3% to 5% out of a reservoir. What we’re doing is trying to optimize the first 35% to 40% recovery factor.”

As an operator in Newfoundland and Labrador, Petro-Canada has a unique position, holding a minimum of 20% in each of the producing fields in the Jeanne d’Arc basin. The company operates the Terra Nova field with 34% interest, holds 27.5% interest in White Rose, and is a 20% share holder in Hibernia. Petro-Canada has also secured 24% interest in the Hebron field. “We have a finger in all of the pies,” Brown said. “That gives us tremendous insight as to how the basin is performing.”

Performance, as it turns out, is a subjective thing. High production and high oil prices have made these fields sources of huge revenue flows for the government. That is a positive point, particularly in a province that has been known as a “have-not” part of the country since it became part of the confederation of Canadian provinces in 1949. The fact of the matter is, however, that the offshore fields are going into inevitable decline. “That’s a concern that can be addressed by optimizing the potential for near-field extensions,” Brown said.

White Rose, which has only been on production for two years, is already in decline, and Terra Nova is about 50% of the way through its production cycle. Hibernia, the oldest producer, is well below its peak production of 230,000 b/d. The good news is that reserves at Hibernia have increased since the original estimate and are now placed at about 1.2 Bbbl. Additional subsea wells will help offset Hibernia’s decline, Brown said, just as tiebacks to White Rose will extend its life. So far, for the most part, we are seeing the truth in the adage that big fields often tend to get bigger,” Brown said.

“A recent pickup at White Rose is a result of the step-out at North Amethyst and the White Rose extensions,” Brown explained. “We hope the extension will be online by late 2009. Hopefully, soon after, we’ll have the West White Rose extension online. Both will be produced through existing infrastructure. These subsea tiebacks are a huge investment in a very fast-track project, but they also provide the most efficient means of bringing this additional production onstream.” The challenges today are to fuel the development cycle and to maintain production.

Brown sees these challenges as opportunities that will allow his company to expand its presence in an area where it has sunk its roots. “It’s a great time to be here. Our story is a great story to tell.”

Ruud Zoon, who was vice president of East Coast Canada operations for Husky Energy until Sept. 15 has a similar view of the province, where Husky has been active for 20 years. According to Zoon, 25% of Husky’s global oil production comes from Atlantic Canada.

“This is a place for companies with deep pockets and a lot of guts,” Zoon said. “The risks here are significant, but for a company like Husky, this is a very good place to work. That’s why we’re spending lots of money here and why we have a very active program going forward.”

Most of the company’s recent activity has centered on adding production at White Rose, where three projects are ongoing. According to Zoon, 20 development wells have been drilled to date, but considerably more are needed. “The satellite program will require about 40 wells. We’ve only completed about one-third of the development wells in our portfolio.”

Though this ambitious drilling program offers considerable potential gains, the cost of bringing a rig to Atlantic Canada was an obstacle. Once again, adversity was turned to advantage, this time through an innovative approach to asset sharing that brought three operators together to solve the problem.

Rig sharing

Eric Abrahamsen, vice president of East Coast operations for StatoilHydro Canada Ltd., explained how the three operating companies reached the decision to contract jointly for a semisubmersible that would stay in the area for three years, working for all of the operators in turn.

“StatoilHydro acquired two new licenses in the Jeanne d’Arc basin a little over a year and a half ago,” Abrahamsen said, and a third license was added to the portfolio last year.

“Those two new licenses required seismic work, so last year we started planning for that,” Abrahamsen said. “Husky was interested in working with us, particularly because they had additional seismic they wanted to shoot on the White Rose area. So the program became bigger. We also approached Petro-Canada about a seismic program over Terra Nova.” The end result was a contract with CGGVeritas for a series of surveys in the region.

Successful cooperation on the seismic program made it easier to sit down and talk about rig sharing as well. “We have a timetable we wanted to meet for our drilling program that required spudding the Mizzen well in the Flemish Pass by early January, 2009,” Abrahamsen said. “The problem was that we only had one well to drill.”

Offshore Newfoundland is a high-cost environment, and moving a rig for one well was cost prohibitive. Just demobilizing and mobilizing a rig from the Gulf of Mexico was nearly equivalent to the cost to drill the well. “We saw that bringing back the Henry Goodrich would be advantageous for our plans on Terra Nova, where we would like to see another two wells drilled early next year,” Abrahamsen said.

The other operators had drilling programs of their own that would be more efficiently accomplished if a rig could be secured on a long-term contract. The decision, in the end, was obvious.

“Building trust was essential,” Abrahamsen said. “The hope was that a successful implementation of the seismic vessel-sharing arrangement would be the foundation for additional cooperative efforts in the region. That first success led to the joint contract on the Henry Goodrich.”

Together, the operators put together a team made up of their own representatives, along with those from the drilling contractor and service companies. This team will follow the rig from one operator to another throughout the two-year work program.

“I think that will be efficient and will facilitate all of the drilling programs because it is in everyone’s best interest to keep the rig at peak operating performance from one job to the next,” Abrahamsen said. “This is a great step forward.”