An arctic oil and gas symposium Tuesday heard calls for regulatory changes when the Northwest Territories government assumes responsibility for resource development from the Canadian federal government April 1.
Ken Hansen, a project manager for Husky Oil Operations Limited, expressed some of the frustration shared by companies that have been exploring the Canol oil shale in the Central Mackenzie Valley.
Last week, he said, Husky submitted a regulatory application for its next four-well drilling program.
“It has taken us over a year to prepare the damn application and that’s not even to do any real work,” Hansen told the conference sponsored by CI Energy Group. “It’s an absurd process.”
For Husky, “one of the frightening things for us is that this process of drilling a couple of wells a year seems to be overwhelming the regulatory process,” said Hansen, project manager, Slater River, N.W.T.
“There are 40 different agencies that review these applications -- and that’s called the preliminary screening,” he said. “Anywhere else in the world that would be a full regulatory review.”
On Husky’s part, “we are putting in a huge amount of effort to just try and prove that we have a play that could have some economic merit,” he said. Husky has already spent $160 million on the project, the conference heard.
“This is an exploration play,” Hansen emphasized. “This is not a proven play; we don’t even have proof of concept that we can actually flow oil.”
Husky acquired two licences (since consolidated into one licence) in 2011 and within a year had negotiated an access and benefits agreement, done a traditional knowledge study, drilled two vertical wells (2011-2012) and shot a 3D seismic program. In 2012-13, it went back and completed the two wells, fracturing one and flow testing both.
This year, Husky has been building an all-weather road that it believes is essential if it is to be able to have access for up to eight months of testing.
In a panel discussion, speakers emphasized the need for a more efficient regulatory process. “This whole process is so stretched out,” said Hansen, noting that ConocoPhillips had eight months of review after its application was approved by the Sahtu Land and Water Board.
He believes the process could be contracted and still do a proper job. “It’s not that you are cutting short the process, it’s not that you are not getting a proper review of the application.”
To move from exploration to development, industry needs a clear path forward, said John Hogg, vice-president of exploration and operations at MGM Energy Corp. “It’s going to take a long time for any of us to get to the point of saying we are ready to develop this play but we can’t have the process change in the middle,” he said.
“We can’t have continuous change because it takes too long for us to put our plans together if there’s change in the middle of it -- if in two years, or three years or five years there is additional change it really does upset our ability to work through.”
Operators also need a clear understanding of what an environmental assessment entails and a timely outcome to the process if they are expected to participate in it, said Hogg. After drilling and testing a vertical well in 2012-2013, MGM chose not to drill a horizontal well in the N.W.T. this winter, pulling the application when it was sent for an EA because it does not believe an EA should be required at the exploration stage.
“We continue to hear from northerners that all these projects should be sent to environmental assessment,” said Hogg. “My question is: ‘What do you expect to get from an environmental assessment?’”
Companies already file a project description (in MGM’s case more than 1,000 pages) that includes all the chemicals that will be used, the various processes and how the land and subsurface will be protected, he said. That document is then reviewed by more than 25 territorial and federal agencies that are staffed with professional engineers, geoscientists and biologists, Hogg told the conference.
“The professionals who work in these agencies are very good at their jobs,” he said. “I trust as a Canadian that when they approve a project they are approving it on the grounds that it is safe and it can be done.”
If a mining company is doing a five-well diamond drill-coring program, it does not get sent to an EA, Hogg pointed out. “I get sent to EA when I am doing a mine and that’s because at that point I am going to affect the environment.”
Oil companies don’t yet know if they are going to build their “mine” and putting them in that process will take two to three to five years out of their timelines in being able to decide whether the Canol project is going to work, according to Hogg.
Aaron Miller, northern Canada manager for the Canadian Association of Petroleum Producers, echoed those concerns. While the Northwest Territories has immense potential, “capital is very fickle and it is very fearful,” he said. “That’s why it is very, very crucial right now to allow our explorers to assess the viability of the resource without premature environmental assessments.”
Miller emphasized that while CAPP is not opposed to environmental assessments, “we firmly believe they should be placed in the right place.” For the association, EAs would be warranted after companies have determined a play has the potential to be commercially viable and is about to begin development. “That’s when there could very well be legitimate public concern or concern over the environment,” he said.
In the meantime, the oil industry’s contribution to the economy is continuing to grow in terms of government revenue and benefits to local communities, the conference heard. Industry forecast investment for 2014 is $700 million, up from $500 million in 2013 and $100 million in 2012, said Miller.
Both Hogg and Miller also pointed to the need for concurrent discussion about market access if the play works out. The existing Enbridge Inc. oil pipeline out of Norman Wells would not be large enough for any significant volumes and a natural gas and potentially a liquids line also would be needed. “The last thing we want to do is get ready for development and then start talking about a pipeline,” said Hogg.
As exploration picks up, other improvements are needed such as a permanent waste disposal site in the Northwest Territories, along with better roads, said panelists.
At present, flowback water is stored in tanks and then trucked or barged to permanent waste disposal facilities in Alberta and British Columbia, the conference heard.
“This is the largest safety risk within our program that we have identified,” said Eric Hanson, supervisor, Central Mackenzie Valley, for ConocoPhillips.“It’s trucking the fluid from our program site, down the winter road, back into Alberta or British Columbia for disposal.”
As for roads, ConocoPhillips effectively has access to the winter road for six weeks and if fracturing equipment it has brought in from Alberta is stranded in the region when the road closes, it would cost millions of dollars to have it barged out, he said.
Hanson also suggested there is a role for the government of the N.W.T. when it comes to a discussion about hydraulic fracturing that will be required if the Canol play is to be developed. “If people don’t want to believe what the companies are saying about hydraulic fracturing, maybe it’s the responsibility of the government to go into those communities and help educate people and to explain the assessment process,” he said.
In the winter of 2012-2013, Conoco drilled two vertical wells on EL470 and this past winter came back and twinned them, drilling two horizontal wells and fracturing them. They are now being flow tested. In the appraisal stage, depending upon results, plans call for drilling and testing up to 10 wells (two per year for five years), said Hanson.