Bakken operators will need to hit their natural gas capture targets, or face the possibility of curtailed production.
The North Dakota Industrial Commission voted unanimously to adopt new flaring reduction strategies presented by Department of Mineral Resources Director Lynn Helms on March 3.
Helms analyzed the North Dakota Petroleum Council’s flaring task force report that was presented to the commission on Jan. 29, and developed some steps to help bring flaring under control, potentially capturing 95 percent of the natural gas by 2020.
Helms explained that operators and gas gatherers should be forced to communicate in order to avoid under-capacity issues, and he told the commission that curtailing production is its most powerful tool to make an impact.
“It’s a really powerful tool though, and we want to wield it with care. It can be an incredible incentive, but also an incredible disincentive,” Helms said.
Industry’s greatest fear
NDPC President Ron Ness told Petroleum News Bakken the industry makes drilling plans and secures investors, so if the wells cannot be produced at rates to obtain a return, they won’t be drilled.
“That’s absolutely the greatest fear of industry,” Ness said. “But if producers retract substantially, everything will retract. It will prolong the growth challenges we have like housing and infrastructure instead of attracting that money while the going’s good.”
Despite the possible consequences of the process, Ness was largely pleased with Helms’ analysis of the task force report, saying he came with good ideas, and the commission adopted much of what the task force presented.
Production curtailment could cause an operator to be temporarily released from its midstream contract, through a force majeure clause, in order to allow on-site capture companies to provide services until the gathering pipeline system is in place. Helms said currently remote capture companies struggle to find their fit.
“I have hundreds of emails from those folks talking about the difficulty identifying where there may be a spot for them in the development,” Helms told Petroleum News Bakken. “Because the vast majority of gas is dedicated into contracts, and it’s hard to determine where the market opportunities are.”
Eric Dille of EOG Resources, chairman of the flaring task force, said he thinks the proposal is workable, but it generates questions.
“Lynn currently breaks the state into eight different producing areas, all with different production levels. Each probably needs a different approach,” Dille told Petroleum News Bakken. “Also, each producer may have a different contract with the midstream company. This creates questions about implementing the force majeure clause which may involve a court action.”
Gas capture plans required starting June 1
The flaring task force had suggested requiring a gas capture plan from each operator prior to drilling as a way to ensure a decrease in flaring.
Helms included the idea in his proposal, so effective June 1, a gas capture plan must be provided when the operator applies for a spacing unit. In addition, the application must be accompanied by an affidavit that the operator shared the gas capture plan with all available gas gathering companies. This would allow midstream companies to better determine how much gas will need to be gathered so they can plan their construction investments accordingly.
“They will have to go to a gathering company, as well as to the commission. This is a completely new method of communication that no one has done anywhere,” Helms said.
Gov. Jack Dalrymple told Helms and the commission that they will need to thoroughly analyze the gas capture plans to ensure each is viable, because “it won’t do any good if we just rubber stamp every gas capture plan that comes forward.”
Over-communicate to avoid under-investment
Helms said a lack of communication between operators and midstream companies has led to an under-investment of gas capture, but now gas gatherers and processors will get the information every month, and “it will change their whole concept of how much investment they need to make in North Dakota.”
Helms added that his office will also meet semi-annually with the midstream companies to gauge the process.
However, Helms pointed out that there are 9,000 wells already approved for increased density spacing, so the opportunity to obtain a gas capture plan will need to be shifted to the drilling permit stage of those wells, which may not happen for five more years.
“That doesn’t mean we don’t recommend gas capture plans on future applications,” Helms said. “Because we’re not going to be drilling for five years, we’re going to be drilling for 20 years. So the following 15 years could be captured in that process.”
Rewriting outdated field rules
Helms also recommended that his office rewrite the field rules that currently allow wells to be produced at a maximum efficiency rate for 60 days, then taper off production to 200 barrels of oil for 60 days and finally to 150 barrels for 60 days. Helms said the rules were designed for conventional resources, dating back to 1990, and not for a 15,000-square mile field like the Bakken.
“That’s why so many maximum efficient rates are (allowed), because proper spacing orders don’t work,” he told the commission. “There needs to be a model that addresses how we control increased density drilling, in an environment where we’re not affecting economics.”
For wells that are not economical to connect to a gathering line, the rules allow flaring for a year, with the understanding that inclement weather limits construction time.
Helms used graphs to show the commission that a typical Bakken well currently offers a payout within a year with 170,000 barrels of oil. If the current field rules were enforced, and production curtailed accordingly, it would take 39 months for a well to become economic.
“If we implement today’s paradigm, we get an enormous reduction,” Helms said. “I’m not talking slowdown, I’m talking enormous. Operators will flee.”
DMR will hold a hearing to review and revise all Bakken and Three Forks field rules governing production curtailment. Helms expects the hearing to bring a crowd much like the one in 2009 when the entire western half of the Bakken play became viable and DMR needed to develop rules for efficient spacing units.
“I expect this to be every bit as large,” Helms said. “This will affect all the contracts we’ve signed over the last 14 to 20 years.”
Pursuing the steps with vigor
Helms’ action steps also include taking the advice of the task force to create a pipeline hotline that ensures a timely response to reports about pipeline spills or concerns. DMR plans to create the web-based form that can accept information and photographs of the problem area, and initiate notification systems or, if necessary, mediation services.
“This is an important space we can occupy,” Helms said. “It’s not exactly regulatory, but it can help with the right-of-way problem.”
Finally, the North Dakota Pipeline Authority was tasked with tracking the status of natural gas capture versus the commission’s goals.
The new policies should be fully implemented by the end of September, and Helms said if they are “pursued with vigor,” the state should be able to reduce flaring to achieve its 5 percent goal by 2020.
