With lackluster gains on flaring, operators can expect strict enforcement of new North Dakota Industrial Commission, NDIC, rules which will restrict production in order to meet the state’s new gas capture targets. May’s flaring percentage dropped only slightly to 28 percent from 30 percent in April, despite the hope that Department of Mineral Resources Director Lynn Helms had of the figure inching closer to the low 20s mark. He described the percentage as “surprising and kind of disappointing” when speaking to reporters at his monthly press conference to share production results.
“It points to the fact that the action taken by the commission on July 1 is really needed,” Helms said.
On that date, the commission issued an order to allow oil production restrictions if producers fail to meet a timeline of gas capture goals. The first target is to capture 74 percent of the gas by Oct. 1, i.e., reduce flaring to 26 percent.
Helms said the latest numbers indicate that the industry will struggle to reduce flaring percentages and volumes on its own, so the state needs a change in the flaring paradigm. He noted that most of the flaring is in McKenzie County, concentrated along the southern shore of Lake Sakakawea from state highway 85 to Keene. Production or permits will soon need to be curtailed in that area.
An unforeseen issue that has hampered gas capture is that Hess Corp.’s Tioga gas plant was only processing slightly over half of its capacity in May. Slowed pipeline expansions and compression due to delayed federal permitting has kept flaring higher than anticipated. Gas in McKenzie County, particularly in the Keene area, would normally cross the lake to get to the gas plant, but it is unable to be transported without those permits.
“I really thought the Tioga gas plant coming online in May would make a bigger difference than it did, but gas can’t get there yet from the Keene area,” Helms said.
Review process begins
In June, the NDIC began receiving gas capture plans from operators and Helms said about 75 percent of them were “very good” but the others varied from being largely incomplete to missing a few pieces of data. After six weeks of reviewing gas capture plans, Helms said permits have seen two- to seven-day delays due to the new requirement. Many simply need answers to questions from the permitting staff and others are on longer term holds since the gas capture is not expected to be expanded until the third or fourth quarter of 2014.
“We’re starting to see the effects of the gas capture plans in our approval processes, but also we’re gearing up and able to look at gas flaring and gas capture in a more granular view,” Helms said.
Though statewide gas capture is at 72 percent, flaring varies greatly by area and field. Each operator will need to meet the 74 percent capture goal by Oct. 1. Helms said when looking at the five major oil-producing counties, there are 775 wells that produce more than 100 barrels a day but capture less than 50 percent of the gas. Most of those are in McKenzie County, so production curtailments to come may be focused there.
Meanwhile, the new NDIC production restrictions order is generating questions from operators in the state and Helms will meet with them on July 21 to attempt to answer their concerns (see related story page 3). He said it appears operators’ biggest apprehension is what the commission will do if flaring increases when outages by midstream companies occur since operators don’t have any control over it. That problem could rear its ugly head shortly. Helms was recently informed of a significant outage that is likely to create gas capture struggles.
“There is going to be rolling compressor plant down times across southern North Dakota as one of the midstream companies increases compressor capacity at all of their plants. So over a period of 45 days, every one of their stations will be down for maintenance,” Helms said. He said the commission will need to decide how to deal with those fluctuations.
Based on the Tioga gas plant not living up to expectations, Helms said the Oneok Garden Creek II plant could also result in short term bottlenecks and delays and thus cause gas capture to miss its mark. But Oneok’s system is interconnected with various facilities so if one doesn’t have capacity, the gas can be sent to one of its other nearby plants. He’s hopeful that type of system will eliminate any gas capture obstacles.
What if goals aren’t met?
Though the first gas capture goal is set for Oct. 1, data for October will not be analyzed until December. Any operators not meeting the 74 percent capture goal will receive a letter to restrict January production. The new order states that if an operator can capture 60 percent of the gas through remote capture technology, they can produce up to 200 barrels a day, but anything lower than 60 percent will curtail production to 100 barrels a day. However, the commission intends to look at the operator on a field-wide and state-wide basis to determine if an exception can be made for a particular well if the operator has a proven track record of effective gas capture. But for some isolated areas where connection to a gas gathering facility is not feasible, operators will need to seek other solutions.
“My anticipation is that there is going to be a handful of companies who their only option is going to be well site technology in order to meet the goals,” Helms said.
He cited Four Bears field in northeast McKenzie County where rough terrain and construction constraints make capture extremely difficult and therefore operators are only capturing 2 percent of the gas from those wells - a far cry from the 74 percent goal.
“That’s an area where some value added process may be their only option - either that or production restriction,” Helms said. “It will vary a great deal field to field … but without some type of well site application or production curtailment, I don’t think we’ll get there.”
Helms noted that if operators had been subject to the new order based on April production data, it would have resulted in curtailment of 40,000 to 50,000 barrels of oil a day if no well site technology was implemented.
Once production restrictions are ordered for an operator, the commission will audit production reports to ensure the operator is not violating the directive. If they fail to curtail production, the commission will issue a complaint and has the authority to fine a company $12,500 a day. But enforcement will be a bit slow as reports for any given month are not available for two months, therefore if the commission sends out a curtailment notice in December, it wouldn’t know if the operator was complying in January until March.
“We do anticipate needing to use penalties,” Helms said.
Curtailment would be approached month-by-month, he said, and an operator could submit an updated gas capture plan to have curtailment lifted by a certain date. For operators who claim that remote capture technology is not economic for their wells, Helms said a typical Bakken/Three Forks well is capable of producing two or three times the uneconomical rate of 100 to 200 barrels a day.
“It looks to me like there isn’t any question that it’s economic,” he said.
From the first recommendations by the North Dakota Petroleum Council’s flaring task force to the July 1 order by the North Dakota Industrial Commission, the key to meeting gas capture targets appears to be a collaboration of industry to find solutions or face the consequences.
“I think the message from the commission to me … was very clear. This order will only make a difference if we are very, very strict about granting exemptions to it,” Helms said. “I think there is enough time between now and Oct. 1 ... for companies to form those alliances and make those cooperative agreements.”
