A clash with tribal leaders over gas capture policies and federal permitting delays could be the greatest hindrances to bringing North Dakota’s flaring problem under control.
The state’s Department of Mineral Resources, DMR, Director Lynn Helms said flaring percentages from June production offered a “slice of bad news” when it remained unchanged at 28 percent. Based on an audit by the department, wells on the Fort Berthold Indian Reservation flared 33 percent of the natural gas they produced.
“We’re going to have to do some work there,” Helms told reporters at his monthly press conference to announce the latest production data on Aug. 15. Helms met with tribal and federal leaders earlier in the week following the release of the Three Affiliated Tribes proposed gas capture plan which requires operators to pay royalties and taxes on flared gas. The tribe believes the fees will give operators incentive to capture the gas. Helms’ next step is to meet with Attorney General Wayne Stenehjem to sort out proper jurisdiction between the state, tribe, Bureau of Indian Affairs and Bureau of Land Management and “get on the same page with gas capture plans and flaring reduction plans,” he said. Once jurisdictions are determined, Helms plans to meet again with federal agencies and the tribe.
“Hopefully we can work out any differences in trying to manage flaring and move forward with a plan that gets us into sync there,” he said.
With multiple jurisdictions involved, Helms said deadlines to hit gas capture goals may begin to slide on the reservation where 30 percent of the state’s oil and gas production occurs.
“You may end up with differing techniques in different parcels of land in an attempt to reduce flaring,” Helms said. “I have an open mind to those different techniques, but what the NDIC (North Dakota Industrial Commission) approved … that’s going to be the most effective process going forward.”
If some type of consensus cannot be reached between the state and the tribe, Helms said litigation could become a possibility.
“That was brought up as something that could potentially happen,” he said. “The state wants to avoid it. It would not do anything to reduce gas flaring in the state.”
Permitting process delays gas capture
A gas gathering pipeline project in the Keene area south of Lake Sakakawea is preventing the expanded Hess gas processing plant near Tioga from being fully utilized. The plant only operated at 59 percent of its 250 million cubic feet, mmcf, per day capacity in June without the gas being transported from the Keene area. Helms said the federal permitting required for the pipeline mechanical and construction work has made the process, “go on and on and on.”
“It really highlights the difficulty in reducing flaring,” he said. Though the project is of small scale, it would provide gas gathering to a key area in the Bakken and could help bring the Hess plant to full capacity which, in turn, should make a significant impact in the flaring percentage. The Keene project alone could increase the Hess plant’s processing by another 60 mmcf per day.
DMR has met with four of the six midstream companies to discuss the gas capture plans that operators have submitted with drilling permits since June 1 and Helms said the companies have indicated those plans have worked well for them.
“It has increased their workload a significant amount so we’re looking at ways to make that more efficient, but at the same time, the information from operators is vastly improved so they’re having a much easier time planning expansions,” he said.
Operators will be required to capture 74 percent of their natural gas in the state by Oct. 1 or face possible production restrictions based on rules set by the NDIC on July 1. The Oct. 1 target was chosen because Oneok’s Garden Creek II processing plant is expected to be operational at that time, adding another 100 mmcf per day of gas processing. Under the new rules, gas can be produced at a maximum efficient rate for 90 days with the first 14 days of flowback gas totals removed from the volume calculation. If an operator can capture 60 percent of the gas with a remote capture process, it will be restricted to producing 200 barrels of oil a day to reduce flaring. If an operator is unable to capture any of the gas, the NDIC can restrict production to 100 barrels a day. However, the first well completed in a pool can produce at a maximum efficient rate indefinitely since that production allows an operator to evaluate the needed infrastructure and well development plans. The only exception to the production restriction rule on infill wells are those proven uneconomic to connect to a gas facility. This applies to just over 1,000 wells and most of those produce less than 100 barrels of oil so restriction wouldn’t be necessary anyway.
Only two operators asking permission to flare in August hearings.
Applications requesting flaring exemptions have diminished significantly since the new rule went into effect as only seven cases from three operators are slated to be heard by the DMR’s Oil and Gas Division at its Aug. 28 hearing. Continental Resources has continued three of its cases from earlier hearings for the commission to determine the volumes and values of flared gas from wells in the Hanson, Temple and Sauk fields of Williams County. As reported in the April 20 edition of Petroleum News Bakken, Continental began a request from the commission to determine the amount of royalties and taxes owed on the natural gas flared from a number of its Williston Basin wells.
Under NDIC rules, natural gas can be flared from a well for a period of one year during which royalties and taxes are not required to be paid by the operator; however, after that one year period, royalties and taxes are to be paid. Continental determined that a number of its wells had flared beyond the one-year royalty and tax exemption period and it was attempting to pay the appropriate royalties and taxes.
Statoil submitted an application of reconsideration from the commission to authorize flaring on a well in Catwalk field of Williams County. The same application was made by Brigham Oil & Gas in June for the same well, but the case was dismissed because supplemental evidence was not provided in time for the hearing. Statoil has since obtained the well and has provided the evidence that the commission requested which addresses the amount of surplus gas available for sale and the feasibility of using the surplus gas to operate an electrical generator.
Hunt Oil submitted flaring applications for three wells in Divide County. The company has requested the commission allow flaring on two wells in Alexandria field and one in Sioux Trail field as they are considered economically infeasible now and in the future to connect to a gas gathering line and facility.
