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Vol. 19, No. 35 Week of August 31, 2014
Providing coverage of Bakken oil and gas

Inside the box

North Dakota oil regulators work to stabilize Bakken crude for transport

Maxine Herr

For Petroleum News Bakken

As robust oil and gas development continues in North Dakota, regulators have had to think “outside-the-box” many times to properly handle production growth. That unconventional thinking is being redefined as they strive to make Bakken crude stable and safer to transport.

The state’s Department of Mineral Resources Director Lynn Helms explained to the North Dakota Industrial Commission at its monthly meeting on Aug. 26 that a recent Turner, Mason & Co. study of Bakken crude oil indicates that many of the samples evaluated in the survey fall into a proverbial box of stability, where pressures and temperatures are of no concern for transporting. However, he said the commission needs to consider using oil conditioning to stabilize the oil represented by the samples that extend beyond the box (see graph, page 16).

The commission will hold a public hearing on Sept. 23 to obtain information regarding potential oil conditioning regulations. The equipment to condition Bakken crude already exists at well sites, so it would be a matter of standardizing the practice with specific pressures, temperatures and equipment used to ensure every barrel of oil is the same.

“The data shows that it’s not that difficult to get there by operating this equipment within its proper range,” Helms told the commission.

As illustrated in the chart, the green box represents stable crude oil - a product “suitable for any kind of transportation you wanted to do with it by anybody’s definition,” Helms said. The points outside of the box indicate that pressure and temperature will make crude oil’s stability vary. Helms said he was intrigued by the rows of points that indicate that at equal pressures but higher temperatures, the oil samples shifted closer to the green box, and said he felt this concept was worth further investigation. In the rows on the far left of the chart, temperatures varied from 35 to 120 degrees Fahrenheit which implies a use of cold treating the oil which operators do to separate water from the crude.

“That left 3 percent propane in the crude oil mix (at 35 degrees),” Helms explained. “But when operated with that same equipment at the same pressure at 120 degrees, then propane went to 1 to 1-1/2 percent. By varying the temperature at a given pressure, it’s possible to change the propane content of crude oil by two- to three-fold.”

A complex process

Removing the propane is actually the third step in the effort to eliminate the natural gas’ light ends. Helms explained that by the time the hydrocarbons come out of the well, methane has separated itself from the oil. Ethane is still partly in the oil but will turn entirely to gas once the oil is moved to a low pressure separator. Some propane will also become gas at this point, and additional propane along with some butane will be removed at the heater treater, the next stage of the process. Finally, at ambient temperature in a storage tank, all of the propane and most of the butane will leave the oil. If a well has particularly high gas volumes, a medium pressure separator may be needed prior to utilizing the low pressure separator. The unique challenge is obtaining a stable temperature in the storage tanks as North Dakota weather can vary by more than 100 degrees throughout the four seasons. Helms hopes the hearing will shed some light on appropriate operating conditions and equipment to bring the most stable barrel of oil that can still safely move into a pipeline at temperatures low enough for safe transport. Currently the pressure separators are only used for flowback on Bakken wells and once production declines, the equipment is moved to the next well coming online, so Helms also wants feedback on how long the process needs to be implemented in the life of a well.

Gov. Jack Dalrymple was interested in the gas capture aspect of the process and what applications could be considered.

“Is there going to be … potential for compressed gas?” Dalrymple asked. “GE talks about that a lot. Is this a situation where we can compress and move it?”

Helms said the process will certainly open the door for greater remote capture processes to market the gas for beneficial use.

“We’re probably going to continue over the next decade to build out that infrastructure,” Helms said. “In the 2020s, 95 percent of the gas will leave by (pipeline) and 5 percent will be left for well site processes.”

The other, less appealing, option: stabilization

Helms compared oil conditioning to stabilization, another process the commission could consider for standardizing a Bakken barrel. Stabilization operates on a much grander scale by processing 20,000 to 100,000 barrels of oil a day at a unit that would need to be constructed at rail transport stations, compared to conditioning 100 to 3,000 bpd on a well site. Helms said the stabilizer units would be at least the size of the Dakota Prairie refinery being built near Dickinson and to match current production, the state would need 22 to 50 of them. Other issues with this option include the need for more pipelines to connect wells to the units and the required massive compressors and coolers to condense the gases into liquids for safe transportation to a petrochemical facility. The system makes sense for oil plays in Texas as its wells produce condensate and a petrochemical facility is nearby in Houston.

“This is very routinely done with high gravity condensate - oil that condenses out of a gas well as it is produced,” Helms said. “That has to be stabilized before it can move through the system.”

Since the large industrial stabilizers would need to be located at rail facilities, the construction and operations would need to be funded by rail transportation companies, leading to higher transportation costs to the producers.

Agriculture Commissioner Doug Goehring voiced his concern with dotting the landscape with stabilizer units.

“We’ve been trying hard to shrink that footprint out there on the landscape, and that’s going to make that awfully difficult,” he said.

Helms agreed, saying conditioning is likely more suitable for North Dakota since the equipment is already in place on well sites but he’d like to hear from others at the upcoming hearing.

“We haven’t closed the door to (stabilization),” Helms said. “We want to hear what people have to say.”

The hearing will take place at the DMR offices at 1000 E. Calgary Avenue in Bismarck at 9 a.m. on Sept. 23. Those wishing to provide testimony can begin signing in at 8 a.m. Written comments must be submitted before 5 p.m. CDT on Sept. 22.

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