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Vol. 17, No. 23 Week of June 03, 2012
Providing coverage of Bakken oil and gas

Looming field declines

Whiting, Continental, Marathon, EERC studying ways to bolster future oil recovery

Ray Tyson

Petroleum News Bakken

Field operators Whiting Petroleum, Continental Resources and Marathon Oil, faced with inevitable production declines, are seeking ways to adapt various oil recovery technologies to the tight, unconventional formations that make up the massive Bakken petroleum system.

Moreover, the Energy & Environmental Research Center, EERC, at the University of North Dakota, recently launched its own oil recovery study, as the time approaches when such technologies will be necessary to fend off production declines and prolong field life in the Bakken.

Petroleum News questioned executives from EERC and the three major Bakken producers separately on the sidelines of the 12th Williston Basin Petroleum Conference, held May 22-24, in Bismarck, N.D.

Industry’s major concern appears to center on whether recovery methods typically used in conventional reservoirs will significantly improve Bakken recovery rates, given the complex geology characterized by rocks with low porosity and permeability qualities.

Roughly 10 percent of the original oil in place can be extracted from conventional reservoirs during the primary recovery phase, according to the U.S. Department of Energy, DOE.

Secondary recovery techniques extend a conventional field’s productive life generally by injecting water or gas to displace oil and drive it to a production well bore, resulting in the recovery of 20-to 40 percent of the original oil in place.

Tertiary, or enhanced oil recovery, EOR, techniques can ultimately produce 30-to 60 percent, or more, of a reservoir’s original oil in place, according to DOE. Technologies used during third-stage recovery include gas injection (CO2, nitrogen and natural gas), thermal recovery and chemical injection.

Low recovery in Bakken

However, the Bakken petroleum system is noted for low primary recovery rates of 3- to 5 percent of the original oil in place; and, while the jury’s out on exactly how much additional oil can be extracted using secondary and tertiary techniques, the recovery rate in the Bakken likely will be substantially lower than in conventional reservoirs.

“I don’t think you will ever see the kind of rates that you do in the very early production history of these wells,” John Harju, associate director for EERC, said in an interview. “But we are very optimistic that you will be able to increase rates from the very long, slow declines that we see on these wells.”

The EOR technique that is attracting the most new market interest is CO2 injection. In the United States, there are about 114 active commercial CO2 projects that together inject over 2 billion cubic feet of CO2 and produce over 280,000 barrels of oil daily.

Whiting Petroleum operates two large conventional enhanced oil recovery projects in Texas and Oklahoma, where both water and CO2 are injected into the formation. The CO2 tends to swell oil droplets that remain trapped and then expands and helps them flow through the reservoir matrix and toward the well bore, while the water helps push the oil along.

Jim Volker, Whiting’s chief executive officer, believes the same approach starting with secondary water flooding should work in its 60 percent operated Sanish field in the Bakken, after the field is fully developed in about two-and-a-half years.

Meanwhile, secondary recovery is being tested at the Parshall field just east of Sanish, where Whiting holds about a 20 percent stake. “We’ll see how it works there,” Volker said.

However, he added, because the Sanish’s primary reservoir is the Middle Bakken formation and is thicker than it is beneath the Parshall, “we think the water flood may even work better under the Sanish field.”

Volker reiterated that recovery techniques used by Whiting after the initial primary recovery stage, are typically water flood during the secondary stage followed by a combination of water flood and CO2 injection during the tertiary stage. “And I expect that is what will happen here,” he said.

Jack Stark, Continental Resources’ senior vice president of exploration, the largest leaseholder in the Bakken, said Continental is currently in the planning stage and that CO2 is just one recovery method the company is exploring. He said a project likely would be launched within the next two years and would cover both the Bakken and underlying Three Forks formation.

“We’re really kind of looking at all options that are available,” he said. “But you want to do it in an area where you feel you have a good opportunity for success and a good pattern of wells and basic conditions.”

David Roberts, Marathon’s chief operating officer, said Marathon is currently exploring oil recovery options at its offices in Houston.

“It’s certainly something that we are studying, because we know that we can get more recovery,” he said. “The question is, do you drill more wells, or do you do something else? But I think that is still sometime out.”

Regardless, he added, industry “is a technological wonder” and “someone will come up with something” that resolves the oil-recovery challenge in the Bakken.

CO2 pilot projects in Bakken

EERC’s Harju is aware of two CO2 pilot projects conducted in the Bakken, neither one of which was considered to be a commercially successful test, he said. Nevertheless, he said, “a great deal of information” gleaned from these projects can be applied to EERC’s on-going study.

“Our general feeling is that CO2 will work, but the first thing we need to do is establish some operating parameters that we’re going to have to do to make it work,” Harju said, noting that in addition to CO2, EERC will be looking at other recovery techniques.

He said that so far Denbury Resources, Marathon and Calgary-based TAQA North have enrolled in EERC’s study program, financed by DOE and the North Dakota Oil & Gas Research Council.

Harju envisions a Bakken petroleum system that eventually will produce a minimum of 1 million barrels of oil per day, compared to the current 575,000 barrels per day.

“I think the big question is how long can it stay at a million barrels a day,” he said. “Can it be 20 years? Can it be 30 years? The work that we are doing is very much focused on improving that lifetime and improving that productivity, all of the time.”



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