Patricia Stockdill for the Bismarck Tribune
A good old-fashioned conventional oil well drilled vertically often has a primary recovery rate of 15 to 20 percent of its available oil.
Companies can then come in with water flooding to entice another 15 to 20 percent of the reservoir’s oil, followed by Enhanced Oil Recovery (EOR) for additional oil.
It’s not like that with Bakken oil wells, said John Harju, Energy & Environmental Research Center, Associate Director for Research, Grand Forks.
A typical Bakken well is able to produce about 4 to 6 percent of the reservoir’s oil. Given the tight nature and other characteristics of the shale rock, water flooding is unlikely to be successful. Bakken rocks are often what Harju described as “oil wet,” meaning that flooding the reservoir with water is not as likely to be productive in sweeping oil out of a Bakken well. Instead, oil tends to go deeper back into the tiny fractures and pores. “We (researchers) don’t believe that water flooding will be widely effective for Bakken enhanced recovery,” Harju said.
Another aspect of Bakken oil wells is that there is typically an 80 percent decrease in production rate within the first year.
However, because Bakken wells produce so well – and it’s such lusciously rich, high quality sweet crude oil – it is worthwhile for companies to accept that lower recovery rate and production decrease. “It’s very common to see initial production of more than 1,000 barrels per day (BBD) from these wells,” Harju described.
The highly productive nature of the Bakken – a combination of its geology and new technology – makes it worthwhile. If only EOR could extend the longevity and production rate, Bakken wells would be even more bountiful than they already are.
It’s the challenge of increasing the ultimate recovery that has the attention of several oil companies, the State of North Dakota through its Oil and Gas Research Council, the U.S. Department of Energy, and the Energy & Environmental Research Center located on the campus of the University of North Dakota.
Together with the Research Council and companies such as Marathon Oil and Continental Resources, Harju said EERC Senior Research Managers Dr. Steve Hawthorne and James Sorenson, along with their research team, are working on the aspect of Enhanced Oil Recovery using carbon dioxide.
EERC is not new to the Bakken oil play or CO2, sponsoring a Bakken forum in 2007. “We’ve been very busy in Bakken since that time,” Harju explained. The use of CO2 also is not new to EERC or the oil and gas industry, having long been used in the enhanced oil recovery process for conventional wells. “There is a long history of using CO2 in mature or conventional fields,” Harju added.
But Bakken is a different beast. Conventional wells are often not as deep and they were typically drilled vertically. Bakken wells go into tight rock through horizontal drilling, going vertically, and then bending out horizontally. In addition, they are typically about 10,000 feet deep and have another 10,000-foot horizontal leg.
Researchers and companies alike need to find another way to get enhanced oil recovery from Bakken wells other than water recovery, Harju said.
The EERC research team is focusing on the use of CO2 in the recovery process. So far, CO2 has worked well as researchers study its use in the lab. EERC recently completed Phase I of a multi-phase effort, which was at the bench scale level in the research process. Other parties have also conducted two field tests, Harju said.
EERC is now entering Phase II of the project, which allows stepping forward to field level technology. “We’re very, very bullish on this technology,” Harju said.
While it is early in the process – and the EOR rate may not be able to get that 15 to 20 percent recovery rate enjoyed using CO2 in conventional wells – given the huge oil reservoir of the Bakken, enhanced oil recovery rates above 4 to 6 percent would still translate into a vast amount of oil.
“However, we’re not likely looking at increasing the recovery rates, but rather extending the productive timeframes of the reservoir and its ultimate recovery,” Harju said.
Sorenson, Hawthorne and the team worked about two years on Phase I. Harju said he expects Phase II will also be a 2-year endeavor beginning in April 2014.
Looking towards the future, Phase II would entail optimizing the learned data for additional testing with the goal of working toward commercial implementation of the process.
Integral to the success of the project, however, is the ability to obtain enough carbon dioxide.
Yes, CO2 could play a major role in coaxing the amount of oil from an already abundant reserve. Harju said 2 to 3.2 billion tons of CO2 could potentially facilitate the production of 4 to 7 billion barrel of incremental oil available above and beyond today’s current technology.
Incremental oil is oil that would otherwise have remained in the formation, Harju said.
The problem is that all of North Dakota’s coal-based power plants produce about 33 million tons of carbon dioxide annually, which is not enough to meet potential demands if carbon capture technology proves to be viable. There needs to be a way to capture CO2 economically, Harju said. While the technology capable of capturing CO2 is currently available, it is not yet cost-effective.
Regionally, the CO2 presently used in the EOR process is produced at Beulah’s Dakota Gasification Company with most of it shipped to Canada for use in their oil fields. To help meet the demand for CO2 in Canada, Harju said the provincially owned public utility company Saskatchewan Power, SaskPower, currently implements technology that will annually capture 1 million tons of CO2.
In the big picture of energy technology and demands, North Dakota is one of the few places in the world with such a co-abundance of oil and coal resources, Harju added. If it was somehow possible to capture CO2 to use in the enhanced oil recovery process, given the amount of oil estimated within the Bakken the combination of the two could greatly enhance the nation’s energy supply.
“Everybody wins,” Harju said: CO2 would not be emitted into the atmosphere and would instead be a valuable by-product of the coal-fired power industry with it being used to meet the United States’ oil demands.
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