The early results are promising in a years-long study of an advanced oil recovery method that could unlock billions more barrels on the North Slope.
“We have not failed; let me put it that way. We have succeeded so far,” said Abhijit Dandekar, chair of the University of Alaska Fairbanks Petroleum Engineering Department.
Dandekar is leading a small team of UAF researchers in collaboration with Hilcorp Alaska engineers to flesh out the viability of a seldom-used technique to drive heavy oil to the surface.
The four-year, $9.7 million Department of Energy-sponsored study is intended to determine whether a thick, syrup-like water-polymer can be used to improve recovery of the viscous heavy oil that geologists say is abundant across the North Slope.
“It really is an experiment done on a field scale,” Dandekar said in an interview.
The field is Hilcorp’s Milne Point, which the company bought from BP in 2014 and has since focused on rejuvenating the mature Prudhoe Bay satellite.
It’s unclear exactly how much heavy oil is spread across the Slope but Department of Natural Resources officials broadly believe the potential resource to be in the tens of billions of barrels.
Seawater is often injected into light and even more viscous oil reservoirs to “flood” the rocks and push as much oil out of the tiny pores of the rocks that hold it.
But the “heavy oil” of the North Slope, which Dandekar said is a very “Alaska-specific definition,” is unique.
“There needs to be something different done for heavy oil,” he said.
Launched in 2018, the specifics of the project involve injecting the polymer into Milne Point’s Schrader Bluff heavy oil reservoir via a pair of horizontal injector wells and production tests at a nearby pair of horizontal producers.
Dandekar compared the synthetic polymer to tapioca pearls before it is mixed with water; afterwards the thickening agent increases the viscosity of the water up to 40-fold, he said.
“You want to slow down the mob of water, which is basically helping sweep more oil,” Dandekar said.
Heavy oils tend to be shallower, as oil pools go, and the Schrader Bluff target of the polymer flood project is up to about 5,000 feet deep. Dandekar said it’s the relative shallow location of the oil that makes it so heavy. It’s colder than deeper oils, particularly in Alaska.
That cold, thick oil simply doesn’t move as easily when pushed by water, which can cause a water “breakthrough” and in a way dilute the oil pool. The recovered liquid is often more than half water when a traditional flood is used on heavy oil and enhanced viscous oil recovery techniques used elsewhere often involve injecting steam into the wells to heat the oil and help it flow more easily.
“Anything thermal, which is easily deployable elsewhere in non-Arctic conditions, is unimaginable here in Alaska because we’ve got 1,800 to 2,000 feet of continuous permafrost,” he noted.
According to a summary of the project by the federal National Energy Technology Laboratory, the work being done at what researchers have dubbed the Alaska North Slope Field Laboratory is the first polymer flood production in the country, though it has been used internationally.
Dandekar said the team first had to prove the “injectivity” of the polymer in Arctic conditions.
“The ambient temperature plays an important role,” he said. “The operation aspects of a polymer injection unit — those are something nobody had tried before.”
Since proving they could inject it, the researchers have refined their polymer management techniques to achieve roughly 1,000 barrels per day of additional oil production from the pair of producers in the test.
Use of the polymer has also decreased the water “cut” of what is produced from 65 percent to between 15 percent to 20 percent, according to a briefing on the work published by the research team in February.
“We are a team working on this and without a team I obviously don’t think this would go anywhere,” Dandekar said. “This is a classic example of collaboration between the federal government, industry and academia.”
Hilcorp Alaska spokesman Luke Miller wrote in an emailed response to questions about the project that the company is proud of the partnership it has with the university and federal research agency.
“UAF and DOE provide outstanding Arctic and industry expertise, as well as technical and project support,” Miller wrote. “As we build on our initial success at Milne Point, we’re expanding polymer flooding to additional reservoirs at Milne Point and continue to evaluate new opportunities across the North Slope.”
The team detected a polymer breakthrough last October of 600 to 700 parts per million in the producer wells, according to Dandekar, meaning the polymer had traveled the roughly 1,100 feet between the injectors and producers. He described the recovered polymer particles as “beaten down, sheared and spent.”
He said it was simply a matter of when the polymer would appear and the fact that it took more than two years is another positive.
“That is a good thing in the sense that the polymer — it still is — really sweeping the oil,” Dandekar said.
The February paper additionally suggests updated reservoir models indicate heavy oil recovery could reach 36 percent, or about twice what was forecasted for continued water flooding.
Now that the preliminary viability of the polymer flood has seemingly been proven, the next challenge is repeating it.
The UAF engineers are trying to match the data they have collected from the wells to what simulation models have produced.
“The idea is to honor that (production) history, match it and then do a forecast,” he said.
The project spawned from a nagging urge UAF researchers felt to work on the well-known heavy oil challenge.
“There’s so much heavy oil, we’ve got to do something,” Dandekar said.
That led the university researchers to seek out funding for the work.
Milne Point was selected as the test case because it provided of a long history of data from a mature field that previously had been flooded with water, according to Dandekar. He reached out to Hilcorp officials about the polymer flood after working with them on previous company-funded projects, he said.
“For projects of this scale, unless you have an industry partner, nothing’s going to happen,” he said. “It’s been a great, functional team.”
The research is set to conclude in September 2022.