By Tim Bradner
Alaska Journal of Commerce

North Slope producers BP and ConocoPhillips are tackling one of their toughest technological challenges to date.

The companies are working to find the best way to produce the heavy oil from the Ugnu formation, a massive deposit of low-grade oil trapped in sandstone rocks overlying the conventional producing fields of the North Slope. Current estimates put the Ugnu in-place resources in the tens of billions of barrels range.

The companies have figured out how to develop parts of the somewhat higher-quality West Sak and Schrader Bluff viscous oil deposits, which lie below the Ugnu — but it has taken two decades of research and development, and about $2 billion in investments. Schrader Bluff is the West Sak equivalent deposit in the Milne and Prudhoe Bay units. There are also several billion barrels of West Sak/Schrader in-place resources.

The companies know only a fraction of these barrels physically in the rock can be economically or even technically produced. But if even several hundred million barrels can be produced, it's worth the effort, as long as oil prices stay high.

BP and ConocoPhillips are counting on viscous and heavy oil to help soften the decline in production from the large conventional fields until a natural gas pipeline is built — if the long-awaited project does come to fruition.

Meanwhile, 40,000 barrels a day of viscous oil is now being produced by ConocoPhillips from the West Sak Formation and from the similar Schrader Bluff formation that overlays the conventional Milne Point and Prudhoe Bay fields operated by BP. This could increase by about 20,000 barrels/day in a few years if ConocoPhillips proceeds with a new phase of West Sak development.

Taxes and temperatures could pose hurdles

One fly in the ointment is the possibility that the state of Alaska may again change its oil and gas production tax. Alaska adopted its new Petroleum Profits Tax in 2006, replacing the previous tax. The state is now considering changing the tax again, and a special session of the Legislature is planned in the fall to consider the matter.

“The economic viability of future viscous and heavy oil developments is highly dependent on the fiscal terms, and stability of those terms imposed by the state of Alaska,” said Jack Griffin, ConocoPhillips' vice president for external affairs.

“The capital commitment associated with these types of projects is very significant. The potential re-opening of the (Production Profits Tax) could lead some companies to take a wait-and-see stance before progressing further.”

In Ugnu, the technical issues are enormous, but the sheer size of the resource makes it a tempting target. Because the oil is in shallower rocks, it is cooler and thicker than the conventional North Slope oil that lies in deeper reservoirs, and is therefore warmer. The temperature of the oil is a key factor in determining how easily the oil flows — or whether it can be made to flow, as is the question with these deposits.

West Sak, which is deeper and a bit warmer, has been tough enough. This oil flows with a consistency that ranges between maple syrup and honey, but at least it flows. Ugnu oil is like Crisco or peanut butter. Like Crisco and peanut butter, it won't flow.

Some of the Ugnu heavy oil is actually frozen into lower reaches of the permafrost, a 2,000-foot layer of permanently frozen soil and rock that underlies all of the North Slope. This oil may never be produced.

Both BP and ConocoPhillips have plans underway this year and next to test new production technologies for Ugnu. ConocoPhillips actually has a test production well in Ugnu that was drilled in 1998. It has been able to produce intermittently as the company tried different strategies, including pumping diesel oil down the well in an to attempt to lighten up the thick crude.

“We burned out a big pump trying to get it to flow,” said Blaine Campbell, ConocoPhillips' supervisor for heavy oil development. One of the challenges with diesel is to prevent contamination of the Ugnu crude, because the company needed pure Ugnu crude to do chemical analyses and to assess issues like sand content and contaminants. This data is important in planning production and separation facilities to handle the Ugnu crude, as well as decisions for future well completion designs.

Campbell said the company will try another idea in November, installing a downhole heating unit at the bottom of the well to warm the oil to the point it will flow.

BP, meanwhile, will drill an Ugnu test production well next winter at S Pad in the Milne Point field, company spokesman Daren Beaudo said. S pad also hosts conventional oil wells but it is being enlarged this summer to accommodate the new test well, where BP will experiment with different ideas for producing heavy oil, Beaudo said.

Transporting ideas to the Arctic

Campbell said the companies are evaluating a number of technologies aimed at getting the Ugnu oil to flow, some of them borrowed from similar efforts with tar sands in Alberta and heavy oil in Venezuela.

One approach, similar to one used in Alberta, is called “steam assisted gravity drainage” and involves two wells, one drilled to inject steam and the second to produce the oil. The injector well is drilled into an area of the reservoir above the producing well, Campbell explained. The steam warms the reservoir rock, loosening the thick oil so it flows. Gravity then causes the oil to slump toward the producing well below the zone that has been warmed.

A variation of this idea, Campbell said, is “cyclic steam stimulation,” which involves injecting steam down a well to “soak” and warm the reservoir in the vicinity of the bottom the well, and then halt the steam injection and use the well to produce oil that has been warmed.

There are challenges presented with these techniques, however. The biggest, others familiar with them said, is the need to inject hot steam down through the permafrost to the oil-producing formation, which can melt permafrost and create subsidence problems near the injection wells. Secondly, transporting hot steam through the permafrost will cause it to lose heat en route, lessening its warming effect once the steam gets down into the oil-bearing rock.

A more exotic solution to the problem, Campbell said, is to create the steam underground, so as to avoid transporting it through the permafrost. This could involve some form of technology to make steam from water in the underground reservoir itself — there is a layer of water underlying oil and gas in many of the North Slope oil fields.

There is no permafrost in Alberta tar sands or Venezuela's heavy oil fields, so this problem does not exist in those places.

This approach involves injecting source water from the surface downhole, to make steam, but it still requires energy to power the process of the making steam, wherever it is done. The energy needed to create the steam is an issue, too. If it takes a substantial amount of energy to produce the oil, the economics of the operation may not work.

While the Ugnu deposit poses huge technical challenges, it has one saving grace, Campbell said. This is that the Ugnu's oil-bearing rock strata is very thick — several hundred feet, in fact — which means that whatever recovery technology is adopted can be concentrated in just a few places on the surface, which creates some cost efficiencies.

This is in contrast to the West Sak formation which contains better-quality oil but is spread out widely in thin oil-bearing layers, which means the production pads and wells are spread across more surface area, adding to costs. Tim Bradner can be reached at tim.bradner@alaskajournal.com