Providing coverage of Alaska and northern Canada's oil and gas industry
February 2012

Vol. 17, No. 7 Week of February 12, 2012

Room in pipeline, but . . .

North Slope processing facilities are full; discoveries might need own processing

Kristen Nelson

Petroleum News

Filling the trans-Alaska oil pipeline has become the mantra in the state: More oil, more jobs, more revenues.

More oil could be found, or developed at Prudhoe Bay or Kuparuk or Alpine, the major fields on the North Slope.

But once more oil is found — or drilling increased at existing fields — that crude oil, which contains water and gas as well as oil, has to be processed before it can be shipped to market.

While there is room in the trans-Alaska oil pipeline to take the oil to market, there are capacity issues in the North Slope facilities that process crude oil, with the exception of the Badami facility on the eastern North Slope.

The facilities aren’t at capacity with oil, Tom Walsh and Bill Barron told the Senate Resources Committee Feb. 3, but most are at capacity for handling the water and natural gas that comes to the surface with the oil.

Walsh, managing partner at Petrotechnical Resources Alaska, or PRA, was the lead in a 2004 study of North Slope facilities done for the Alaska Department of Natural Resources Division of Oil and Gas. Barron is the current director of the division.

As Barron noted, a facility built to handle a thousand barrels a day of crude oil may have initially handled fluid which consisted of 900 barrels of oil and 100 barrels of water, while later in field life that same volume of fluid may contain 900 barrels of water and 100 barrels of oil.

2004 facilities report

Walsh said PRA had not updated the 2004 report since the work was done, but said the division had done some updating, which Barron would discuss.

In 2004 PRA found that there were opportunities for facilities sharing.

But Walsh said there were facility constraints and it wasn’t a slam dunk that if you found hydrocarbons on the North Slope that processing them through existing facilities was the way to go.

Facilities are designed to handle the field they’re built for, Walsh said. Over time the oil volume declines but the volumes of gas and water coming to the surface with the oil increase.

There have been numerous facilities expansions on the North Slope to handle increasing volumes of gas and water, he said, but at some point additional investments for gas and water handling don’t make sense because they don’t create new oil, they just accelerate production of existing oil.

If there is a new discovery within 25 miles of an existing production facility, however, use of that facility can get new oil to market faster than building a new facility.

Facilities owners interested

Walsh said that when PRA talked to the North Slope operators in 2004 to gather information on the facilities and see what benefits the owners saw to facilities sharing, “the response was very interesting.”

He said that in most cases the response was that there were gas handling and water handling constraints on the facilities, but that at some point in the future, as oil production declined, the owners would be actively marketing access to the facilities.

The facilities owners wanted to see information on the facilities available so that potential third-party users would know where there might be existing capacity and what the terms would be if the owners had to back out oil, Walsh said.

Backing out oil occurs when wells with very high volumes of water or gas are shut-in to make room in a facility for wells that have less gas or water mixed with the oil. Walsh said it’s something that occurs on the North Slope daily at the producing fields, where wells are evaluated and shut-in if production has too much gas, for example. He said such shut-ins have a benefit in that better barrels of oil are produced.

However, when third-party oil comes into a facility for processing and that third-party oil requires wells in the field to be shut-in, a price for backing out that oil will be part of facilities’ use negotiations.

Facilities sharing choices

Walsh cited Badami as an example which went beyond facilities sharing. That 35,000-barrel per day facility was sitting idle because production from the field had never lived up to expectations.

BP offered a farm-out of the Badami facility and acreage around it. Walsh said that when PRA did the 2004 study, the Badami facilities were underutilized. Now Savant and ASRC have partnered to explore and develop the area, he said.

Oooguruk and Nikaitchuq had been discovered and were under development when PRA did its 2004 study, Walsh said, but Pioneer Natural Resources contracted with the Kuparuk River unit for processing of Oooguruk oil, allowing the company a quick turnaround on development of that field.

Eni, on the other hand, chose to develop standalone production facilities for the Nikaitchuq field.

Walsh said such decisions are driven by a company’s commercial review and include factors such as commercial terms, a company’s cost of capital and its target internal rate of return, factors which would make it very difficult for an outsider to review such a decision.

Walsh said he believes “facility owners are generally supportive of facility sharing” and said that he does not know of any oil which is being kept out of the pipeline because of facilities sharing issue.

Prudhoe production

Barron said when production began from Prudhoe Bay, the oil-water ratio “was incredibly low — essentially zero.” It’s now approaching almost four parts water to one part oil or an 80 percent water cut, he said.

Barron formerly worked as a reservoir engineer, and he said that tells him “that there is still robust life left in the field in terms of oil production.” What’s changed, he said, is that you have to manage a much higher volume of water.

There is also more gas to be managed, a combination of gas cycling — reinjection of gas into the field — and reduced reservoir pressure, which causes more gas to break out of the oil, he said, and while the facilities could handle a lot more oil they have or are reaching capacity in the ability to gas and water.

Third-party oil

On third-party oil coming into a facility, Barron said part of the issue is what kind of oil it is, but it’s also an issue of reservoir management.

The North Slope operators “have incredibly sophisticated numerical simulations that they run on a very routine basis” looking for wells that are going to gas out or water out, due to too much gas or water, and plan workover, drilling and shut-in programs “to minimize the impact of the water or the gas fronts as they come into those areas,” he said.

With facilities sharing, the operators then have to calculate what wells they might have to back out prematurely to allow for processing of third-party gas, and that raises the issue of ultimate recovery. Barron said at that point the Alaska Oil and Gas Conservation Commission will want to know “if we do back these wells out, will we in fact ever get that oil back?”

The Kuparuk reservoir is different, with a significantly lower gas-oil ratio than Prudhoe Bay, a reflection of both the amount of gas cycling at Kuparuk and the fact that Kuparuk oil is less gassy.

Looking at the facilities situation on the North Slope, Barron agreed with Walsh: “Everything’s full, one way or another,” other than Badami, because of gas or water handling issues.

But, he said, new oil doesn’t have to go through facilities at Prudhoe or Kuparuk, because new companies can build their own facilities.

That decision will partly depend on corporate culture, Barron said.

“Every company has its own preconceived idea on how they will want to develop their property,” he said.

If a find is very small, a company might well decide that if it’s possible to “shoehorn it in (to existing facilities) and work through the commercial terms,” that they would do that.

But if the find is very big, “the likelihood is they will do their own (facilities).”

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