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New technology aims to draw heavy oil from rocks
(Alaska Journal of Commerce (Anchorage) Via Acquire Media NewsEdge) Oct. 5--A test of new technology to produce heavy oil on the North Slope has had encouraging results, BP Exploration (Alaska) Inc. said Sept. 29.
"This is really good news because this is a giant resource, with about 20 billion barrels of oil physically in the reservoir. We think the time is right to go after it," said BP spokesman Steve Rinehart.
Based on the success of the test, BP will drill three more test production wells in the coming weeks and will build a processing and test facility this winter that will be installed next summer at the Milne Point field.
Four more test production wells may be drilled the following year.
Meanwhile, ConocoPhillips is preparing to test another technique for producing the cold, thick oil by warming the oil underground in a test well drilled in the Kuparuk River field, said Bowen Roberts, ConocoPhillips' manager for the project.
Heavy oil poses major technical challenges and is very costly to produce, but both companies believe there is good potential for production that can be sustained over long periods to help offset the decline in conventional light oil.
Heavy oil must be mixed with conventional crude to flow through the trans-Alaska oil pipeline, however.
Most of the estimated 20 billion barrels of heavy oil on the North Slope is in the Ugnu deposit, a shallow reservoir overlying the Milne Point, Prudhoe Bay and Kuparuk River fields.
As it sits in the rocks, some heavy oil will barely flow and much of it won't move at all. It has a consistency that ranges between maple syrup and shoe polish.
The companies have to do something to make it move.
BP's approach, in its test project at Milne Point, is a technology called cold heavy oil with sand production, or CHOPS. It is a procedure being used to produce heavy oil in Alberta by Canadian oil producer Husky Oil Ltd. In one project there Husky is producing 150,000 barrels per day, according to Eric West, BP's manager in charge of the heavy oil project.
Heavy oil is being produced in California, Venezuela and Alberta, and the companies operating in Alaska are taking advantage of lessons learned in those places. Venezuela's heavy oil is a little lighter than Alaska's, and Alberta has oil that is heavier than in Alaska.
ConocoPhillips is taking a different tack in the Kuparuk field, using an electric heater placed down in the well to heat the heavy oil so that it will flow, said Bowen Roberts, coordinator on the project.
ConocoPhillips drilled an Ugnu test production well in 1998, in the southeast part of the Kuparuk field, and has been testing different production procedures intermittently over several years, Bowen said. The most recent, done last year, involved injection of diesel down the well to warm the oil.
The test with the electric induction heater will be done in mid-2009. Roberts said it is aimed partly at testing the heater technique, but also at obtaining uncontaminated samples of the oil for laboratory analysis, Roberts said. Previous batches of heavy oil produced with diesel has been contaminated with the fuel, he said.
Such thermal production techniques to warm the oil are now being used in Alberta to produce heavy oil, BP's West said. One procedure involves injecting steam, with one well drilled to inject the steam and a second drilled nearby to drain oil that is loosened, West said. Companies in Alberta are also using heavy earth-moving equipment to mine very thick, heavy oil that is close to surface.
Surface mining has never been done on the North Slope because the oil is too deep and the surface disturbances would be unacceptable.
The North Slope companies also don't think the steam injection will work because of the amount of energy required to make the steam and the possible problems created as steam is injected through permafrost below the surface on the Slope.
However, thermal heating also requires certain reservoir characteritics to be effective, and while those might be present in some fields on the Slope, they aren't at Milne Point, where BP is operating, West said.
Thermal heating requires good continuity of the reservoir rock so the heat isn't dissipated along fractures or shale barriers in the rock, he said. At Milne Point, the reservoir rock is segmented by shale barriers, which would reduce the effectiveness of thermal heating.
BP's approach is to try to produce the oil without heating. The CHOPS procedure involves producing the oil without heating, and uses a novel production technique that essentially sucks loose sand saturated with the oil up the well with a "progressive cavity pump."
At the surface, oil is separated from the sand-oil mixture. After the oil is extracted, the sand is to be injected back underground in one of the special injection wells BP uses to dispose of drilling mud and cuttings underground.
BP tested the production system in late August and early September at Milne Point, in a well drilled last year at "S Pad" into the Ugnu heavy oil reservoir. The test was concluded Sept. 15 and had better than expected results, BP spokesman Rinehart said.
BP mainly wanted to determine if the sand/oil mix could be produced up the well.
"Our objective was to demonstrate that we can bring the sand (and the oil) to the surface on a sustainable basis," West said.
Rinehart said that did happen, and the test was even more successful because the company was also able to test the oil separation procedure. About 700 barrels of heavy oil, with an API gravity of 10, were extracted from the sand and shipped to the Trans-Alaska Pipeline System, Rinehart said. API gravity is a measure of oil quality derived by the American Petroleum Institute.
"This test was successful in several ways," he said. "We were able to bring sand mixed with the oil up the well on a regular and sustained basis, and to create a series of small fissure -- we call them "wormholes" -- in the reservoir to allow oil to flow. We used a device called a progressive cavity pump to create a suction to bring the oil-sand mixture up the well."
BP was able to create a significant flow of heavy oil, although Rinehart did not give figures. It was enough, however, to convince BP that the reservoir "appears to be fairly robust" in its potential.
The initial flow of sand and oil was 50 percent sand but that dropped to 20 percent sand by the end of the 30-day test, he said.
"We were also encouraged by the success of separating the oil from the sand, which was done with heating," Rinehart said. There are still technical challenges, however. One is whether the sand/oil mixture can be extracted from a horizontal well, BP's West said in a briefing for reporters in September, when the production test began.
BP has been working on the technical feasibility of heavy oil production for about three years, and ConocoPhillips has been working on it for more than a decade. The resource has been known for a long time but the technical and economic challenges are daunting.
"We know where the heavy oil is and where it isn't because we drill through it all the time to reach the deeper conventional oil reservoirs," West said in a briefing on the project during September. "We know how much oil is in place with some precision. The question is how much we can produce."
If BP proceeds with heavy oil development, it would require a large number of wells and would most likely be done with horizontal multi-lateral production wells involving a several underground production legs drilled off a single "mother" well to the surface, West said.
Whether horizontal and multi-lateral wells can be used isn't known, but it could be a way to reduce the surface impacts and costs. BP and ConocoPhillips use horizontal multi-lateral wells on the Slope to produce viscous oil, which is of higher quality than heavy oil, as well as conventional oil.
The jury is still out on heavy oil production, but BP and ConocoPhillips hope to make it part of the "bridge" strategy until natural gas production from the North Slope.
One of the big attractions of heavy oil wells, if they can be shown to produce commercially, is that they could last a very long time, much longer than oil produced from the conventional oil well.
Conventional oil production from the North Slope fields will continue to decline and at some point gas production will begin to help support the production infrastructure on the slope, BP's West said.
If it is feasible to produce, heavy oil could be a key part of a strategy to mitigate the decline of oil fluids, West said. That way, when gas does start flowing, there will still be a healthy production of oil and gas.
To see more of the Alaska Journal of Commerce, or to subscribe to the newspaper, go to http://www.alaskajournal.com.
Copyright (c) 2008, Alaska Journal of Commerce, Anchorage
Distributed by McClatchy-Tribune Information Services.
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