Preparations for the test injection are underway now, according to John Denis, a BP geologist working with the project. A response should be evident by summer 2008. The demonstration is expected to cost about $10 million, Denis said

The test of the technology in a producing oilfield is the first worldwide and it has far-reaching implications because BP's laboratory tests indicate a possible 10 percent to 15 percent additional recovery of oil from mature oilfields.

If that turns out to be true, and the project is expanded to cover the entire Endicott field, it could increase the recovery of oil from about 65 percent of the oil-in-place at Endicott that is estimated with conventional recovery techniques to about 75 percent or 80 percent with the low-salinity waterflood.

That works out to about 100 million to 150 million barrels of additional oil from the Endicott field, which has about 1.1 billion barrels of oil-in-place, or oil physically trapped in the reservoir rock.

Traditionally about 40 percent of the oil physically in the rock has been produced from oil fields, but on the North Slope that has been pushed to 60 percent in the giant Prudhoe Bay field and 65 percent at Endicott. The higher recovery results from a combination of factors, including the quality of the reservoir rock, which allows efficient drainage of oil, as well as the drilling of new production wells and the application of enhanced oil recovery technologies.

Waterflooding, which involves injection of high volumes of water to flush more oil from the underground rock, is a long-established technology that has been applied to almost all of the North Slope fields, including Endicott. The water that is injected is water produced up the oil wells with the crude, then separated in facilities at the surface, as well as water taken from the sea and treated. Most of this water has a high saline, or salt, content.

BP has been looking to use water with a lower salt content in the waterflood after laboratory work showed the low-salinity water appears to induce chemical changes that break down the bonds that cause oil to adhere to the underground rock, allowing more of it to be extracted.

“We've studied the bond and we've figured out a way to break it. We've proved it can be done in the lab, so this will be the first field trial,” Denis said.

BP has been interested in the idea for about 10 years, and active research has been underway for about five years, Denis said. The company has patented its process, which it calls “Low-Sal,” but other major companies are on the same track and will ultimately develop their own approaches.

The competition is about two to three years behind BP, however. The London-based company will be the first to do a field test.

The Endicott field was chosen for several reasons, Denis said. It is a high-quality reservoir that is well along in its producing life, but still has potential resources in the ground. About 45 percent of the hydrocarbon fluids would be left in the rock under the production technologies now used. There is also a tremendous amount of production information available from Endicott, which began producing 20 years ago.

“Endicott has great rocks (for efficient drainage) and is very mature in its depletion. We've swept a lot of oil already, so if we get an incremental additional recovery with this we can credit to the low-sal water injection,” Denis said.

Those factors combined make Endicott an ideal place to do a demonstration because the results can be accurately measured and verified, he said.

Oil companies have known for years that injecting water with a low saline content has some benefits in production but those have not been quantified. Also, the low-saline water has caused changes in the reservoir rock that have caused problems in drilling, so most companies have stayed clear of low-saline water injection.

Denis said there is some production experience in Russia where fresh water from lakes has been used in waterflood, and even on the North Slope where brackish water with a lower saline content produced in wells and used in waterflood has enhanced oil recovery. But the benefits have never been quantified in ways that will be possible in the Endicott demonstration, he said.

The process has worldwide implications but BP's focus, if it is found to work, will be with other large, mature North Slope fields like Prudhoe Bay and Milne Point where reservoir conditions are condusive. If applied in other fields on the Slope, low-salinity waterflood could add hundreds of millions of dollars to the long-term recovery of oil.

The principal cost for any company working with in the new process is obtaining the low-salinity water, Denis said. The field infrastructure, including the injection and producing wells, are already in place, so these are available. In places where brackish water with relatively low salt content can be produced from intervals of rocks in the producing fields, the process can be implemented with lower costs. But where water is taken from the sea and treated to reduce the salt content, the costs will be higher. There are now large water treatment plants on the Slope, including Endicott, that are used to process seawater for water injection. Those would need to be modified if the process is used on a large scale.

But however promising the new process looks, it is no sure bet, Denis cautioned. “There are always risks with new technology,” he said.

BP is confident enough in low-sal that it pushed initially for a full-blown application of the process at the Endicott field, which would have required a $60 million to $70 million investment, the company told state officials in briefings.

However, other companies who are partners in the field were more cautious and wanted to see results of a smaller-scale demonstration before approving a field-wide application.