Spurred by the prospect of teasing out more oil from the Endicott oil field on Alaska’s North Slope, BP has started pumping low-salinity water at a rate of about 5,000 gallons per day into an injector well in the field. The idea is to flush oil towards a producer well that bottoms out about 1,000 feet from the injector, to test the effectiveness of the company’s new LoSal™ enhanced oil recovery technique, John Denis, ACT East resource manager, told Petroleum News June 27.
If the test meets expectations, the water will induce the flow of a bank of oil that will reach the producer well in a few months time — the test should be completed by the end of 2008 and will end up costing something in excess of $10 million, Denis said.
If the new technique goes into full operation at Endicott it could increase waterflood oil recovery by 25 to 30 percent, he said.
Waterflood
Conventional waterflood in an oil field involves pumping seawater or oilfield produced water through the field reservoir, to flush residual oil towards produc tion wells. But for a number of years people have investigated the way in which the composition of the water changes the effectiveness of the waterflood technique. BP became interested in this work and in 2003 started ramping up its research into the use of low salinity water to significantly increase waterflood oil recovery, Denis said.
Jim Seccombe, BP team lead for resource planning, explained how low salinity waterflood works.
After the removal of free oil from the pores between the rock grains in an oilfield reservoir, the residual oil left behind tends to stick to the clay that typically coats the grains, Seccombe said. However, the chemistry of the various materials involved is such that low salinity water proves much more effective than saline water in breaking the clay-oil molecule linkages — the water breaks the electric bonds between the oil and the clay, he said.
The oil attaches to the clay somewhat like Velcro, with the water disconnecting the Velcro hooks, Denis said.
Lab testing
After successful laboratory testing of the technique with rock core, BP trademarked its LoSal™ process in 2005, Denis said. And presentations about the technique at various industry conferences created a great deal of interest.
“There’s actually recognition throughout the industry that something’s really here,” Denis said. BP is a front runner in this technology, he said.
But the technique lacked a track record of use in practice.
“BP several years ago started looking worldwide, for where it could start demonstrating this technology,” Denis said. “We knew it worked from what we had done in the lab, with the core, but we needed to scale up to field level.”
Endicott turned out to be the best location for a field test, as part of BP’s efforts to use new technologies to develop new oil reserves in existing oil fields on the North Slope — Endicott is a mature field with a substantial volume of oil remaining in place.
So in early 2006 BP announced that it had sanctioned LoSal™ testing at Endicott.
The initial testing involved pumping water in and out of single wells to find out how effectively the low salinity water shifts residual oil from reservoir rock within 10 to 20 feet of the well. That form of testing has since proved successful both in Endicott and in other North Slope oil fields.
“We’ve tested four wells in Endicott and across the slope we’ve tested 30 wells,” Denis said. The tests involved a wide range of reservoir rock formations in the various fields.
The response to the technique did vary depending on which field reservoir was involved, but all reservoirs have responded positively to the low salinity water, Seccombe said.
The new dual-well test that has just started goes one step further than the single-well test by verifying that the LoSal™ technique will successfully flush oil across the considerable distance between an injector well and a producer well.
Controlled test location
To establish a suitable location in the Endicott field for this test, BP identified a relatively thin reservoir sandstone in which the fluid flow involved in the test can be constrained within a limited rock volume and to the single pair of injector and producer wells. The company checked the integrity of the test site by tracing the flow of fluids through the reservoir between the wells.
And to provide a baseline oil production level, against which the LoSal™ technique can be assessed, BP applied conventional waterflood to the test location, to a point where 90 percent of the fluid coming out of the production well consisted of water.
“We actually started flooding these wells back in December, to sweep them out,” Denis said. “You want to strip out as much oil as you can.”
Then, as the test proceeds, any reduction in that “watercut” percentage will represent new oil produced as a direct consequence of the use of low salinity water.
However, BP is certain that the LoSal™ technique does work. The Endicott field test will establish some operating characteristics for the technique, to help in reservoir modeling and production planning, Denis said. The test will also give oilfield partners confidence in the technique and will help manage the risk of LoSal™ implementation.
“These are big investments and people shouldn’t take them lightly,” Denis said.
And the next step would be full deployment of the technique in appropriate locations on the North Slope.
“The expectation is that once you gain this competency, you go full field with all kinds of applications,” Denis said.
Then LoSal™ will become part of a toolbox of enhanced recovery techniques that include the use of miscible injectant and, at some time in the future, carbon dioxide injection, he said.
Cost will vary
The cost of implementing and operating a full-scale LoSal™ operation will depend on the circumstances in a particular field location. And the source of low salinity water forms one of the main cost variables.
“The cost could vary quite a bit,” Seccombe said. “You might be in places where you can drill shallow wells into aquifers and get water chemistry that works. Or on the other extreme you might be sitting on the ocean and build a reverse osmosis plant to turn sea water into lo-sal.”
The amount of well reconfiguration needed for a LoSal™ implementation could also be a significant cost factor. Although in some situations the technique may work effectively using existing wells, in other situations wells may have to be redrilled, Seccombe said.
“So in some places it will actually be quite pricy — you’ll be installing a big kit and redrilling all your wells,” he said. “In some cases less so, because it’s a simple add on to the (existing) kit.”
In a new offshore field it may be quite straightforward to install LoSal™ from the get go, using a seawater desalination plant. For example, BP is considering the use of LoSal™ enhanced recovery in the Liberty field that it plans to develop in the Beaufort Sea, Denis said.
“You never know the (cost) answer until you know about the specifics (of a particular field),” Seccombe said. “Having said that, the key is that you now have access to a new (production) drive that you didn’t have before.”
And across an area such as the North Slope, even a modest percentage of additional oil recovery would represent a huge amount of new oil production.
