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Enhanced oil recovery begins at central North Slope’s Milne Point EOR, starting in December, adds 20 million barrels recoverable to light oil from field, could also be applicable to viscous oil at Milne Point in future Kristen Nelson PNA Editor-in-Chief
BP Exploration (Alaska) Inc.'s Milne Point field produces some 55,000 barrels per day. That's a big increase from the 20,000 bpd the field was producing when BP acquired it in 1994, but there is “a tremendously large reserve base under Milne, both in the viscous and in the lighter oils,” Ed LaFehr, BP's Milne Point delivery manager told PNA Dec. 14.
And over the last couple of years, he said, BP has embarked “on a rather aggressive strategy to unlock some of that potential,”
A part of that potential, some 20 million barrels, is being unlocked beginning this month with a $30 million project enhanced oil recovery project, LaFehr said.
The Milne Point enhanced oil recovery project, targeting the Kuparuk reservoir light oil at Milne Point, builds “on the successes that Phillips has had in the Kuparuk reservoir” at the Kuparuk River field, he said.
But BP has more in mind that just light oil.
“It's strategically important that we get EOR to work and be economic,” LaFehr said, “because this isn't where EOR stops at Milne Point. If this works, we would have the ability to expand that into the peripheral areas of the light oil and then also, most importantly, into the viscous… And that's where a big chunk of reserves are hiding … in that tertiary recovery area.”
Time for tertiary recovery at Milne The EOR project is in start-up at Milne Point, Bill March, BP's projects manager for Milne Point, said Dec. 14. And “it's time in the life of the field for us to be doing an EOR recovery” at Milne Point, he said.
BP has been doing water flood — secondary recovery — at Milne Point since the mid-'90s, he said, “and it's time for tertiary recovery.”
“The project involves injecting a solvent into the reservoir so that it dissolves and picks up oil that's been left behind from the water flood,” he said. Incremental recovery in the project area is expected to be 7-9 percent, about 20 million barrels of oil.
“The equipment for the project is very simple,” March said. “It's a pipeline to import NGLs, natural gas liquids, from Prudhoe Bay; metering and a pump to pressurize the NGL. And then it's mixed with gas that's already at injection pressure.”
Gas produced at Milne Point, except that used for fuel at the field, is already being re-injected. So NGL is brought up to the reservoir pressure and mixed with the gas.
“That forms the solvent. Which is injected into the injectors,” he said.
March said the existing distribution system for re-injecting gas will be converted from immiscible to miscible flood by adding NGLs, so basically EOR begins at the same time in those areas of the field covered by injector wells.
It will take six to 18 months to see returns from the injection, which will show up as increased oil production from the producing wells close to the injectors.
No new gravel “This is a wonderful project” in terms of equipment and footprint, because there is no new gravel,” March said.
“We put a pipeline on existing vertical support members, right alongside of our oil sales pipeline. So there's no new footprint there for the pipeline. This pump that I mentioned is in a module that's on existing gravel pad and the distribution pipelines in the field likewise are on existing vertical support members.”
The gas mixed with NGLs — miscible gas — will be injected into the same injectors formerly used for re-injecting field or immiscible gas.
This is a water-alternating-gas system, March said. In any given injector, you inject water for a period of weeks, and then you “close valves, open up other valves, and you put gas in there for a similar period of time.”
Some injectors are on water, some are on gas, and then you switch, he said. “You've got to get rid of all your fluids. So the right number have to be on water, the right number have to be on gas. So when you switch one from water you've got to switch one from gas — it's orchestrated”
More injectors will be on water at any given moment than on gas.
“It's quite a coordination thing. The water's coming at you — it comes with the producing wells — the gas is coming at you, it's coming with the producing wells, so you have to manage that.”
Almost all of Kuparuk reservoir March said the EOR project covers almost all of the Kuparuk reservoir — the light oil — at Milne, with the exception of some edges of the reservoir.
“It's not any of the viscous oil, the Schrader Bluff reservoir,” he said. “One benefit of this project is that it gets Milne into the EOR business, gets us both equipment and experience in running an EOR project at Milne. And we hope that we can use that to springboard off at the right time in the development of the viscous oil reservoir. So there's some upside to this beyond just the immediate project scope.”
“The reserves prize is much, much larger in viscous than it is, this 20 million barrels,” LaFehr said: “There's an enormous opportunity out there for us if we can get this to work.” A viscous oil EOR project could tap 100 million barrels, he said.
EOR projects marginal Engineering for the Milne Point EOR project began in 1996. BP has been working on the project fairly diligently for five years, and really ramped up the work a couple of years ago, LaFehr said. “It took us a long time to get traction on an EOR project. These things are not easy.”
EOR projects are tough to do economically, he said, “because they require NGLs and gas. You're putting hydrocarbons down into the earth and expecting certain returns.” Those returns are in addition to the high-value hydrocarbons that are being put into the ground. By definition, LaFehr said, these are marginal projects.
The natural gas liquids used in the project have to be purchased from Prudhoe, and have to be transported to Milne Point.
More difficult than Kuparuk While EOR at Milne Point mimics the EOR at the Kuparuk River field, “our sands are a bit more challenging,” March said, with the reservoir at Milne Point thinner and containing more faults than the Kuparuk River reservoir.
“The way we have to optimize our EOR is through understanding our fault block geometries and our patterns,” he said. “Milne is really 50 small fields, it's not one large field. It has … more than 50 separate hydraulic units… which makes it terribly challenging. We may have two wells in a given hydraulic unit,” he said: “one injector and one producer.”
LaFehr said BP has a global program called reservoir value assurance — experts who help local operators understand reservoirs.
“And one of the things they do is what's called a complexity index, a reservoir complexity index. And Milne Point has one of the highest reservoir complexity indices in our portfolio.”
That's globally, LaFehr said. “So it's one of those areas that is challenging. At the same time, if you can figure it out, if you can see the reservoir, you will see opportunities that no one had been able to see before.”
Project safely done LaFehr and March both said BP is pleased with the contractor work on the project.
“We're very proud of the safety record on this project,” March said: “We've had no lost-time accidents on this project. …
“I want to give some credit there to the contractors that worked on the project. Houston Contracting did the pipelines and they did a great job. They were working under schedule pressure and yet they did the job safely — good safety records. … And not just Houston, but also APC installed the module at the slope. They did a good job.”
The module was built in Anchorage by APC Natchiq Inc. The engineering for the project was also done in Alaska, March said, by VECO Engineering.
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