Endicott, the first offshore Arctic island production facility, celebrated its 20th anniversary in early October.
First production was Oct. 3, 1987, said John Denis, east resources manager for BP Exploration (Alaska)’s Alaska consolidated team. Denis is the subsurface manager for the eastern side of the North Slope — Northstar, Endicott and Liberty (still in the planning stage).
There were a number of North Slope firsts at Endicott, Denis said in an Oct. 9 interview, and the field is slated for another first when a pilot test begins using low salinity water to sweep crude oil remaining in the field.
Endicott produces from the Kekiktuk formation; “it’s effectively the same system as the Prudhoe system, it’s just a different reservoir,” Denis said.
It’s a highly efficient reservoir system, like Northstar, he said. Both those reservoirs have a quick drop in production “because you recover the oil so quickly.”
Endicott and Northstar are “highly efficient, high rate-of-recovery” systems, unlike Kuparuk and West Sak that “will run for 50-60-70-80 years, but the oil comes out slowly.”
Room for LibertyEndicott production topped out at some 120,000 barrels per day; today it is some 15,000 bpd, Denis said.
Like most other North Slope fields, Endicott has plenty of oil capacity but maxes out on gas handling capacity. Denis said Endicott is producing as much oil as it can, but when Liberty comes online — although it is not yet approved, the plan is to drill Liberty from Endicott and process Liberty through the Endicott facilities — that oil will have more oil per volume of gas and will have “a higher yield of oil for gas and so you’ll divert some of that gas (handling) capacity to use at Liberty and pull a lot more oil.”
Liberty, estimated at 100 million barrels, is expected to produce up to 50,000 bpd, so total production out of the Endicott facility will be some 50,000 to 60,000 bpd.
“It’s the same reservoir as Endicott — it’s in the Kekiktuk — so we know how it will flow and produce: it will be a great little reservoir,” Denis said.
From lab to fieldThe low salinity test planned at Endicott uses a method that is counterintuitive to the oil industry, Denis said. Injection of low-salinity water has been avoided, he said, because it gets into the rock and swells the clay. Conventional wisdom has been: don’t put low-salinity water into your reservoirs, he said.
That makes sense until you look at “the detail of how residual oil is held in the rocks.”
At Endicott, even with waterflood, some 40 percent of the oil will remain in place — even after the reservoir has been flushed with four or five volumes of water, Denis said.
Oil is an organic module and it is chemically bonded to the rock.
“We’ve been studying that bond and we think we’ve found a way to break it” based on “the cocktail of water you put back in there to break that bond that’s holding that organic module onto the clay.”
BP has proved it in the lab and in some field trials “and we’re just upscaling all that and that’s what the Endicott pilot’s about.”
Denis said the goal is to “convince our partners and everybody else that it works. They’re asking legitimate questions because they … haven’t done the ground work we’ve done, the homework that we’ve done.”
A couple of years ago BP was pushing a full-field low-salinity flood at Endicott that included a reverse osmosis plant to process seawater, but partners weren’t comfortable with that, Denis said.
Some anecdotal evidenceThere is some anecdotal evidence that low-salinity flooding is effective.
In Russia there are places where they have flooded reservoirs with river and lake water.
And at Milne Point, another BP-operated field on the North Slope, there’s some flooding with brackish water from shallow reservoirs. This water isn’t freshwater quality, Denis said, but it’s fresher than seawater. It was used at Milne because BP couldn’t get seawater there.
When they looked back later, they found that the formation pattern flooded with brackish water was performing better than a pattern next to it, flooded with seawater.
100 million barrel goalThe original oil in place at Endicott was 1.1 billion barrels; some 500 million barrels have been produced, so hundreds of millions of barrels are left. Using low salinity, “we’ll get at least 100 (million barrels) of that, maybe more,” Denis said.
An additional 10 to 15 percent of the oil in place will be produced if low salinity works as BP thinks it will.
“We’re asking ourselves kind of how efficient is it going to be and that’s where you can do all the lab work and you can do a lot of testing” but testing in the field will show what the performance is, he said.
Work on low salinity began in BP’s lab in Sudbury, England, some 10 years ago, Denis said. The company thinks low salinity flood has “global application and BP has picked Alaska to demonstrate.”
BP believes it is two or three years ahead of other companies, but at conferences it’s become clear that Statoil, Total and Exxon have all started work in this area.
As for applicability elsewhere, Denis said he thinks low-salinity flood has applications in the gas-caped fields on the North Slope. “But again, it comes back to knowing your rock, your clays and your oil types. And you’ve got to match the chemistries up,” he said.
“So it won’t work everywhere but it will work in a lot of places.”
It will also work to different degrees: If it will only give you an additional 2-3 percent of original oil in place, it probably isn’t worth doing, Denis said. “If it gives you 10 or 15 percent incremental recovery you’ll go for it.”
Pilot starts soonThe “unambiguous demonstration” is the next step for low salinity.
“We’re cementing, getting our perf intervals right in our wells, doing pulse tests. There’s kit ordered. … We will have all of our service facilities in place before the end of the year.”
Produced water will be used to flush the area first and while there is pumping going on now, Denis said “we don’t think we’ll get this pattern where we want it until early next year.” He said they hope to have “water going in the ground … by the middle of next year, if not sooner.”
The water for the test will be trucked from the Duck Island gravel pit which contains melted snow. The volume will be 5,000 to 6,000 bpd once the test gets up to full speed. “We’ve used this water for our testing and we can get this water to the right chemistry we need,” Denis said.
There will be results available within months from the $10 million pilot test, he said.
Denis said he’s “very bullish and positive — but this is new technology.” A lot of research has been done, a lot of time, effort and money put into the project, “but with new technology you never really know and there’s a little risk.”
The project will involve either one producer and one injector or one producer and two injectors.
Testing to this point has been from a single well, “but when you’re down 10,000 feet all you’re doing is investigating out a few tens of feet.”
The planned test will “take a wellbore and go 1,000 feet away and — inject here and produce over there and see what kind of performance comes out of that well.”
Why Endicott?Endicott was chosen partly because it’s a mature reservoir, Denis said.
“It’s got great rock … and it’s very mature in its depletion so you have high confidence that you’ve swept a lot of the oil out. And you know you’ve watered everything out.”
So if incremental oil is recovered it will be clear it comes from the low-salinity flood.
Endicott is also a “very well understood system — we’ve got a tremendous data set” that BP has acquired at Endicott over the years, he said.
And Endicott has a high level of residual oil: “It’s got 40 percent of oil left."
More drilling possibleThere used to be a rig parked at Endicott but that was removed about four years ago and has been rebuilt and is being used elsewhere on the slope.
Endicott now does winter-only programs, Denis said. For the last three years BP has built an ice road to Endicott and is doing it again this year. A rotary rig or a coil tubing rig or sometimes both come out the first of February and stay until April, he said. Most of the work is workovers, “fixing and repairing and getting wells healthy.” Endicott is drilled up, although “we occasionally find another little sweet spot that we put a sidetrack into, but it’s mostly about just getting the wells so that they’ve got a longer future ahead of them.”
That work is “slow and steady,” he said, “but I think at some time in the future we’ll ramp all that up” when the low-salinity program takes off.
“I mean that will be another kind of major investment coming for Endicott and then we’ll drill a lot more wells and replace well stock.”