A new enhanced oil recovery technique using water could be tested at Endicott on Alaska’s North Slope.
BP Exploration (Alaska) is doing preliminary engineering for a full field test of its proprietary low-salinity waterflood, LoSal™, and hopes to sanction the project this year.
Steve Marshall, president of BP Exploration (Alaska), gave an overview of the project at the Alaska Support Industry Alliance “Meet Alaska” conference Jan. 20.
Petroleum News sat down Jan. 25 with BP’s John Denis and Kirk Johnson to learn more about the project. Denis is BP’s Alaska consolidated team subsurface team leader; Johnson is the Endicott LoSal™ project manager.
Waterflood, like gas flood, is one of the standard techniques industry uses, Dennis said. Gas flooding is followed by miscible injectant, an EOR technique, and LoSal is “almost like the water equivalent” of miscible injectant, with low salinity water following standard waterflood. Both miscible injectant and LoSal™ are techniques stimulating oil movement in the subsurface and both are EOR techniques, he said.
Idea has long history
Denis said the idea of using different water has been around in the industry for decades, but “I don’t think the industry ever really figured it out. We think we may have. And so we’re moving forward with this in a new and different way than anybody else has.”
The process has been under development by BP at its Sunbury research lab in England for about three years.
There’s been anecdotal evidence, some of it on the North Slope, but in the last few years BP researchers “began to connect the dots,” he said.
At Milne Point BP does some waterflood with low salinity water, using source water from a well which is less saline than Beaufort Sea water. BP Exploration (Alaska) spokesman Daren Beaudo said BP “saw an impact from the lower salinity water” at Milne Point.
The technique has worked in the lab, where core from reservoirs is flooded with different waters. BP has also done “near-wellbore tests where we’re investigating out a few tens of feet into the reservoir,” using tracers to watch for changes, Denis said.
The technique works in the lab and in well tests. What BP needs now, he said, is tests between wells of a few thousand feet in a reservoir.
“And that’s the piece where you have to just go and put your money down and ... test it and get the confirmation.”
BP screened its worldwide portfolio of fields and Endicott was selected as the best place to test the technology, Denis said.
Preliminary engineering
Johnson said preliminary engineering for the Endicott test is going on now. In the conceptual phase Endicott was selected for the test both because of the kind of field it is and because it “has much of the infrastructure already in place required to produce a lower-salinity water source to the wells” such as the seawater processing facility.
The elements that BP will add are reverse osmosis and micro-filtration. Both are membrane technologies, Johnson said, and BP wants to “prove these up for future use in the near term ... at Prudhoe Bay and then eventually at our global facilities.”
Reverse osmosis technology is used worldwide in desalination to take solids and salt out of water. It’s not a new technology, Johnson said, but is a new technology for this application. Micro-filtration will be used to take solids down to less than 10 microns.
There will be some retrofit to existing facilities at Endicott, “but we do plan to construct and erect a module that will require sealift, a pretty substantial-sized module,” Johnson said. The module will come up on sealift in 2008.
There will be some civil work required at Endicott, a new pipeline will be built and some wells will be converted.
A good portion of the work will probably be in 2008, Johnson said, but BP would like to do some work — “retrofit of existing modules, the pipeline, that type of work” — in advance of 2008 because of limited space at Endicott.
Plant will handle 50,000 bpd
Endicott has production of more than 200,000 barrels of water a day, Denis said. “We won’t build a plant big enough to replace all of that, but we’ll build a plant to produce 50,000” bpd. The field will be flooded area by area, and as each area is depleted of oil, they’ll move on to another area.
The surveillance portion of the project will also require some new technology, Johnson said. Because Endicott is producing so much water in some areas “it’s going to take some new technology to really pick up subtle changes in water cut because the rates are so high.”
Endicott is “so mature, we’ve stripped the easy oil out,” Denis said.
But significant oil remains, although incremental oil recovery is now in the 3 percent to 7 percent range, and “you’ll want to be precise in finding those small differences because that’s actually a big chunk of your recovery given there’s mostly water left and not much oil left.”
Endicott currently produces some 19,500 bpd, down from a peak of 115,000 bpd, Denis said. State records show that through November the field had produced almost 444 million barrels of oil.
Marshall said the incremental recovery at Endicott from this technology could be some 30 million barrels, with hundreds of millions of barrels possible across the North Slope.
Part of the reason Endicott was chosen is that the field has 400 million to 500 million barrels of oil remaining in the ground, Denis said. “And without this technology we might walk away from that field and shut it and there’d still be 400 million barrels down there just because the oil hangs onto the rock and you can’t liberate it.”
The remaining oil at Endicott is a large target, and with infrastructure in place, “if we can find these new technologies,” there are “nice targets” remaining, he said.
Should apply to Prudhoe, other fields
In terms of the sub-surface the technology should work at Prudhoe and in the Prudhoe satellites, Denis said. BP has already done some low-salinity work at Milne Point.
The fluids in each reservoir are unique, he said, and you have to get “the right cocktail for the right application. But early indications are that there’s a lot of the North Slope reservoirs that this will work for.”
The exception, Denis said, is Northstar, “essentially a clean reservoir with very volatile fluids. If you don’t have a lot of residual oil left, you don’t have a big target to chase.”
Applications would be at fields with significant residual oil, “most of our big major fields and our more viscous fields.” But there is a limitation to the technology with viscous oil, because some viscous oil is waterflood-able, and some is not. Where viscous oil can be waterflooded, low-salinity may have applications, Denis said.
Challenge of new technology
Marshall talked about a “buzz” in BP’s Anchorage headquarters.
“It’s really fun to be in a place where we’re doing things that are going to be game changes for Alaska, or game changes for BP or maybe game changes for the industry.” There’s uncertainty that goes with being the first to try something new, and certainly naysayers, he said. It was the same with miscible injectant: there were industry experts who said that wouldn’t work when it was first tried.
With any new EOR process you’re changing things in the subsurface. You can do remote sensing, but you can’t actually see what’s going on, Denis said.
He compared it to going to the moon: you can do all the work, but you don’t know until you actually do it. “We can do all this work; we can do all the analysis; we can do all the modeling; we can do all the testing.”
The proof will be in the full-field test at Endicott.
