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Development pace at North Slope Milne Point slowed by low oil prices Kuparuk reservoir approaches plateau production, feathering in viscous Schrader Bluff, enhanced oil recovery tied to economics, facility availability Kristen Nelson
PNA News Editor Sustaining production at the Milne Point field on the North Slope requires finding ways to reduce the cost of producing barrels of Schrader Bluff oil. Shallow, viscous Schrader oil is more costly to produce than the lighter Kuparuk formation oil which currently forms 90 percent of Milne production. Schrader also has less value on the market, but as production of Kuparuk oil peaks, there is room at Milne facilities for Schrader oil.
And, as David Blackwood told PNA March 4, there is just too much Schrader Bluff oil in the ground to be ignored. Blackwood, manager of BP Exploration (Alaska) Inc.’s western North Slope business unit, has been responsible for Milne Point for about a year.
Infrastructure is in place at Milne. The field has been producing — off and on — since the 1980s. The real question about Milne, Blackwood said, is the smart pace at which to bring on development of Schrader Bluff oil, to add enhanced oil recovery, to look at more exotic production options. Development of the deeper and more difficult Sag River formation, he said, is “up the road a bit.” Kuparuk production mature, Schrader in infancy The majority of the production at Milne Point is from the Kuparuk formation — and most of the drilling necessary to produce that reservoir has already been done. What’s left, Blackwood said, are “a few infill locations” and the “bulk of them will be injectors, I suspect.”
But the majority of the oil at Milne Point, some two-thirds of the oil in place, is in the shallower Schrader Bluff formation. The literature, Blackwood said, contains estimates from “1 to 2 to 5 to 10 billion barrels in place of this stuff between what we call Schrader and what ARCO calls West Sak.”
Schrader Bluff is “more viscous than the classic Kuparuk oil,” Blackwood said, and is “worth marginally less” than Kuparuk oil. Also, “it’s thicker, so it’s harder to move. If you had the same pressures, the same rocks and the same pore space, less of this stuff flows than a lighter oil.” To get the same flow rates from Schrader Bluff wells as from Kuparuk wells you “have to have horizontal wells … and multi-zone completions and just more complex … technology to get the same relationship … between a flow rate and a cost.” That relationship between rate and cost, he said, is the whole issue of developing the Schrader bluff formation. Infrastructure, fixed and variable cost is in place The fixed cost of expanding Schrader Bluff production — the plant — is in place, Blackwood said, although there may be debates about whether “you do another Milne expansion or not or do you take this plant up to its limit, yet to be established right now.” We know, he said, that the plant capacity is more than the roughly 60,000 barrels a day being processed now. It is 80,000 barrels a day? Is it 100,000 barrels a day? Extensions to the plant — what might be required to add another 10,000 barrel a day capacity — “you could almost regard those as variable,” he said.
“And then there’s the seriously variable piece, which actually covers the vast majority of the expenditures in a large-scale development of viscous oil — is in the wells.” With wells, Blackwood said, you look at the productivity per dollar spent. I can have a simple well that costs X dollars, and produces 300 barrels per day, he said. “Or I can have a very sort of high-tech horizontal well that produces 600 barrels a day. But if it costs me twice as much, I haven’t taken a step forward, I really haven’t.” Both high-tech and simple wells tried For the last couple of years, Blackwood said, BP has been experimenting in both directions at Schrader: high-tech wells and simple wells. At the high-tech, expensive end, the company has tried multi-zone completions, horizontal wells, different sizes and types of the submersible pumps needed to bring the oil to the surface and different well completions. They have had some success he said. Flow rates have come up — and costs haven’t risen quite as fast as production.
In the other direction the question was how simple — and cheap — could a well be. The boundary is well integrity, Blackwood said. “It’s going to be there for 20 years, so there’s the limit.” Fewer strings of casing were used and simpler wellheads — simpler plumbing, simpler instrumentation.
Well cost for radically descoped wells has gotten down to around the hundred thousand dollar mark, Blackwood said. “They’re just very simple — just punch a hole… get it down to TD and then go to work on the completion costs which are on top of that… And we’re getting those down by similar proportions….”
Schrader slowed, not canceled “It’s been in the public domain that Schrader’s canceled, it’s dead,” Blackwood said. “No, it’s not canceled. It is going quite slowly.”
“There’s too much of the stuff to walk away from,” he said. But development is affected by current low oil prices. This isn’t the type of big capital project where you start now and look for results in five years, Blackwood said, but one where you’re pushing the button and seeing production in a pretty short time. And at current oil prices, he asked, “who’s going to do it right now?”
Schrader production is now at 5,000-6,000 barrels a day, he said. BP will continue to work with those wells drilled in 1997 and 1998, and continue to work both high-tech and low cost wells options. “And we’ll be experimenting with a few wells again this year,” he said. “It will be very few…”
The goal, Blackwood said, is to come up with something that works at $11 a barrel, because while it’s hard to predict what the oil price will be six or 12 months down the road, it’s likely that it will look about the same. And when prices rise, costs will also rise. By finding ways to develop Schrader Bluff at present prices, making it robust at the bottom end, he said, you’re also well placed if prices pick up and the cost base inflates. Kuparuk reservoir on plateau The main Kuparuk reservoir at Milne Point is nearing its peak. “We’re sort of up there and it will come down the next couple of years — it will come off the plateau,” Blackwood said.
“The question is the pace at which we feather in the Schrader. At which we feather in EOR schemes. At which we feather in even more esoteric options…” They’re working on the Schrader piece right now, he said.
“And then the next piece, which is still farther out and it’s not huge, but it’s there, is based on miscible EOR flood.” The field has had gas injection, “basically water alternating gas,” he said. Enhanced oil recovery injects natural gas liquids. “The actual NGLs which you inject are a non-trivial cost,” he said. And the pipeline to bring in the NGLs has a price, and so do the pumps. So, he said, EOR is not free. But, he said, “one of the joys of EOR is that you can play with scale. So those are the two options that you’ve got in EOR…you play with the timeline and you play with the scale. You go for the best looking areas first….”
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