BP Exploration (Alaska), no longer active in traditional exploration in Alaska, is focused on exploring for — and recovering — resources at Prudhoe Bay through technology.
BP is a successful explorer worldwide, Scott Digert, the company’s resource manager for full-field waterflood in the Greater Prudhoe Bay business unit, told Petroleum News.
The company has “done really, really well in remote basins,” areas like the deepwater Gulf of Mexico and the deepwater off Angola, Digert said. But in Alaska, it wasn’t “seeing that same sort of success.”
BP is now focusing on where it thinks the big remaining resources are in Alaska — and that’s “around the existing oil fields,” Digert said, undeveloped oil at the BP-operated Prudhoe Bay field and heavy oil across the slope.
“We actually know where it is. The problem is getting it out,” he said.
Frank Paskvan, Prudhoe Bay western region subsurface development manager, said “BP globally is amongst the top tier of world-class exploration companies.” BP wants to be not just the world’s best explorer, but “the world’s best explorer and recoverer of oil,” he said.
At Prudhoe Bay, with 30 years of development, there have been “a series of projects, wells, reservoir techniques and facility expansions that have substantially improved our ultimate recovery,” Paskvan said.
More oil has been recovered to date at Prudhoe than was estimated for total recovery when the field went online in 1977.
Original oil in place at Prudhoe Bay was 22.6 billion barrels of oil, Digert said. The original estimate was that about 42 percent of Prudhoe oil could be recovered, some 9.5 billion barrels; to date, more than 11 billion barrels have been produced.
The belief now is that another 2 billion to 2.1 billion barrels, can be recovered, he said.
“We know where the oil was to start — before we started moving things around — so now the question is, of the oil that’s left, where is it?”
One thing that helps with oil recovery is three-dimensional seismic with its “much finer vertical resolution.” Faults can be seen on a smaller scale, Digert said, probably around 20 feet vs. 60 feet originally.
Four-dimensional seismic, comparing seismic with that shot earlier over the same area, can show “changes in fluids or pressure from the injection that we’ve done,” he said, and “… helps you identify where are the pockets that you’re not sweeping out” either in the gravity drainage area or with water. “And now you can start targeting the sidetracks into these smaller and smaller remaining pockets of oil.”
And with new technologies — coiled tubing drilling and multilateral wells — “you can now start to envision how you can actually target these smaller and smaller pools, things that we couldn’t have even done two or three years ago.”
2,500 wells drilledInformation on remaining oil also comes from “a pretty active appraisal and delineation effort within Prudhoe,” Paskvan said. Some 2,500 wells have been drilled, and starting in the mid-‘90s, BP did appraisal drilling “on what you might call initially discovered satellite reservoirs.”
This included delineating the western satellite pools — Aurora, Borealis, Orion and Polaris and it also included the Put reservoir, “an accumulation that was included in the (Prudhoe Bay) initial participating area,” he said.
The Put, now on production, was found in early field drilling.
“We’ve gone back in the last half-dozen years, figured out where that hydrocarbon is gas and where that hydrocarbon is oil; where the reservoir quality is the best and where it’s not so good; where we should put in water injectors; and where we should put in oil producers,” Paskvan said.
“The Sag River formation falls in exactly the same category,” Digert said. “It’s something that we’ve known about; we’ve drilled through it.” The Sag is minor compared to the Ivishak — the major producing formation at Prudhoe — and sits right above it. It’s “much tighter. It’s still nice, light oil, but it’s a much more difficult reservoir to produce from. It’s thin and tends to be broken up by the faulting more; and it’s much less productive.” When Sag River is commingled with Prudhoe Bay Ivishak production, Sag may only be contributing 1 to 2 percent of the total.
But it’s being targeted now with horizontal wells, Digert said.
Where are more than a billion barrels of oil in place in the Sag, said Paskvan: “We’re still working on technologies to make that actually work.”
Digert said the recovery factor for the Sag will probably only be a few percent of the billion-plus barrels in the formation.
The best Sag recovery has been “adjacent to the gas cap where continued gas reinjection provides pressure support. Waterflooding of that reservoir is very difficult because it’s low-low permeability,” Paskvan said.
The Sag has been targeted at the Milne Point field, Digert said, where there isn’t a gas cap. Out of a dozen Sag wells drilled at Milne, only one is currently producing. “So it’s very difficult.”
Better resolution in seismic helps with the Sag, because faults are easier to see, Digert said.
The Sag was “highly marginal 20 years ago (but) is starting to look now like it’s competitive with other drilling opportunities,” he said.
Economies of scale
For continued development on the North Slope you need a “certain economy of scale … to make things work,” Paskvan said.
Ten to 11 rigs are active in the Prudhoe Bay area year in and year out, he said, with an annual average of seven rigs working. That includes coiled tubing, workover and rotary drilling rigs. That’s part of the North Slope economy of scale that Prudhoe Bay brings to the North Slope, he said, because the rigs are mobile and you can bring in a rig to do a specific job.
It’s not just the rigs, he said: “It takes people who really know and have experience doing what they’re doing to get it right,” Paskvan said.
Vertical development“The State of Alaska talks about a string of pearls,” Paskvan said. “… And I think they thought of it as … stringing pearls along the Barrow Arch,” and fields have been added laterally across the North Slope.
“But we’re stringing pearls vertically,” he said.
Referring to a schematic of stratigraphy in the western satellite area of Prudhoe Bay, Paskvan noted that the Schrader Bluff Orion accumulation lies above the lighter-oil Borealis pool — and both lie above a Sag-Ivishak accumulation. And above all is the Ugnu, the heaviest oil on the North Slope, which is not yet being developed.
This is known oil that lies above developed fields in shallower formations.
Development started with the deeper, light oil. The companies knew the heavier oil was there, but “the technologies were available at the time of development to go in and develop the Prudhoes and the Kuparuks of the world,” Paskvan said. Deeper, lighter oils have a lower viscosity — they flow more readily. The Schrader Bluff-West Sak formation is heavier oil, but it can be waterflooded, and 100 million barrels have been produced to date.
The “transforming technology” for Schrader Bluff-West Sak production was horizontal drilling, Digert said, “drilling these long horizontal producing wells.” Production went from an initial 200 barrels per day with vertical wells that dropped off quickly to 50 bpd with “wells that have come on above 1,000 barrels a day,” he said.
“They still decline pretty fast, but you’re starting from a much higher point so it’s been absolutely transformational in our ability to now drill this lighter heavy oil.”
Western region developmentIn recent years the number of developed oil pools at Prudhoe Bay has doubled, Paskvan said. Aurora, Borealis, Midnight Sun, Polaris, Raven and Orion have all been brought online.
Four of those accumulations — Aurora, Borealis, Orion and Polaris — are in the western region development area at Prudhoe Bay.
This is the area of Prudhoe Bay west of the Kuparuk River, said Paskvan, “a huge area and known accumulation of reservoirs discovered originally, drilled through to prove oil up … during the original Prudhoe Bay appraisal.”
“The western region is kind of a microcosm of the North Slope story, because you’ve got Ivishak development first (deeper, lighter oil), more than 250 million barrels produced to date from the western region,” from more than 220 wells producing some 50,000 barrels per day, Paskvan said.
“And we’re unlocking the heavy oil resource as we’re moving through … the reservoir,” he said.
Western region development started with “Eileen West End development in 1988, continued with the Borealis reservoir installation in 2001 of L and V pads,” Paskvan said.
Z pad is being expanded now and a new pad, I, is proposed for the far northwest corner with startup planned for 2011.
“We’re adding a gas partial processing plant on Z pad,” and will use gas-lift to get more oil out of the reservoir.
Paskvan said I pad appraisal wells were drilled in the winter and spring of 2006 and engineering is being done for the area today. Z pad expansion should be put in next year, he said, with startup in 2009; I pad would be installed in 2011.
This is the long-term forecast, he said. Full funding has not yet been approved.
“Western region development is … such a large program that we broke it into separate projects,” Paskvan said. Some elements are operating — which accounts for the 50,000 bpd from the area — other components have not been sanctioned, but are budgeted over the next five years.
$2 billion in futureThe Western region development is an ongoing five- to 10-year program with an estimated $2 billion in future investments.
Paskvan said those investments are “offsetting natural decline” as well as “pushing the limits on resource development.”
At least half a billion has been spent recently on the western region, Paskvan said, excluding the original Eileen West End work.
The current project involves some 400 people including 120 technical staff split between drilling, subsurface and facilities. There are about 100 project engineers working in Arcadia, Calif. — and a subcontractor has run out of people in the United States to work on oilfield equipment and is looking at doing some engineering in Beijing.
About 150 people are working on the fabrication, “building this equipment and installing it,” he said.
And, because Prudhoe is mature, Paskvan said the challenge is to process and reinject all of the gas that is produced with the oil and produce all of the seawater needed to supplement produced water for waterflood.
With equipment fully employed, there is no idle equipment for a project like western region development.
Because of that, sealift modules will be required for western region development, with three sealift modules planned. That’s happening because “the drilling successes, the recovery successes, have created an opportunity to put in a new facility,” Paskvan said.
The target is a 2010 sealift, he said. Long-lead materials commitments have been made to preserve the option.
If that portion of the project is approved, the sealift modules would come up in summer 2010 and the startup target would be the fourth quarter of 2010.
Ugnu challengedKnown but undeveloped oil extends beyond Prudhoe Bay.
“Over half of the known North Slope oil remains to be developed,” Paskvan said.
This oil is primarily in the shallow, cold, heavy Ugnu formation: Of the 20-billion-some barrels of oil in the Ugnu formation, current production is zero.
“When you see 20 billion barrels sitting there, even though (production) is zero today, it can’t stay zero,” Digert said. “There is a way and we’ve got the energy to find that.”
He said the search is on for technologies that will allow Ugnu production. There have been a couple of Ugnu wells, but they’ve been pretty unsuccessful.
Waterflood doesn’t work on Ugnu, the shallowest and heaviest of the North Slope formations.
A new technology, cold heavy oil production with sand, is being tried now “with different pumps and different wellbore style to see if we can actually keep that sand from moving out of the wellbores better.”
Light oil technologiesFor lighter oil Prudhoe Bay development is underpinned by waterflood technologies and enhanced oil recovery through miscible gas injection.
And new technologies are being developed and employed, technologies which allow BP to move “beyond the easy oil into the more challenging, difficult bypassed oil or more challenging high-viscosity heavy oil,” Paskvan said.
Examples of new technologies are low salinity waterflood and Nalco’s Bright Water™, which allows redirection of water injected for waterflood.
Talking about low-salinity waterflood, Digert said BP thinks that “by changing the chemistry of the water we inject and actually engineering that chemistry, we can increase recovery in zones that have already been flooded by mobilizing some of the oil that’s been left behind” by earlier waterflood. “And in some cases we see that as being as much as 10 percent of the oil that was originally in place,” and at BP’s Milne Point field, he said, the original oil in place is about a billion barrels.
Bright Water™ is also a waterflood technology, in this case a way to redirect injected water, not a change in the water injected.
In areas that are under waterflood, where the oil has been displaced, water can move through the area where oil has been displaced and move rapidly from the injector to the producer without moving oil, Paskvan said.
The water is following a route through portions of the formation where the oil has already been swept.
Bright Water™ redirects the waterflood.
Particles are pumped into the injector well. The particles are so small they move into the sandstone. Heat in the reservoir expands the particles, which mesh up with other particles, filling the pores in the sandstone through which water had been moving, creating “a deep diverting block” which prevents water movement, Paskvan said, causing injected water to move into new areas where it can sweep remaining oil to producing wells.
Digert said those are only examples of innovative technology used at Prudhoe: Alaska is a key technology area for BP, he said. Considering the size of BP — 100,000 people and $20 billion a year in capital deployed worldwide — Alaska is a recognized leader in technology within BP, he said.
Renewal projectDigert said that while the good news is that Prudhoe has produced more oil in 30 years than was expected — and BP now sees a much longer future on the North Slope — “the downside of that is … we find ourselves with facilities that were built for a 30-year future.”
The company is now “heavily engaged in what we call our renewal project.”
Digert said that’s a little misleading because “really you’re rebuilding for a future that’s different from your past.” The future, he said, will include heavy oil and hopefully major gas sales.
What’s needed for heavy oil, Paskvan said, is modifications within Prudhoe, including equipment that allows heavy oil production through facilities designed for light oil.
Digert said modifications were done at Milne and will also be needed at Kuparuk to handle West Sak heavy oil.