BP made a decision in August to develop its Beaufort Sea Liberty project from shore, using the extended reach drilling technology it pioneered at Wytch Farm in England in the early 1990s, a technology in which it still holds a world record.
BP has used extended reach drilling in Alaska — at Niakuk and Milne Point — but the Liberty wells will go out much farther, possibly twice as far, as BP’s Niakuk Alaska record ERD well.
It’s a big change in perspective, says BP Exploration (Alaska)’s Liberty development manager Daryl Luoma.
“When you look at this as an offshore project it was kind of routine North Slope drilling. And in August we made the decision to do something that’s not routine North Slope drilling,” he said in an Oct. 21 interview.
It will be a major change for slope drilling.
“Just as Prudhoe Bay and the original Arctic development were world class, this will be a world class drilling and reservoir management project,” he said.
Originally BP proposed developing Liberty, which is on federal outer continental shelf acreage off the North Slope, as a Northstar twin, Luoma said, with development from an offshore island. But when costs doubled at Northstar, and that project took two years longer than projected, BP decided to rethink Liberty development, and in 2002 it cancelled the project.
In 2003 and 2004, “BP reassessed the concepts for developing Liberty,” and also did a lot of work with the U.S. Department of the Interior’s Minerals Management Service, on whose leases Liberty is located, with the U.S. Army Corps of Engineers, the other lead agency for permitting, and with the North Slope Borough, a major stakeholder in any North Slope development.
The 2003 and 2004 work focused on refining offshore development, using existing infrastructure — either Endicott or Badami — to process the oil. Liberty sits some five miles offshore between Endicott (some six or seven miles to the west) and Badami (some 12 miles to the east).
2005: a new charge
Luoma was brought in to manage Liberty development at the beginning of 2005. One of the requests, from both BP Exploration (Alaska) management and from “senior executives in London, was to not only understand the offshore development concepts that had been looked at, but to take a hard look at what it would take to make a development from shore work as well,” he said.
In August the decision was made to develop Liberty from shore.
There were a number of factors in the August decision to develop Liberty from shore, Luoma said:
The first was BP’s success at Wytch Farm, where the company also struggled with “difficult challenges to try and drill these wells from shore; difficult environmental challenges in trying to develop offshore,” he said.
“We’ve done this before at Wytch Farm. It was challenging then; many of the same reasons people said we couldn’t do it from shore then are the same challenges people are bringing up today. We figured it out then; we’ll do that now.”
Another factor was that industry has progressed ERD drilling since the 1990s. “There’s been tremendous progress made in terms of drilling technology, drilling best practices,” he said, with much of that progress driven by BP’s Wytch Farm drilling. Both BP Exploration (Alaska)’s drilling and wells manager, Gary Christman, and BP’s Alaska business unit leader, Steve Marshall, were at Wytch Farm when some of the ERD wells were drilled, Luoma said.
In terms of departure length, ERD wells reached 15,000-16,000 feet in the early 1990s, and by the late 1990s were reaching 30,000-35,000-plus feet, including a Wytch Farm well which still holds the ERD record. Wytch Farm wells have a true vertical depth of about 5,000 feet and ExxonMobil at Sakhalin 1 has drilled some 8,000-9,000 foot TVD wells to the 30,000-33,000 foot range.
ERD important to BP’s future
Luoma said BP also sees ERD as important to its future, with opportunities to go farther as ERD technology develops at Wytch Farm, BP’s own Sakhalin interests and at Liberty.
So a third factor in the Liberty decision was the capability BP will develop at Liberty, a capability that can be used elsewhere in Alaska “to develop state lands onshore and offshore, or federal lands offshore.” And the technology can be deployed around the world.
“It’s an important technology,” Luoma said. “It’s one we’re a leader in today and we see remaining a leader in that technology going out.”
Safety and environment were also factors in the decision: if Liberty can be developed from onshore the footprint is reduced, and you minimize safety and environmental issues. “We can develop safely offshore: we’ve done it with Northstar; we’re producing safely at Endicott; we could do it here.” But ERD technology means BP doesn’t have to go offshore at Liberty.
This technology also allows alignment with the North Slope Borough for the pro-ject.
Those factors, he said, led to the decision that “it’s the right thing for BP to do on this project.”
Probably a single pad, and a road
Luoma said no final decisions have been made, but Liberty would probably be developed from a pad at Point Brower, or another location farther east. Point Brower, he said, would allow shorter wells to be drilled first, and to the northwest portion of the reservoir, which looks best based on comparison of BP’s Liberty exploration well and an earlier Shell well in the same block.
The final decision on a pad site, he said, will be made based on which “gives you the best technical chance of being successful drilling the reservoir.”
The shortest wells would be in the 23,000-foot range, the farthest in the 35,000-40,000 foot range. The number of wells hasn’t been determined. It could be as few as eight, Luoma said, or as many as 12 or 13.
The record Alaska ERD well at Niakuk is in the 19,000-plus foot range.
Early thinking is that a road would be needed to the pad, and whether or not there is a road will affect the decision on pad size, as more storage room is needed without a road. These are issues, Luoma said, that require the approval of “a number of regulatory agencies … But to support a drilling operation like what we talked about … we think a road probably makes sense.”
Badami the base case
The base case BP is looking at right now would use Badami as the production facility, Luoma said. At Badami both leases and facilities are 100 percent BP owned. Another option that is being assessed is Endicott, which is BP-operated but not 100 percent BP owned. “But Endicott would have to be competitive with Badami,” he said.
The concept is that wells are drilled from a pad, the oil is produced back to the pad and three-phase production (oil, water and gas) is sent to the processing facility, where the oil is processed, the sales quality oil sent to the trans-Alaska oil pipeline and the gas is pumped back for re-injection. Water, Luoma said, would also be supplied for re-injection.
Badami facilities would have to be modified because Liberty fluids contain carbon dioxide. Liberty is essentially the same reservoir as Endicott, he said, so the fluids are very compatible. “Endicott handles CO2 … (with) duplex pipe … to manage the corrosion issues.”
Compatibility with Badami fluids wouldn’t be an issue, he said, because the Badami fluids would be a small volume compared to Liberty.
Likely a new rig
Gary Christman, BP’s Alaska drilling and wells manager, said a bigger rig is needed: “The equipment we have (on the North Slope) does not have the capability to do this work.”
A “significant modification” of an existing rig is possible, he said, but it’s likely that “for a unique opportunity like this it would be a purpose-built piece of equipment.”
Hoisting capability, pumping capability and the top drive would all need to be larger, Christman said: “Everything is bigger. It’s just super size everything we have.”
Depending on “what you look at in terms of horsepower,” Nabors Alaska Drilling’s rig 33E at Northstar is probably “the biggest piece of equipment” currently on the slope, he said. In terms of measured depth the BP Liberty wells would be “almost double the total of measure depth drilled from what we have at Northstar.”
It’s “double the well-path length” and “translates into different sizing issues” that haven’t yet been calculated, he said.
Hoisting requirements will be about twice as large as the loads at Northstar, pump capacity about three times Northstar and torque probably double. Detailed design, Christman said, will be needed before exact numbers are available, but hoisting capability would probably be 1.5 million to 2 million pounds hook load capability, up from around a 750,000 pound maximum available on the slope now.
Rig would be ‘beefier’
Such a rig wouldn’t be any taller, he said, but “it will look bigger more in the sense of beefier.”
Like most of the rigs on the slope such a rig wouldn’t be readily mobile. “It’s going to be pretty much a fixed installation that’s going to be purpose designed for Liberty, probably.” A skid-rail system would allow the rig to be moved from well to well on the pad.
The rig would probably be manufactured at a major yard, hauled up in pieces and reassembled on the North Slope, Christman said. It would probably take two or two and a half years to get a rig put together and to the slope. Actual construction isn’t the issue, he said. “The issues are the engineered components. In a hot market like this it’s just getting in line for the next mud pump that’s being manufactured.”
BP is just getting its drilling team put together, Christman said, and will be working on issues like the details of what is needed in a rig.
On this kind of project you want to identify the drilling contractor “pretty early on so you can work with them on terms of finalizing design and construction,” so “there would be a pretty early tender exercise to see who we’re going to be involved with.”
From the port to Rabbit Creek Road
The wells, some four and a half to eight miles long, would be “about like drilling from the port (of Anchorage) to Rabbit Creek Road,” Luoma said.
Compared to Wytch Farm, Liberty “may be more challenging; in other ways it may be helped,” he said. Wytch Farm wells have a true vertical depth of about 5,000 feet, while the Liberty reservoir is at 11,000 feet: “Gravity works in our favor, depth works in our favor a little bit here.
“But it does get down to specific geology you have to drill through and there are some differences; every location is different. It’s not one size fits all,” he said.
Luoma said existing 3-D over Liberty is being re-processed now, “and it’s possible we could choose to re-shoot 3-D” to help drill the wells.
Conceptual issues in 2006
BP will work on conceptual issues for the project next year, perhaps into the early part of 2007, Luoma said.
Permits would be submitted in 2007, and that year BP would also move into engineering for the selected concept and “final engineering on exactly what that rig would look like.”
Permits would be in hand in 2008 and with permits in hand, BP would go for corporate approval of the project.
“And then we would move into the procurement, fabrication, construction (in) 2008, 2009 (and) 2010.” The rig would be built in the 2008-2009 timeframe, mobilized to the slope in 2010 and start drilling in late 2010, he said, with first production in 2011-2012.
“Not something you can easily go out and do in a year’s time. And a big piece is to work through the concept and get the regulatory approvals in place that enables the project,” he said.
The up-front regulatory work is crucial, said BP Exploration (Alaska) spokesman Daren Beaudo. “We didn’t want to jump in and do a bunch of advance engineering … spending a lot of real dollars, until we knew where we were going to stand to a certain degree of certainty from a regulatory standpoint, and with these important stakeholders.”
For that reason, Beaudo said, there have been a lot of conversations and a lot of information sharing over the last couple of years.
“We’re an engineering organization,” he said, and usually engineering comes first and then “the permitting and the relationship stuff and we kind of reengineered the process to be the other way around.”
