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BP completes quad-lateral at Orion Drilling end of viscous equation appears solved; production of heavy oil still an issue because of sand produced with oil and well maintenance issues Kristen Nelson Petroleum News Editor-in-Chief
The viscous oil resource on Alaska’s North Slope — like the natural gas resource there — has been known for decades, but heavy oil has been as stranded as gas, stranded in the ground through lack of the technology and knowledge necessary to produce it.
BP Exploration (Alaska) has been working on ways to produce viscous oil, also referred to as heavy oil, at Milne Point since the 1990s and now also has viscous oil under development in the western Prudhoe satellites.
Multi-lateral horizontal wells have solved the drilling side of the viscous equation, but problems remain on the production side, members of BP Exploration (Alaska)’s drilling team told Petroleum News in late September.
Viscous oil accumulations lie closer to the surface and are colder, less mobile and have poorer reservoir quality than conventional crude oil, said Mik Triolo, Greater Prudhoe Bay operations drilling engineer.
Triolo worked the Schrader Bluff viscous accumulation at Milne Point before moving over to Orion, working on the early multi-lateral and horizontal well designs in late 1999, early 2000. “And we’ve progressively evolved that technology ever since,” he said.
That work is continuing at Orion, a Prudhoe Bay western satellite viscous oil accumulation. Multi-lateral wells, well bores with multiple horizontal laterals into shallow sands containing viscous oil, make wells productive enough to be economic. First tri-lateral in 2003 In 2003, BP drilled the first tri-lateral multi-lateral well on the slope, and this year, the company set a world record with a quad-lateral well.
“Horizontal multi-lateral wells have been the key to unlocking those (viscous) reserves… predominately through efficient geo-steering within the segregated sands… Rather than undulating through them,” Triolo said, “we actually stick dedicated laterals into each one of the sand intervals.” In addition to better ability to steer through the formations, drilling also helps viscous oil development with “good well design,” he said.
A crucial part of the well is where the laterals branch from the main well bore, and BP has also been trying different junction designs, the connection between the main well bore and the lateral.
At Milne Point BP determined “that the level three, the TAML level three junction, was the junction of choice…,” Triolo said. TAML stands for Technical Advancement of Multilaterals, an organization set up to regulate “the different levels of multilateral junction equipment such that everything is standardized,” he said. “So if Baker comes out with a level-three junction, the criteria that are set up to distinguish between a level-three and a level-four, are the same as for Halliburton…”
The TAML levels, said Mark Johnson, BP senior coiled tubing drilling engineer, “refer to the re-entry capability of the junction and how well it seals or isolates at that junction.” Re-entry capability and the seal provided are the two primary things a junction does, he said.
Triolo said BP determined “that we did not need isolation at the junction — what we needed was access to the lateral, so the level-three junctions became the method of choice.” First level-three, quad-lateral well in world BP took its experience at Milne Point to Orion, a western Prudhoe Bay satellite, and this year “we drilled the first level-three quad-lateral multi-lateral well in the world,” Triolo said. (The accompanying graphic illustrates such a quad-lateral multi-lateral well.)
BP’s initial experience with multi-lateral wells was that complicated wells were expensive for the wells group to maintain: “We didn’t really have cost-effective ways to work on the wells or impact the flow streams of the wells later in life, so we went back to the drawing board and came up with some criteria that we wanted to see achieved in our well designs, and then worked with our vendors to come up with a solution to those problems.”
The current system, he said, was “proved up in Milne Point” and the junction design was modified at Orion “to add more efficiency to the full life-cycle cost of the well,” Triolo said. Well work can now be done through the tubing, with a coiled tubing unit, without the need for a workover rig.
The total footage in the quad-lateral well, Prudhoe Bay unit L-201, was almost 35,000 feet, with “almost 28,000 feet of horizontal footage within these thin bedded sands,” more than five miles of horizontal footage in one well, Triolo said.
There were cleanup issues with the well, and BP didn’t realize full flow potential, but the well had a productivity index of 40 (a measure of barrels per pound of square inch drawdown), compared to most wells on the slope somewhere in the 20-range.
“If we could have opened it up full bore, we probably would have been somewhat tubing limited,” he said. Facility limited Right now the well is facility limited, Triolo said. Daren Beaudo, BP’s director of public affairs, said one of the things BP worked on during the summer production shutdown at Prudhoe Bay was cleaning sand out of tanks in Gathering Center 2. “One of the constraints that we’ve had is managing all of this sand,” he said.
“This is a viscous oil production issue, not a well-rate issue,” Beaudo said, and the issue is the sand produced with the viscous oil. To really produce viscous to the maximum, BP will either have to add facilities to handle sand that comes to the surface or find a way, such as screens, to keep the sand in the reservoir.
Not only does sand accumulate in production facilities, said Andy Kirk, BP’s Alaska drilling and wells performance consultant, but it also causes problems in pipelines because it is corrosive — another reason to keep it in the formation.
And if a multi-lateral well has to be shut in and the oil stops flowing, Kirk said, the sand can lay out along the horizontal portion of the well, creating dunes which plug up the well, making it difficult to re-establish production when the well is brought back online. Opportunity huge The opportunity for viscous is huge: some 1.6 billion barrels recoverable with current technology, said Gary Christman, BP’s Alaska drilling and wells manager.
“We’re going through kind of a concept selection phase … and one of the things that we don’t know is how we’re going to handle all this production, because it is different.”
“This multi-lateral technology has unlocked the flow potential,” said Johnson. “now we can finally get that reservoir to flow at economic rates — and that’s been the challenge for the last 20 years. …”
There are other issues now connected with getting viscous production to the surface, “but the key thing is that this multi-lateral has unlocked viscous oil.”
Christman said the horizontal footage drilled in the quad-lateral well, the 25,000-feet of horizontal hole, has “not been done anywhere else in the world: it’s just huge, just huge stuff.”
The issues, now, Christman said, are sand control and long-term serviceability of the multi-lateral wells: “The multilaterals are there, but do we know we can keep them all producing for many, many years?
“It will be a sand control issue… And long-term well serviceability,” he said. Well design evolved here The men said this is a slope-wide effort, with a slope-wide viscous team including BP, ConocoPhillips and ExxonMobil, working the viscous development issue, and contractors for the firms developing the technology being used.
Triolo said that while the well design in use at Orion was evolved at BP, “we’ve also shared this well design with ConocoPhillips and so they’re using it on their development,” and ConocoPhillips is “learning things over there that they’re sharing with us,” as part of the regional viscous team. ConocoPhillips operates the Kuparuk River unit viscous West Sak development effort.
The quad multi-lateral has been drilled, and a quintuple multi-lateral is planned for later this year, Triolo said, the first such well on the slope. That well, however, is not planned with five junctions coming out from the main well bore, because “some of these sands are so thin that they cannot economically support the cost of a multi-lateral junction,” so coiled tubing technology will be used to do an open-hole junction.
Four laterals will come off the main well bore; one of those laterals will split again.
The whole well will be drilled with a rotary rig, Triolo said, but will use some coiled-tubing developed technology, scaled up in size to rotary applications.
Some of that technology was developed for use over at Kuparuk, he said, so there is technology sharing among the different drilling groups, as well as between BP and ConocoPhillips.
Drilling, services and materials contractors responsible for technology for BP’s drilling program include: Baker Hughes Inteq; Doyon Drilling; Halliburton; Nabors Drilling; Nordic Calista Drilling; Schlumberger; and WellTec Tractor.
EDITOR'S NOTE ABOUT THE SERIES: Members of BP Exploration (Alaska)’s drilling group sat down with Petroleum News Sept. 28 to talk about the company’s development drilling program, recent drilling records and about the technology that is driving the company’s North Slope development drilling. Part 1 of this story, printed in the Oct. 10 issue of Petroleum News, included an overview of the company’s North Slope drilling activity and an update on its coiled tubing drilling program. Part 2, which appeared in the Oct. 24 issue, described multi-lateral drilling at Milne Point, and well maintenance work.
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