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Technology, knowledge team up at Lisburne
Alignment, subsurface knowledge, coiled tubing drilling result in two successful wells for BP at North Slope carbonate field Kristen Nelson Petroleum News Editor-in-Chief
BP Exploration (Alaska) President Steve Marshall told the Resource Development Council in November that the company is revisiting some of the North Slope’s more challenging oil accumulations in an effort to produce known resources.
One of those, he said, is Lisburne, where two recent wells provide hope that the giant carbonate oil field on the eastern edge of the Prudhoe Bay field can be economically produced.
Lisburne started to get another look in 2002, when BP took over operatorship at Prudhoe and associated fields.
Anne Shaw, BP Exploration (Alaska)’s Greater Point McIntyre Area resource manager, told Petroleum News Dec. 5 that in 2002, BP’s Point McIntyre subsurface team and the company’s coiled tubing drilling team took another look at Lisburne, which is managed as part of Greater Point McIntyre.
There had been a lot of work done on Lisburne over the years, trying “to figure out, how do you unlock the potential” of the 2 billion barrel field, Shaw said.
Production from Lisburne to date has only been about 136 million barrels, less than 7 percent of oil in place, she said, compared to Prudhoe Bay, where expected recovery is 50-55 percent of barrels in place. Lisburne a different type of field The problem the companies have had with Lisburne is that it is a different type of reservoir than other North Slope fields. The major North Slope oil reservoirs are in sandstone formations. Lisburne is not.
“It’s a huge carbonate field, and the carbonate nature of it is what makes it very different from the rest of the fields on the North Slope, which are sandstone,” Shaw said.
The companies started out with high hopes for Lisburne. The Lisburne Production Center was built to handle some 100,000 barrels of oil a day and more than 80 wells were drilled at Lisburne in the 1970s and 1980s.
The limestone reservoir presented drilling challenges: it is hard and difficult for drillers to penetrate. When they did penetrate, they sometimes found good porosity in the reservoir — pore spaces which could contain oil — and sometimes no porosity at all.
Oil rate is also a problem with Lisburne wells, Shaw said: “They come on strong and fall off quickly.
“And then they also have high gas rates.”
And limited North Slope gas handling facilities mean “a lot of the wells just weren’t economic to produce.”
Development drilling at the field ended in 1989 because of the disappointing results.
Production continued, but dropped from a peak of around 40,000 bpd to 10,000 bpd. No absolute analogues Shaw said that Lisburne has some similarities to limestone reservoirs elsewhere in the world, but there are differences.
Lisburne has dual porosity, she said, “both matrix and fracture porosity.”
The reservoir is also complex, with what are called ‘thief zones’ — “high permeability streaks at the top of the reservoir” — through which gas from the field’s northern gas cap quickly moves to wells drilled elsewhere in the field.
During the earlier development drilling, wells would be drilled in the southern portion of the field, “and within a week” gas would be moving into the well bores from the gas cap to the north.
There are analogues to Lisburne around the world, Shaw said, but “specifically, when you get into this, there’s all sorts of little complexities.” Subsurface and drilling teams both crucial to Lisburne success Both the Greater Point McIntyre area subsurface team — geophysicists, geologists, reservoir and petroleum engineers — and BP’s coiled tubing drilling team worked on Lisburne.
The subsurface team did a lot of work “developing an improved understanding of the reservoir itself,” which increased the “odds of hitting both what we call matrix porosity and then also fractures in the Lisburne,” Shaw said. The team has a lot of experience, she said. Some have worked Lisburne and the North Slope for 20 years, and “they’ve really been able to overcome the odds.
“A year and a half ago people would have just said ‘you’re nuts to do this,’” Shaw said.
Both new technology and a better understanding of the reservoir have contributed to the current successes.
Without “major breakthroughs” in drilling technology, the new wells could not have been drilled.
Key are coiled tubing drilling in limestone; using “non-damaging fluids, solids-free fluids” so drilling doesn’t damage the reservoir; and drilling “near balance, so we’re not over balanced — we’re not pushing stuff into the formation. So what you end up with is a pristine well when you’re finished.”
The goal in drilling at Lisburne, Shaw said, is preserving the natural fractures. Past drilling plugged the fractures, and fracture stimulating didn’t work very well because the reservoir rock is very hard and fracture stimulating works just near the well bore. With the “matrix porosity, which is your storage volume … you’re trying to preserve your natural fractures … which are the connectors to your storage volume.” Merger and alignment allow more flexibility at Lisburne One reason Lisburne got another look was because, due to the BP-ARCO merger when ARCO’s Alaska properties were sold to Phillips Petroleum (now ConocoPhillips), ownership at major North Slope fields was aligned and BP became the sole operator at Prudhoe Bay, which includes Lisburne, one of the Prudhoe Bay participating areas.
“This was a big thing,” Shaw said. “Because of the alignment and the merger, we were now able to actually go over and use Prudhoe Bay wells” to drill to the Lisburne reservoir.
Because there were so many wells already drilled into the reservoir, new penetrations can be drilled with coiled tubing drilling as sidetracks from older wells. Coiled tubing drilling is cheaper, and vendors are developing specific bits that can drill through the Lisburne limestone faster. “The faster you can drill through it, the less time you have to spend on it, and that brings the cost down.”
K-317B well a success The first of the two new wells, the K-317B, completed in January, was drilled from an old Prudhoe Bay well on K pad and had a measured depth of 11,935 feet and a true vertical depth of 8,830 feet.
By drilling the first well from K pad, on the western side of Lisburne, BP was able to avoid some of the high permeability zones gas could move through.
K-317B was drilled with a horizontal section through the reservoir, cutting across the fractures and intersecting the matrix.
The well was completed in January and is still producing 800 to 1,000 barrels per day, Shaw said.
In addition to continued oil production, the well’s gas production hasn’t increased. Second well more challenging After the success at K-317B, the team tried something more challenging, and tackled a sidetrack within the Lisburne participating area. The L1-15A was drilled closer to the gas cap and had some 1,500 feet of horizontal section. The well began producing in mid-October, and production has continued to increase.
That is because of the dual porosity at Lisburne, Shaw said: “As the well cleans up, and as the matrix porosity starts to feed the fractures, you get a stabilized flow” with “increasing production,” which was at 1,500 barrels per day in early December, with slightly declining amounts of gas.
“It’s exactly the type of well we want to emulate throughout the whole field,” Shaw said.
BP is learning as it goes at Lisburne, Shaw said, and successful drilling has “been a daunting challenge.
“And this team is just continuing to learn and continuing to innovate.” With each well there is information, which can be applied to the next well. “So success will breed success here,” Shaw said.
It’s also a learning process for drillers on the Nordic 2 coiled tubing drilling rig, she said.
“These are all new things for them. They’d never drilled in limestone with coil. They’d never drilled near-balanced on the slope before.” A third well scheduled for January A third well, the L2-14, will be drilled early next year, also a coiled tubing sidetrack. And at least two more wells are on tap for next year.
And what have the new wells done for the field so far?
There are 89 reservoir penetrations, about 10 wells on production full time because of the high gas content from the field. There are perhaps another 40 wells that are swing wells, Shaw said, which can be produced for maybe a week or two and then have to be shut in for four or five months.
Total production is about 10,000 bpd. And the two new wells account for 21 percent of that production.
Additional wells will also be coiled tubing sidetracks, and will also be designed to run horizontally through the reservoir. “We’re trying to do that because we’re trying to hit all the fractures and open up the matrix porosity,” Shaw said. One of the things that the team will learn as more well are drilled is how long the horizontal sections need to be: “Do we need 2,000 feet? Or do we need 800 feet?
“It’s part of the learning process,” Shaw said.
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