|
BP has conceptual breakthrough on North Slope viscous crude oil
Kristen Nelson Petroleum News editor-in-chief
When a single horizontal well was drilled to viscous oil on Alaska’s North Slope in 1999, producers had taken what proved to be a significant step toward economic development of the 15 billion barrel resource.
In the last year, new drilling and completion technology tripled productivity from the shallow viscous accumulations, which are both thicker and colder than the slope’s conventional oil, and harder to get out of the ground (see sidebar on viscous and heavy oil).
Viscous production across the slope is now some 30,000 barrels per day, and with some 22,000 bpd from Milne Point, viscous accounts for 40 percent of production at the BP Exploration (Alaska) field, Ed LaFehr, Milne Point asset manager, told the Alaska Support Industry Alliance April 8.
Current success follows years of effort to find the right technology to produce viscous oil, but it’s only the beginning.
LaFehr said he believes that in the struggle to commercialize viscous oil, the North Slope producers have established a base camp at the 7,000-foot level of the mountain, and are starting to see what lies ahead.
But, he cautioned, it’s still a long way to the top of the mountain — significant commercial development. Viscous a third of BP’s Alaska resource Viscous oil is critical to both Alaska and to BP, LaFehr said. It accounts for a third of BP’s Alaska resource — conventional oil and natural gas are each about a third — and will bridge the gap to gas production, he said.
While BP has “essentially shut down exploration,” it is “still spending risk capital — but we’ve shifted it from exploration over into the viscous arena and other areas… but we’re spending $400 million plus or minus inside the fields on things that are challenging, that require enormous innovation and a lot of scientific and engineering envelope-pushing off that.”
The Alaska business unit has the largest resource base of the BP business units, he said, but “most of the BP Alaska resource base is … economically challenged or … gas,” and Alaska is also “the highest-cost region” in BP, some $5 a barrel above the BP upstream average.
That makes the competition for investment dollars tough, he said.
On the plus side, viscous has “relatively short cycle times to production” and is “really green” because there is minimal new infrastructure required: “A lot of this extended reach drilling has been a phenomenal breakthrough for us to come off of existing gravel. You can’t do that in very many parts of the world,” he said.
BP’s production from Alaska is still a significant portion of the company’s total production, at 330,000 bpd some 8-9 percent of the almost 4 million bpd the company produces, but it’s less than half of what it was at the peak in the late 1980s, and the goal, he said, is to keep that production level, and “to reinvest in the existing resource base to hold production flat” until gas can be produced.
But LaFehr said he believes that strategy is only possible “if viscous oil happens and if it happens in a relatively material way,” not just in bits and pieces. Much has been accomplished Industry has known about the viscous resource for a long time, LaFehr said, and the North Slope producers collectively spent more than half a billion dollars in the 1980s and 1990s, trying to produce viscous, “pushing the envelope” with such techniques as fracturing for sand control and drilling smaller wells.
But “none of that worked: it was all uneconomic,” he said.
The horizontal well drilled in 1999 showed promise, and BP tackled things needed to make viscous economic: tripling well productivity to sustained rates of 1,000 barrels per day and reducing life-cycle costs by finding a way to lift the oil other than with electric submersible pumps.
“We also had to radically reduce our costs of drilling per unit of production,” LaFehr said, and leverage infrastructure costs, “coming off of existing gravel, minimizing pads and new pipelines.”
Since 2000, BP has spent more than $300 million on viscous, “largely developing S pad at Milne Point,” and in 2004 will spend more than $100 million as its share of more than 30 wells, some 13 of those at Milne Point, 15 or so at Prudhoe Bay and others at Kuparuk. Plan size from five pads to one The original plan for Milne Point viscous development called for five new drilling pads, 75 miles of new pipeline and 10 miles of new road.
What BP did, however, was to build one new pad which will “access nearly the same reserve pool” with extended reach drilling. With wells reaching out as much as 12,500 feet, to an accumulation at four or five thousand feet vertical depth, the wells are “just laid out on their side,” LaFehr said, “pushing the shallow extended reach drilling envelope for BP.”
BP is using jet pumps for lift and drilling multilateral wells from a small pad. Geologic models lead “to predictability in our geo-steering” and have resulted in wells staying in the productive sands 90 to 93 percent of the time.
And when it comes to drilling, “what Doyon 14 has done, what 141 did before that, just blew the doors down.
“We’ve seen the best drilling performance in all of BP sitting right out there on the tundra.”
In addition, he said, “the safety performance has been outstanding, the cost delivery has been 20 percent below what we authorized” and on drilling measures like days to 10,000 feet, “we’re beating those by about 20 percent.”
And “trouble time on drilling has been very, very low — half the slope average roughly,” he said.
“So a lot of technology all the way from subsurface to facilities has been driving the breakthrough in performance.”
Viscous oil production from S pad is a success, LaFehr said: “we’ve seen our first commercial project at S pad.”
What BP would do differently in the future, he said, was management of facilities construction.
Because so many surface facilities have been built on the slope, there wasn’t enough front-end attention or project management for the facilities side of S pad, LaFehr said, and it was too schedule driven. “We pushed ourselves into a pretty tough … schedule-driven approach, and we met the schedule, but we paid a premium on the facilities’ side.” Where next With development success at S pad, “if we start seeing signs that the next evolution of technology works, and the economics are there … there are hundreds of millions of dollars over the next decade that we would spend …
“It’s a phenomenally large project,” LaFehr said.
With success have come new challenges: long-rate delivery; issues around how water flood in the field is run; understanding the reservoir; and how sand is managed through the facilities.
Sand management is part of issues around “cost of operations and operability (that) have started to creep in,” LaFehr said, with something like 35 barrels a day of sand now being trucked off of S pad (viscous oil reservoirs aren’t well consolidated, so sand, bits of the reservoir, is produced along with the oil). We knew there would be sand, he said, “it’s a bit more challenging than we had thought.”
Then there are new types of wells.
In addition to multilateral wells, LaFehr said ConocoPhillips in Venezuela has drilled wells using what he called “the fish-bone concept,” where many drain holes are drilled off of a lateral line, exposing “huge volumes of reservoir, so your … productivities are greater” in viscous oils, which really don’t want to flow.
“There’s concept thinking on where we go next with the drilling, and then cost transformation and project management has to be improved.”
And, he said, “it’s pretty clear that the access costs have to continue to come down, everything from engineering to procurement to construction to … fabricating… We need to continue to drive the cost of business in the right direction to make a marginal project like this … happen, and so the pie gets bigger.” How big could this pie be? Once you get into enhanced oil recovery, LaFehr said, “you start getting into the big numbers.”
While the viscous resource is 15 billion barrels, for various reasons probably only 10 percent can be extracted, but “that’s one and a half billion barrels — and we only have maybe 100 million, 100 to 200 million under development.”
Looking at this as a mountain, “it gives you a sense of where we are — we’re just above the foothills.”
| 