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Jet pumps, horizontal sections, solve sand problem at BP’s Milne Point S pad drilling under way as facilities installation continues, first production expected this year, with peak of 16,000-18,000 barrels per day in 2003 Kristen Nelson PNA Editor-in-Chief
Getting viscous oil out of the ground is a balancing act between keeping sand from the shallow formation in the ground and pumping the cold thick oil out of the ground, BP Exploration (Alaska) Inc.’s David Jenkins told the Alaska Support Industry Alliance May 9.
The pump piece of the puzzle was solved with jet pumps, said Jenkins, BP’s viscous oil team leader at the Milne Point field. This technology, he said, has no moving parts down the hole — the pump is on the surface, unlike electric submersible pumps where the moving parts are down in the well where they can be and are damaged by sand.
A jet pump pumps water down the annulus of the well and back up through the tubing. At the bottom of the well there is a nozzle which “works similar to the Bernoulli principle … as it accelerates the power fluid, in this case the water that we’re cycling through it, it kind of brings the oil along with it.”
The working end of the jet pump, the nozzle, can be put in the hole with wire line equipment, reducing the cost of down hole replacements from $300,000 for an electric submersible pump which requires a rig for replacement to $5,000 for a nozzle.
The jet pump is probably less efficient than the submersible pump because water is pumped both down the hole and then back up again, “but from an operating perspective, far more forgiving in a sandy environment,” Jenkins said. And it allows the elimination of screens to keep sand out of the wells.
From 1999 to 2000, BP tested doing away with sand screens, tested multilateral wells and achieved a 1,200 barrel per day well. Reduced drilling costs BP also reduced drillings costs — the goal was a 30 percent reduction from 1998 rates — “in order to really be able to drill lots of wells and produce a significant well rate.”
In 1998 a Schrader Bluff well cost about $2.5 million and produced about 300 bpd, Jenkins said. By 1999, with long horizontal wells in a single sand, the cost had gone to $2.6 million for 600 bpd — or about $1.3 million for 300 barrels, half of the 1998 cost.
For long horizontal wells, targeting multiple zones, the wells came in at about $4 million per 1,200 bpd, or less than a million dollars per 300 bpd.
The long reach wells also drove a reduction in footprint.
With conventional wells, Jenkins said, you can reach about 7,500 feet out from a well pad. But with long horizontal wells, the reach is some 10,000 feet from a pad.
That meant that the Schrader Bluff development at Milne Point, which was thought to require five new pads, 75 miles of new pipeline and 10 miles of new road, could be done with one new pad, 7.5 miles of new pipeline and one mile of new road, plus some expansion of gravel on existing pads.
Both the footprint and the cost have been dramatically reduced, Jenkins said. S pad development BP is building that one new pad, S pad, Jenkins said. It will have 14 multilateral producers and production is expected to be 7,000 bpd after the pad comes on production later this year, with a 16,000-18,000 bpd rate in 2003.
Drilling is under way at the pad, along with facilities installation.
S pad will allow BP to commercialize roughly 55 million barrels of recoverable oil.
“Fifty-five million barrels is actually a pretty small piece of the overall prize,” Jenkins said.
Looking at the whole viscous accumulation, S pad at Milne Point, Polaris and Orion at Prudhoe Bay all have a good chance for success, he said, and Phillips Alaska is working on the West Sak project at Kuparuk. “They have a greater challenge because they’re a little further to the west, hence the oil quality’s a little bit worse,” he said.
BP will go back and redevelop the Tract 14 area at Milne Point, where Conoco started Schrader Bluff development, and the rest of the core corridor, bringing recoverable barrels into the several hundred million range. Enhanced oil recovery Some of the more challenging viscous may be producible, Jenkins said, “if we can actually figure out how to make some of the enhanced oil recovery techniques work, which is one of the things we’re working on now.” With enhanced oil recovery, “we actually have a chance of working our way into another say hundred million barrels in the core areas, but the big prize for us there is actually making enhanced oil recovery techniques work enough to get into some of the truly viscous oils,” he said.
“And that is really what starts to unlock a great part of this prize up into kind of a billion barrels plus. And at that point we don’t really know if that’s a billion barrels or 2 billion barrels. We’re still a ways away from that.” Production life cycle Where viscous production fits into the overall North Slope picture relates to lifting cost per barrel of oil over time — as production goes into decline.
Operation becomes more expensive when you get into steep production decline, Jenkins said, because you not only have a cost per barrel to produce the oil, but “a fixed amount of money to run everything that you have sitting in your oil field.”
Looking at the major North Slope fields — Prudhoe Bay, Kuparuk, Milne Point, Endicott — “a lot of where we are on the North Slope is we’re getting to the steep part of the hill,” Jenkins said, which is why there is so much talk about controlling costs.
On the steep part of the production curve, he said, “the only way we can actually reset this clock is by adding more reserves so that we’re not as far along this percent depleted reserves.”
From BP’s perspective, he said, there are reserves already banked, including about 1.4 billion equivalent barrels in natural gas, 1.3 billion barrels in satellites and in-fill well candidates and then other potential reserves, not proved up yet.
And then there is that potential 2 billion barrels of viscous oil, “so a big part of this point for us about keeping this clock reset — keeping ourselves in a place where we have … lifting costs — is dependent on viscous oil.” Viscous oil incentives Congress is looking at a tax incentive for viscous oil development, and Jenkins said if that tax incentive passes it “is one of the things that could actually unlock a greater swathe of reserves … on the North Slope” and would be significant because since the quality of the oil degrades as you move into shallower areas “so anything we do to take cost out of the system or to add incentive into the system expands that envelope.”
Each expansion of the envelope, he said, could add hundreds of millions of barrels, which means years of drilling and economic development on the North Slope. Pace, partnerships, technology Jenkins said BP is working on the appropriate pace for viscous development and on reducing drilling costs “because we’re going to have to drill a lot of wells to deliver this oil.”
BP is an owner at Kuparuk where operator Phillips is working on viscous development and both are major owners at Prudhoe. Jenkins said the companies will be trying to “maximize the manpower and brainpower that we have … and instead of working separate accumulations … look at the entire prize and really maximize some of those resources.”
In addition to different types of wells, BP is looking at different rig technologies and has just completed a 3-D vertical seismic profile program.
“We actually broke some new ground in the world testing this technology in new ways and we’re starting to get the data back now,” Jenkins said. The 3-D VSP can “help us image better underground so that we can drill these long distances across the faults with less kind of false starts and sidetracks.”
BP is also looking at different types of enhanced oil recovery, but Jenkins said a lot of the enhanced oil recovery technologies used in the Lower 48 and Canada “aren’t going to work here because it costs us about five times the cost it does in Canada to implement anything we do from a facilities perspective on the slope. And they’re actually struggling over there to make some of their stuff economic, but when you multiply that cost by five and bring it to the slope, it’s going to be really tough for us.”
But there are parts of technology with enhanced oil recovery and drilling that will work on the slope, he said, as well as reducing the overall cost of doing business on the slope.
“At the moment, out of the overall 15 billion barrels we see in place, we’ll probably be lucky to get a couple of billion of it — so there’s still a lot more there if we can kind of work through these three things over the next set of five to 10 years we’ll get it. But if we don’t get it soon enough, the overall, we’re going to hit that large steep part of that curve and we’ll never be able to generate sufficient rates to get us back down to where we need to be to operate sufficiently.”
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