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A light in the tunnel New drilling, completion technology help BP tap shallow, viscous Schrader Bluff crude oil at Milne Point Kristen Nelson PNA Editor-in-Chief
After seven years of working with different technologies, BP Exploration (Alaska) Inc. is beginning to see promising production results from Schrader Bluff wells and may be on the way to significant development of the 2 billion barrels in place of shallow, viscous oil that lies above the Kuparuk formation at Milne Point.
Conoco, which originally operated the field, had wells averaging 300 barrels of oil per day — and BP initially had the same results. But with new drilling and completion technologies, BP is now drilling wells with average production of 1,000 BOPD.
“Where I think we are now, with viscous oil development on the slope, is it feels like we’ve turned on the light in the tunnel. And previously we were kind of wandering around in the dark, bashing our heads on things. …”, David Jenkins, BP’s viscous oil team leader, told PNA in a February interview.
And while the light is on, and it is possible to see a ways down the development tunnel, “we can’t actually see the end. We’ve a vast, vast resource out there and it’s going to take many, many years and continual progression of technology, continual reduction of costs, to come anywhere close to developing the full scope of what we have available to us.”
Schrader Bluff at Milne Point is an extension of the West Sak accumulation at Kuparuk. The viscous accumulations lie some 4,000 feet below the surface, close to the permafrost which extends down 2,000 feet. The combined West Sak-Schrader Bluff viscous oil accumulation is estimated at something like 15 billion barrels in place, Jenkins said.
“And that’s a significant prize.” Conoco began Schrader work The first decade of work at Schrader, Jenkins said, was “about developing the technology that might make this an economic development.”
Conoco invested $130 million in four gravel pads, 17 producing wells and five injection wells in the early 1990s. The wells averaged 300 BOPD, a total of about 3,500 BOPD. Conoco looked at full development at Schrader and estimated the cost at around a billion dollars: “basically it was just totally uneconomic,” he said.
When BP bought Conoco’s interest in Milne Point in 1994, it was for the field’s Kuparuk reserves. Not much value was placed on the Schrader resource. But the Schrader Bluff accumulation at Milne Point is estimated at “something like 2 billion barrels worth of oil in place. It’s kind of hard to sit on a prize that big, without actually trying to do something with it,” Jenkins said.
Economic development of Schrader Bluff is made difficult by several things, among them the viscous nature of the oil. The American Petroleum Institute gravity of Schrader Bluff oil varies from 14 to almost 22 degrees compared to an API gravity of 28 degrees at Prudhoe and the oil flows “at an order of magnitude slower rate than a normal oil would in this kind of sand,” Jenkins said, anywhere from “30 to 200 times slower than a comparable well at Prudhoe Bay under normal terms.”
Because the formation is at very shallow depths, “the rock is a lot weaker,” he said. “It hasn’t really been compressed hard enough and long enough to turn into real stone. …and if you get a piece of the core, you can actually push your finger through the core. That’s how weak it is.” Because the formation is unconsolidated, as the oil is produced into the well bore, “it brings all the sand with it and clogs up the well bore and clogs up the machinery.”
BP drilled nine Schrader Bluff wells in the mid-1990s, and wasn’t able to improve production rates over what Conoco had achieved. Inexpensive conventional wells In 1997-98, BP began a program of inexpensive conventional wells in an attempt to drive the cost down enough so that Schrader Bluff could be produced on a big scale. The plan included five new gravel pads, expansion of several existing pads, more than 75 miles of new pipeline and 10 miles of new road.
Jenkins said an initial 16-well program was planned, focusing on some technologies established in the early years, including hydraulic fracturing of the formation for sand control.
Initially, sand screens were put into the wells to keep the sand out, but eventually the screens can get blocked, reducing what little productivity you had to begin with, Jenkins said.
The wells also require artificial lift, and the lift systems had electric submersible pumps in the wells — where they were subject to damage from the sand.
The low rate of production, need for sand controls and artificial lift all added to the cost of the wells compared to a well at Prudhoe Bay.
“They’re more expensive, but at the same time they’re lower rate,” Jenkins said.
For sand control, the 1997-98 program tried fracturing the formation and pumping it full of proppants, “basically specifically sized sand… meant to hold open the fracture,” provide a way for the oil to reach the well bore and at the same time keep the sand from coming out of the well. This proppant was resin-coated — the grains were going to glue themselves together, preventing the sand from getting into the well.
But there were a number of technical problems, Jenkins said, problems compounded by the cold reservoir. The resins didn’t glue the proppant together very well, and a lot of the proppant sand was produced back into the well bore, destroying equipment. Beginning of horizontal drilling Throughout the early program, however, BP had been trying some horizontal well technology at Schrader Bluff. The last well in the 1997-98 program was a horizontal producer which was drilled into both of the Schrader Bluff producing sands, about 1,000 feet in each.
The team working on that well took a risk, Jenkins said.
“They completed the well without positive sand control.” They used tubing which had no sand control at all — just a pipe with one-inch holes along it.
“And low and behold, as we put that well on production, all our beautiful frac for sand control wells were busily burping proppant and sand and killing pumps. And this well, which had one-inch gapping holes all along it, wasn’t producing really much of any sand at all,” Jenkins said.
It wasn’t just a lucky guess. The technology of rock mechanics, “determining how weak and how strong rocks are,” had been evolving. So had understanding of horizontal wells, and that growing knowledge indicated that even in weak sands, wells are stronger and hold up better than previously thought.
Not only did the well perform well in sand control, it actually doubled the production rate of the other wells. “Almost no sand and twice the production,” Jenkins said — without sand control “there’s no barrier to flow.” New development vision In 1999, BP drilled four long horizontal wells at Schrader Bluff without sand control — they ran slotted liners into the producing zones.
There was another change.
Past wells, “in order to become economic, had always tried to produce as many zones as possible and just kind of add them all up. The problem with that was that with these big pumps in the hole, we could never actually use the logging technology to go down and see which ones were producing and which ones weren’t producing,” Jenkins said.
The 1999 long horizontal wells were drilled into single sand horizons to get specific information. And these wells had longer horizontal sections — 2,500 to 3,000 feet within a single sand.
These wells had comparable results to the first horizontal well with no sand control — about 600 BOPD, double the rate of earlier wells. The 1999 wells, Jenkins said, became the “proof of concept” for horizontal wells without positive sand control. Four-pronged strategy With proof of concept that long horizontal wells could be drilled at Schrader Bluff without sand control, BP’s viscous oil team began working on a four-pronged strategy to make development of the viscous oil economic.
First, the team decided it would need to triple well production from the original 300 BOPD to something like 1,000 BOPD.
And life-cycle costs — the long-term operating costs of the wells — would have to be cut in half.
Drilling costs would have to be reduced by 30 percent over 1998 figures.
And infrastructure costs — the cost of building roads, pipelines and surface facilities — would have to be reduced.
“By the end of ‘99,” Jenkins said, “we had proof of concept on rates. We had these horizontal wells, which were double our previous productivity.” From those 600 BOPD single-sand horizontal wells, he said, you could extrapolate that for multi-lateral wells — two wells drilled from the same well bore — you could double production again and get it into the range of 1,200 BOPD.
Life-cycle cost reduction involved two things: a decision on completion with or without sand control; and artificial lift — the kind of pumps used to get the oil to the surface. BP began looking for information on “long-term survivability of long horizontal wells in weak sands with slotted liner or pre-perforated type of completions” and no positive sand control and also gathered information from the wells drilled in 1999 and similar wells drilled in 2000.
BP also looked at technical papers, current thinking in the industry and the latest rock mechanics testing, but Jenkins said there are “very few analogues in the viscous oil arena where people are trying to water flood. …
“The issue there,” Jenkins said, “is that there’s some general thinking in the industry — has been for years — that if you actually water flood this stuff, which is where you push water down one injector to help push oil towards producers, that as that water breaks through into the producer it weakens the sands.” BP did a water flood test at Schrader Bluff last year with a long horizontal well that had just been drilled and a nearby injection well to see if sand production would change when the water broke through. The test well has remained on production, Jenkins said, with very little change in the sand that’s been produced. New pumping method The other piece of the life-cycle cost issue is the electric submersible pumps. “Every time we change them out, they cost about a quarter million dollars to do that. And on average in 1997-1998, we were replacing about half of the equipment in the wells every year,” Jenkins said.
BP’s management allowed the team to go clear back to basics on the pump issue and ask: “If we were to do it all over again, what artificial lift would we choose?” They looked at everything on the market and settled on jet pumps.
The beauty of jet pumps, Jenkins said, “is there are no moving parts down hole.” The pump sits at the surface and pushes water down the annulus of the well and through a special nozzle which compresses the water and shoots it out into the well where it accelerates back to the surface, sucking the oil along with it. At the surface the fluids are run through a separator, the oil goes to the facility and the water is pumped back down the well to bring up more oil.
Replacing a broken nozzle costs perhaps $5,000, Jenkins said, and the rest of the equipment — pumps and separators — is on the surface. “The tradeoff is there’s more surface equipment involved, but it’s all there where you can work on it,” he said.
The system also reduces costs for well work. “With jet pumps in the hole, we can actually pull this nozzle out and then run with coiled tubing through the existing completion to go work on the well below.” Jenkins said BP has five to eight jet pumps on line now, testing different designs; the first system built for the field will be delivered this spring and will be operating in the third quarter. Reducing drilling costs Jenkins said the first Schrader Bluff coiled tubing well will be drilled in April. All drilling to date has been conventional, but recent wells were effectively non-conventional, with horizontal sections reaching 3,500 to 4,000 feet.
“And what’s amazing technologically from the drilling perspective is … you’re only drilling in maybe a 20-foot sand,” Jenkins said. “You’ve got to drill over a half a mile along a 20-foot corridor when the resolution of the seismic data, which tells us where all the formations are, is typically plus or minus 15 feet.”
Specialized logging while drilling tools can establish if you have drilled out of the formation — perhaps when crossing a small fault — but geologists have to determine whether the drillers need to go up or down to get back into the sand.
In 1999 and 2000, Jenkins said, “we placed over 90 percent of our long horizontal intervals within the 20-foot target zone.” With those levels of drilling accuracy, and multi-lateral wells — two sections totaling 6,000 feet — 1,200 BOPD Schrader wells now cost about $4 million, Jenkins said. And the question then is, how do you continue to drive down costs? Answering that question, BP is doing something new for drilling at Schrader Bluff — see the accompanying article on the light automated drilling system. Reducing infrastructure costs The move to long horizontal wells has another benefit in addition to improving production, Jenkins said: It reduces the amount of new infrastructure required to develop Schrader Bluff. Some of the wells drilled in 2000 were not just long horizontal wells, but were classified as extended reach drilling wells, wells that reach out a long distance horizontally from the well pad, increasing the area around a gravel pad that can be developed without having to put in another pad.
Initially, Jenkins said, BP thought it was going to need five new gravel pads, 10 miles of new road and 75 miles of new pipeline to develop Schrader Bluff. But now, with ERD wells, more than 90 percent of development can be done with one gravel pad and some expansion of existing pads.
Instead of 75 miles of new pipeline, the project will require seven and a half miles; and one mile of new road instead of 10 miles. Oil quality is good There are also, Jenkins said, strategic fit issues with Schrader Bluff. One of these involves refineries. The general thinking in the industry has been that viscous oil is harder on the refineries.
“That’s actually not true in our case,” he said, because Schrader Bluff crude came from the same source as Prudhoe Bay. “Because it’s buried at a shallower depth, it’s at a depth where bacteria basically ate away some of the lighter molecular components. So it’s basically a biodegraded Prudhoe Bay crude. What’s significant about that, is it actually has a lower metal and sulfur content. … than the Kuparuk crude” and is better quality than Kuparuk crude from a refinery perspective.
It’s also a benefit to the refineries in another way, Jenkins said.
West Coast refineries handling Alaska crude were basically designed for Prudhoe Bay crude — and the mix going down the pipeline is getting lighter because of fields like Alpine, which has a very, very light crude. “And so as we produce more and more of the viscous oil, we actually are bringing the crude right back to the place that those refiners like to see it anyway.”
The Schrader Bluff development is also a good strategic fit with the BP brand’s emphasis on environmental considerations because of the reduction in the overall development footprint and because of the lower metals and sulfur content, Jenkins said.
Link to gas sales
Schrader Bluff development also links to upcoming Prudhoe Bay gas sales and to BP’s stance in the green agenda, which is about reducing CO2 emissions. Prudhoe Bay gas has something like 10 percent CO2.
“And so the question is, when you begin your major gas sales, what do you do with it? And the beauty of that,” Jenkins said, “is that CO2 is one of the best enhanced oil recovery type gases to use for sweeping viscous oil,” swelling the oil and reducing its in-situ viscosity.
“And so you can have a dramatic improvement in the ultimate recovery by the use of CO2 as a miscible gas.” When CO2 is used in oil recovery, a lot of it gets tied up in deep formations, protecting the atmosphere while producing extra oil.
The enhanced oil recovery process for Schrader Bluff is being studied now, Jenkins said, and probably will begin with normal types of hydrocarbon miscible injectants and then follow with CO2. The process under evaluation now is miscible WAG — water alternating gas — from injectors, followed by CO2.
With the vast amounts of CO2 available, “what we’d like to do is have a large-scale development of viscous oil available to use it.” That, Jenkins said, ties back to BP’s strategic outlook on viscous oil: “We actually see ourselves developing the technology to move to a large-scale development of that resource. It kind of closes the circle for us.”
Current production
Viscous oil production from Schrader Bluff and West Sak combined is somewhere around 15,000 BOPD, Jenkins said, with Schrader Bluff production between 8,000 and 10,000 BOPD from 43 producers.
The upcoming pieces are the large-scale S pad development, 17 producers plus supporting injection wells. West Sak, he said, is going to be doing a similar sized development off existing gravel.
Between BP and Phillips, he said, we’re probably looking at drilling 75 to 200 wells, producers and injectors, over the next five years.
BP will drill a dozen Schrader Bluff wells this year.
In five years, Schrader Bluff production is expected to be in the 25,000 to 30,000 BOPD range, and West Sak will probably be in the 20,000-30,000 BOPD range, so a total of 50,000-60,000 BOPD combined in five years.
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