A tunneling optionJoint venture proposes novel approach to develop North Slope heavy oil By ALAN BAILEY Petroleum News Bakken
With more than 30 billion barrels in place and little of it thus far developed, the heavy oil that lies at shallow depths above the producing light oil fields on Alaska’s North Slope presents a tantalizing target for future oil development. And in the latest concept for tackling this challenging resource, two companies are proposing the use of tunnels 300 to 500 feet beneath the North Slope tundra, to enable the underground drilling of large numbers of wells into heavy oil reservoirs, with minimal surface and environmental impact (see illustration, page 23.)
“I think we’ve got a unique chance … to see if we can turn Alaska production around and develop this world-class asset responsibly and efficiently. We know that this is possible,” Chris West, CEO of Alaska Petroleum Technologies, one of the companies involved, told a meeting of the Society of Petroleum Engineers in Anchorage on Jan. 8.
West said that for several years BP had been researching this approach to developing Alaska heavy oil but that the company has now decided to focus on the Alaska liquefied natural gas project, rather than pursuing the underground drilling concept further. Alaska Petroleum Technologies has picked up the research and is working with engineering company Golder Associates to establish a test facility near Fairbanks, to try out the required technology.
This approach to developing heavy oil would use technologies, each of which has a proven track record but none of which has been used together in this way, West explained.
But there is a precedent for drilling for oil from tunnels.
“Tunnels are currently being used for oil production in Wyoming … where they tunnel underneath the fields and drill up to use gravity drainage,” West said.
Difficult to flow Heavy oil, with a viscosity ranging from that of olive oil to material that is almost solid, does not flow easily and is, therefore, difficult to entice into oil production wells from underground rock reservoirs. Under the North Slope, some of the less viscous variety of heavy oil, referred to in Alaska as “viscous oil,” has been produced using horizontal wells in the Schrader Bluff formation above the Prudhoe Bay and Kuparuk River fields. However, heavier oil in the Ugnu formation, above the Schrader Bluff, has thus far defied economic development.
In 2011 BP implemented a test facility in the Milne Point field to try extracting heavy oil from the Ugnu using a technique called cold heavy oil production with sand, or CHOPS. But although the BP tests achieved heavy oil production rates of more than 650 barrels per day from two horizontal wells, the cost and difficulty of operating the wells eventually caused BP to shelve the project, West said. West also commented that the CHOPS technique only recovers about 6 percent of the oil in place, with the use of the technique damaging the reservoir to the point that there is no known way of recovering the remainder of the oil.
By comparison, California, a state that started out with 75 billion barrels of heavy oil in place, has produced 25 billion barrels of that oil to date, West commented. Three approaches Essentially, there are three approaches to developing heavy oil: Access the oil by drilling a high density of wells; reduce the viscosity of the oil by heating it or mixing it with solvents; or use a chemical process to alter the multiphase flow of the produced fluids, West said. California has used the high-well-density approach, an approach that can result in an oil recovery rate of 33 percent or more, he said.
Heavy oil development in Alberta, Canada, has predominantly used steam to reduce the oil viscosity, through a technique referred to as steam assisted gravity drainage, or SAGD. But SAGD requires specific geology and, in Alberta, uses paired wells with 20-acre spacings, West said.
With a key challenge on the North Slope being the need to protect the surface tundra and the Arctic wildlife, the fact that drilling of many closely spaced wells is a key to high heavy oil recovery rates has been a major obstacle to North Slope heavy oil development, West said. Hence this new proposal to drill from tunnels, an arrangement that would enable many wells to be drilled with almost no surface impact. Tunneling machines Devices referred to as tunnel boring machines, or TBMs, devices that have been used successfully for applications as constructing tunnels for the London underground railway, would excavate tunnels under the North Slope, using portals in existing quarries. A TBM has a rotating head with disc cutters that carve their way through the subsurface. The tunnels would be positioned in stable ground inside the permafrost and would be routed to avoid existing wells.
A large access tunnel, capable of supporting two-way truck traffic, for example, would connect with smaller drilling tunnels. The favored design consists of pairs of drilling tunnels, with one tunnel above the other: The upper tunnel would accommodate special purpose drilling rigs, while the lower tunnel would contain the blowout preventers for the wells, with each well having surface casing connecting the wellhead in the upper tunnel to the blowout preventer below.
And, with the wells being drilled underground rather than on the surface, wells could be drilled into heavy-oil reservoirs with spacings as tight as one to four acres, thus enabling the optimization of heavy oil production using a variety of possible extraction techniques. A production line approach In concept, the drilling operations would operate rather like a factory production line, using robotics as much as possible to automate the procedures. A series of specialized rigs of modular design would pass along rails in the upper tunnel. The first rig would emplace the well conductor pipe. A second rig would drill about 100 feet of surface casing and then advance the hole to the top of the oil reservoir. Finally, a coiled tubing rig would steer a well horizontally through the reservoir, placing a slotted liner into the well bore for oil production. A coiled tubing rig uses long lengths of small-diameter, flexible steel tubing, rather than conventional drilling pipe.
Drill pipe for the conventional components of the drilling would arrive in a magazine moving on a monorail mounted on the tunnel roof.
Initial production would use a type of downhole pump called a progressive cavity pump, with other recovery processes potentially coming into play as the reservoir pressure drops. The near-vertical orientation of the section of a well down to the reservoir would minimize wear on the rod from the wellhead for driving the downhole pump - rod wear turned out to be a significant problem in the deviated wells that BP used for its CHOPS test at Milne Point, West said.
And, while the program would involve the expense of building the tunnels, the wells themselves would be relatively quick and cheap to drill, involving the repetitive use of standardized and specialized rigs. Incremental development Field development would involve concurrent tunnel construction, drilling and oil production, with different sections of the reservoir coming on line at different times, as the development proceeds. It would likely take 10 years to complete all of the necessary wells, with production starting quite early during the development and lasting 35 years, West said. And with a possible peak production rate of 175,000 barrels per day, a massive return on investment is possible, he said.
In addition to the benefits of maximum heavy oil recovery, minimal surface imprint and low drilling costs, the underground worksites would remain at a constant, moderate temperature year round, unlike the frigid and sometimes stormy surface conditions above.
“It eliminates Arctic conditions … it’s 20 F year-around, which means no Arctic welding, no Arctic steel,” West said. “Everything is going to be Lower 48 equipment, bought off the shelf.”
There are two main drawbacks: the cost of the tunneling and the uncertainties associated with use of a radically new development technique on the Slope.
The tunneling would not, in fact, be as expensive as might be expected, with a cost perhaps amounting to 15 percent of the total program cost, West said. The viability of the tunneling is highly sensitive to the resource density of the oil field, in other words the volume of oil per unit area of the field - from that respect the Ugnu and the Schrader Bluff reservoirs appear promising, with resource densities similar to those of the California heavy oil fields, West said. Test facility To address the operational and regulatory uncertainty associated with the project, Alaska Petroleum Technologies and Golder want to build a test facility in the permafrost near Fox, in the Alaska Interior near Fairbanks. The test facility, which could later become a training facility for personnel involved in underground drilling operations, would be built on to an existing underground test facility operated by the U.S. Army Corps of Engineers Cold Regions Research Engineering Laboratory. An access tunnel would lead to underground drilling bays capable of accommodating 10 test wells. Test drilling using the same type of robotics-supported technology as is envisaged for the North Slope, will enable the technology to be evaluated and any regulatory issues identified.
The two companies anticipate the test facility costing around $50 million.
“We’re looking for half of that from the state and the rest from private industry,” West said. The idea is to set the test program up as a joint industry project, with participants having access to the results of the testing, he said.
And West thinks that the underground drilling technique has a high likelihood of success on the North Slope.
“It will maximize (oil) recovery and (production) rates beyond anything achievable from the surface, with a step change in drilling costs,” he said.
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