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So far, so good BP: Heavy oil flows from cold Ugnu formation during initial test at Milne Alan Bailey Petroleum News
BP Exploration (Alaska) Inc. achieved success in an initial test for production of heavy oil from the Ugnu formation at Milne Point S-Pad on Alaska’s North Slope, according to a company spokesman.
The test well succeeded in bringing sand and oil to the surface with a peak rate of about 120 barrels per day. By the end of the test Sept. 15, about 700 barrels of the oil with a consistency similar to chocolate syrup had been mixed with conventional crude produced at Milne Point and shipped down the trans-Alaska oil pipeline, BP’s Steve Rinehart told Petroleum News Sept. 30.
“The well brought oil and sand to the surface,” Rinehart said. “It did it reliably, sustainably.”
The oil has API gravity of about 10, he said. By comparison, conventional oil from the central North Slope typically has an API in the 20s, though light crude from the Alpine field has an API of 40.
“It was a welcome discovery that the reservoir itself appears very robust,” Rinehart said. That suggests that the Ugnu reservoir could sustain higher production rates, he said.
Downhole pump The initial test was intended to determine whether a procedure called cold heavy oil production with sand, or CHOPS, could produce heavy oil at Milne Point. CHOPS involves using a downhole pump with an augur-like rotor to suck a mixture of sand and oil up the well, without applying any heat to the reservoir formation — the Ugnu sands that form the heavy oil reservoir lie 4,200 feet below the surface and are relatively unconsolidated.
Once at the surface, the sand is separated from the oil by heating the mixture of sand and oil in a tank.
A novel feature of the pumping arrangement is that the electric drive motor is at the surface, connected to the downhole pump rotor by a long rotating rod that is passed down the well from a huge spool called a mobile gripper unit. Placing the drive motor in the well would cause the motor to overheat.
“The pump proved effective at pulling a lot of sand out of the formation,” Rinehart said.
In ramping up to the peak production rate, oil content in the oil/sand mixture flowing from the well varied from about 50 percent to 80 percent. Those production characteristics, together with the facility with which the pump drew sand from the formation, suggest that “wormholes” had formed in the sand reservoir, as BP had hoped, Rinehart said. And the sand settled out of the oil fairly easily in the production facilities at the surface, he said.
Next stage Having completed the hurdle of this initial test — proof that sand with oil can be induced to flow continuously to the surface — BP plans to proceed to the next stage of its Milne Point heavy oil project.
“This was a success and we are going forward with the multi-well, multi-year program,” Rinehart said.
For that test program, BP will build a permanent test facility by installing custom-built, truckable heavy oil production modules on the Milne Point pad during the coming winter; the initial test used standard oilfield equipment.
The planned multi-well tests will involve three new wells. Two of them wells will be CHOPS wells of the type used for the initial test, while the third well will be a horizontal well with a sand screen to prevent sand production. The purpose of the horizontal well will be to test heavy oil production using a technique that has already proved successful for producing viscous oil on the North Slope — viscous oil is lighter than heavy oil but not as light as conventional crude. BP wants to know how that viscous oil horizontal well production technique compares with the CHOPS technique when it comes to producing heavy oil.
“The goal here is to test a number of scenarios and a variety of equipment, so we can see what works best under what circumstances,” Rinehart said. The testing may take three to five years to complete, he said.
During the next phase of testing, BP also plans to re-complete the first CHOPS well, to test production from another reservoir zone, he said.
Economic viability In addition to a technically feasible production method, the multi-year route to commercial heavy oil production will require proof of economic viability. Economic success will depend on overcoming the major challenges of maximizing heavy oil flow rates, while reducing production costs. For example, BP is considering using multilateral horizontal wells to improve flow rates, but no one yet knows whether the type of downhole pump used for CHOPS production will actually work in a horizontal well.
Further, heavy oil is will not command as high a price per barrel as light oil even though today’s high oil prices provide a strong incentive for heavy oil production.
Successful heavy oil production at Milne Point could open the way to large-scale production of some of the estimated 20 billion barrels of heavy oil in place under the central North Slope. And BP is anxious try to move heavy oil into production while there is ample production of conventional, lighter oil from the North Slope. This will allow the heavy oil to be mixed with the light oil for transportation via the pipeline.
“There’s a big prize if we can find a way,” Rinehart said. “It’s an important part of our long-term strategy. … Heavy oil production enables other things to happen at Prudhoe Bay for a longer period of time.”
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