Fingers are crossed at BP as the company’s heavy oil project at S-Pad in the Milne Point unit on Alaska’s North Slope moves into its first test phase. The company is lowering a pump into a well designed to extract oil with the consistency of chocolate syrup from the Ugnu formation, 4,200 feet below the surface. The test well is located on an S-pad extension that was constructed for the project.
An initial test should take about three weeks, with a phase one testing project continuing into 2009 and involving the drilling of three more wells by the end of 2008, Eric West, BP’s heavy oil project manager, told a media tour of the Milne Point test facility Aug. 18.
If the phase one testing demonstrates the technical feasibility of heavy oil production, the project will move into a second phase of testing, to evaluate whether heavy oil production at Milne Point will prove economically viable, said Max Easley, Alaska Consolidated Team business unit leader.
20 billion barrelsAnd, with an estimated 20 billion barrels of heavy oil in place in the central North Slope, the stakes couldn’t be higher.
“If we only get 10 percent of it, that’s a lot of oil,” West said.
The oil in the Prudhoe Bay region has migrated into various reservoirs at different depths. But bacteria that become particularly active in the temperature conditions at depths of around 4,000 feet eat out the lighter hydrocarbons, West said. That results in a residue of heavy oil in relatively shallow reservoirs far above the conventional light oil reservoirs of the North Slope oil fields.
Methane waste from the bacterial action bubbles towards the surface and becomes trapped around the base of the permafrost as gas hydrate, West said.
About three years ago BP decided to embark on a project to try to develop the heavy oil while there is still significant production of light oil from the North Slope. The light oil is needed to thin the heavy oil so that the resultant fluid can flow down the trans-Alaska pipeline, West explained
“We need the light oil to blend it with, so it’s the perfect time in the North Slope’s life,” Easley said.
Were BP to stick to the conventional concept of waiting for depletion of the North Slope light oil before producing the heavy oil, the company would have to resort to an expensive technique such as hydrogen cracking to create a light enough fluid for export by pipeline, West said.
Which way?But which of the many possible ways of producing that residue of heavy oil is likely to work?
The most widely publicized methods consist of either the surface mining of oil sands or the application of heat to the underground reservoirs, West said. However, in Canada, the epicenter of heavy oil development, techniques for cold heavy oil extraction have also been developed, he said.
BP has a policy of not mining for heavy oil, West said. But the choice between hot and cold in-situ production depends on the nature of the oil reservoir and the characteristics of the oil, he said. On the North Slope much of the Kuparuk unit area heavy oil appears most suitable for hot extraction, while in the Prudhoe Bay and Milne Point units cold techniques seem more appropriated.
West also said that cold techniques create a smaller carbon footprint than hot techniques.
The particular technique that BP has chosen to try at Milne Point is called cold heavy oil production with sand, or CHOPS, a technique that has seen several commercial developments in Alberta.
In this technique, which depends on an unconsolidated sand reservoir, the production well has large perforations and no screen for keeping the sand out of the well. Sand is produced along with the oil and is subsequently separated from the oil at the surface by heating the oil/sand mixture in a tank.
“You’re actually producing a bit of the reservoir into the wellbore,” West said. “That is totally contrary to light oil reservoirs where you always want to keep the sand out.”
Downhole pumpA key part of the well technology is the downhole pump, known as a progressive cavity pump, consisting of a long augur-like rotor that spins at high speed inside an enveloping tube. The rotating augur screw will draw material up the well, while being less susceptible to wear than a piston-based pump design.
Because the sand in the well would tend to cause a downhole electric motor to overheat, the pump’s motor drive is placed at the surface and is connected to the pump rotor by means of a long rotating rod that extends through the well inner casing. A huge spool called a mobile gripper unit feeds the drive rod down into the well casing.
The pump should cause a pressure drawdown or drop of around 1,000 pounds per square inch or more at the bottom of the well.
“We’re going to put really significant drawdown against these open perfs,” West said. “And that’s going to induce the formation to produce into the well.”
Once a well goes into operation, initial sand production should be high, perhaps 40 percent of the total production volume, said Grant Encelewski, operations lead tech for the BP heavy oil team. Then, after a system of fissures and wormholes in the reservoir has opened up and somewhat stabilized, sand production will drop to 10 percent or less, with a corresponding increase in oil production.
But, although the project team has already recovered a small amount of oil from the test well in the course of preparing the well for pump installation, the key to success will be the pumping of sand up the well.
“We define success, not so much as oil, but as being able to bring sand to the surface in a sustainable manner,” West said. “… If we can do that we know we’re going to have a project, because the oil will come with it.”
Initial testing is using adapted conventional oilfield equipment to process the material drawn from the well. If that test proves successful the team will drill three more wells by end 2009 and install a long-term test kit consisting of processing equipment purpose built for handling heavy oil. Sand separated from the oil will be disposed through the Prudhoe Bay grind and inject facility.
The total cost of this phase one testing will be $68 million.
Phase two will involve an additional extension to S-pad, the drilling of four more wells and possibly the installation of additional well test facilities. Phase two is likely to cost about as much as phase one.
“We’re going to put over $100 million into this, before we even know if this is a business opportunity,” West said.
Several hurdlesPhase two could culminate in a development decision, but for a viable full-scale development the testing will need to cross several hurdles.
“This is a journey that is going to take some time,” West said.
Assuming that the initial well configuration works successfully, the team will try to improve flow rates — higher than normal cold heavy oil production rates will be needed to offset high Alaska well costs. The technique of choice for flow rate optimization is the use of multilateral horizontal wells but no one knows whether the sand production will work through horizontal well bores.
“No one has yet determined how you can pull sand along a horizontal well,” West said. “That’s our technology challenge.”
And one key factor will be the use of good reservoir imaging from seismic data to enable precise well placement.
“In Alberta they have a 40 percent (CHOPS) well failure rate,” West said.
Cost and valueThe project team will try to apply innovative technologies to reduce costs. And, finally, the team will need to ensure that the footprint of the required surface equipment is acceptable.
By crossing these various hurdles, BP expects to overcome the two major challenges of heavy oil production: high production costs resulting from the high oil viscosity and the relatively low value of the product. Because the heavy oil contains a smaller proportion of high value products such as gasoline than light oil, BP expects the North Slope heavy oil to sell at about $9 per barrel below the regular price for Alaska North Slope crude. But at current oil prices, the economics look good, West said.
And BP’s strategy for its North Slope production is to bolster overall fluid oil production by bringing heavy oil on line.
“Without the heavy oil the future of Alaska is very much one of diminishing light oil, but then gas coming on big,” West said. “But with heavy oil you … have a rejuvenation of the fluids business for Alaska, and it becomes as much a fluids future as a gas future.”
“This to me is the next big oil boom,” Encelewski said. “… This is a domestic project that’s under our noses. … That’s what gets me enthusiastic.”