Posted on 03/21/2011 8:56:11 AM PDT by thackney
It has been nearly a year since BP completed construction of its $100 million heavy oil test facility on Alaska’s North Slope, but the company has finally completed commissioning of the facility and is about to start operations at the plant, Eric West, manager of BP’s Alaska renewal team, told a group of state legislators at a “lunch and learn” session in Juneau on March 10.
“It’s essentially ready to go,” West said.
The facility, on S-pad, the most southerly well pad in the BP-operated Milne Point field, will try extracting heavy oil from the relatively shallow Ugnu formation using a technique called cold heavy oil production with sand, or CHOPS. In this system, a device called a progressive cavity pump, a kind of Archimedes screw that spins at high speed at the bottom of a well, sucks a mixture of sand and oil to the surface from an unconsolidated sand reservoir, such as the Ugnu. The slurry of sand and oil reaching the wellhead is pumped to a heated separation tank, where the sand sinks out of the oil for removal and disposal.
Successful test
In 2008 BP successfully tested the CHOPS technique in a single well at S-pad, using standard oilfield equipment to process the produced material. But the new facility represents a considerable scaling up of that initial test, with the installation of custom-built heavy-oil production equipment. That equipment includes a system for minimizing fire risks by heating the facility’s separation tanks indirectly using a closed loop of circulating fluid. BP had hoped to bring the facility into operation in May 2010 but it has taken until now to bring everything together, BP spokesman Steve Rinehart told Petroleum News March 14. The company expects to bring the first CHOPS well on line in mid-April, Rinehart said.
BP has drilled four wells for the testing at the new facility, with two of the wells being horizontal, West said. BP will put processed oil into the flow line for the Milne Point field, with waste sand being trucked to the Prudhoe Bay grind-and-inject facility for disposal.
The purpose of operating the pilot facility is to test the technical viability of heavy oil production, with the eventual aim of assessing the commercial feasibility of a future full-scale plant.
“We’re not quite sure what it is going to take commercially to make this work,” West said. “What we are focused on right now is proving technical viability.”
Needs light oil
Heavy oil, with a consistency of molasses, cannot flow unaided down a pipeline for transportation to market. And, although it might be possible to flow the product either by upgrading the oil in a North Slope refinery or by heating the transportation pipeline, BP does not view these options as commercially feasible, thus leaving the dilution of heavy oil production with light oil as the only commercial option for shipping the heavy oil from the Slope. “Because of that linkage (with light oil), the time to look at heavy oil is now,” West said. “And in fact the longer we wait to look at it, the more the light oil declines, and at some point we’re going to curtail the amount of heavy oil that we can get off the Slope.”
And the prize is huge, given the estimated 20 billion barrels of heavy oil in place on the North Slope. Added to the estimated 10 billion barrels or so in place of viscous oil, the slightly lighter oil that BP and ConocoPhillips already produce from West Sak-Schrader Bluff formation below the Ugnu, a recovery factor of just 10 percent would result in 3 billion barrels of recoverable oil, West said.
In fact, one purpose of operating the new Milne Point test facility is to determine what that recovery factor would be, although BP anticipates recovery percentages somewhere in the low teens using the CHOPS technique, West said.
Steam inappropriate
Recovery techniques involving the use of steam, in particular a technique called steam assisted gravity drainage, in operation in Canada, have been reported to have achieved recoveries in excess of 50 percent, but these techniques are not appropriate to the reservoir and oil characteristics in the Ugnu reservoir at Milne Point, West said. And with techniques involving steam it is necessary to evaluate the overall energy balance, determining whether more energy is delivered in the produced oil than is used in producing and injecting the steam required for production.
On the other hand the characteristics of the North Slope heavy oil deposits vary east to west in the Ugnu, so that, if heavy oil proves commercial, a variety of different production techniques would likely come into play, with initial production centered on a ramp up of heavy oil drilling around Milne Point S pad — development could involve the drilling of multiple horizontal wells from single, surface well bores, to minimize the surface footprint, West said.
Significant challenges
But commercial production of heavy oil will face some significant challenges. Heavy oil has less of the light, high-hydrogen components, valued for refining into high-value products such as gasoline, than does light oil, thus giving the heavy oil a lower market value than its lighter cousin. In addition, the production and usage of heavy oil would involve the use of the same value chain of pipelines, oil tankers, refineries and so on as light oil, but with new (and costly) technology bolted on — heavy oil is unlikely to ever be more economic than light oil, West said. “Heavy oil is not light oil that happens to weigh more,” West said. “It is in fact a different commodity. It has different technical challenges.”
And although BP’s test facility should this year provide some clarity over whether the physics of heavy oil production from the Ugnu works, it will likely take another couple of years, and perhaps another pilot project, to flesh out the production characteristics of the heavy oil resource, he said.
On the other hand, the heavy oil production, at its peak, could add 250,000 barrels per day to overall North Slope production.
“Should we be able to deliver that, it represents a renaissance and rejuvenation of the Alaska North Slope fluids business,” West said. “It’s a really large resource and we are committed to making it work.”
24 – 33 Billion barrels of Heavy Oil in Place
Heavy Oil Challenges & Opportunities North Slope Alaska
http://www.aoga.org/wp-content/uploads/2011/01/8.-Pospisil-Heavy-Viscous-Oil.pdf
Note: Oil in place is not the same as recoverable oil amounts. This is testing a new method to see how much oil can be economically recovered.
Alaska needs a refinery.
5 of them are fairly little.
Number and Capacity of Petroleum Refineries, Alaska
http://www.eia.doe.gov/dnav/pet/pet_pnp_cap1_dcu_SAK_a.htm
Another good reason for going into ANWR, IMO.
Ak will have oil for many years into the future and the price will only keep going up; making it more valuable and Alaska the most tax friendly state for it's residents.
Oil industry pays around 62% in taxes and that includes state, feds, and local. I read that many places around the world, the oil companys pay 80 & 90% and get shot at or nationalized or have various political upheaval problems in the end. So, I do believe oil will be coming out of the ground here in Alaska for another 50 years.
Until they get a natural gas pipeline, they don’t want more methane on the North Slope.
Beside, the oil pipeline needs more liquid.
What is the gravity of this stuff ?
Is there any of this heavy crude above the formations in the Prudho Bay Unit?
Thanks so much...... some but mostly next door
From the info, it appears Alaska’s six refineries operate at about 35% capacity in comparison to those in Louisiana and the bulk of their finished product is heavy distillates.
How did you come up with that? That link is capacities, not production.
I am interested into what numbers you are comparing.
It gives more detail about each refinery and the products produced. Jet Fuel is the most common.
In the “Operable (Barrels per Calendar Day)” column(s);
Alaska has six refineries with total bbls/day of 393,980
Louisiana has 17 operable with total bbls/day of 3,171,923
393,980 / 6 = 65,663 average per refinery
3,171,923 / 17 = 186,584 average per refinery
(65,663 / 186,584) x 100 = 35.19 percent
I realize there’s a world’s difference in the geographical locations of the refineries regarding climate, but is it 65% worth of a difference or does the difference occur in the refinery size/capacity? I honestly don’t know. Are Alaska’s refineries 65% smaller in scale compared to Louisiana’s?
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