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BP heavy oil pilot exceeds expectations Cumulative production to date from Milne Point Ugnu is about 75,000 barrels, with peak well rates of around 500 barrels per day Alan Bailey Petroleum News
The estimated 12 billion to 18 billion barrels of heavy oil known to exist in the shallow Ugnu formation, above the reservoir rocks of major oil fields on Alaska’s North Slope, represents a huge, as-yet undeveloped oil resource. But can North Slope heavy oil, oil too viscous to flow unaided through a pipeline, ever go into commercial production, bolstering declining oil production from the operational North Slope fields?
BP has been conducting a pilot project, testing the feasibility of producing heavy oil from the Ugnu in the Milne Point unit, between the Prudhoe Bay and Kuparuk River fields. And so far the results look promising, Josef Chmielowski, BP’s Alaska heavy oil appraisal team lead, told the Alaska Geological Society on Feb. 21.
“The BP heavy oil pilot has exceeded expectations,” Chmielowski said. “It’s really beaten what we thought was possible.”
Cumulative oil production to date from the pilot project is 75,000 barrels, with production rates from individual test wells topping 500 barrels per day, he said.
Different industry However, Chmielowski emphasized that the production of heavy oil constitutes, in effect, a different industry from light oil production, with added costs at all points of the value chain and, ultimately, a lower value in the market for the product. Heavy oil requires, for example, more wells than light oil, special on-pad processing, the disposal of large quantities of produced sand, and the use of light oil as a diluent, to ship the oil to market.
On the other hand, there has been successful heavy oil production for a number of years in Canada, Venezuela and California, Chmielowski said.
And the commerciality of heavy oil depends on oil prices.
“Heavy oil will never be economic at $40 or $50 per barrel,” Chmielowski said. “At $60 to $100 it could be competitive.”
The situation in Alaska is fortunate, since the heavy oil deposits lie above light oil reservoirs, thus making light oil diluent readily available while also placing the heavy oil in proximity to the existing oil infrastructure.
Layered cake The rock strata of the central North Slope form a kind of layered cake, with the relatively shallow Ugnu formation containing heavy oil towards the top. Below the Ugnu lies the Schrader Bluff or West Sak formation, the rock unit that reservoirs what the Alaska oil industry refers to as viscous oil, oil that is relatively difficult to flow but which BP and ConocoPhillips have been producing using horizontal drilling techniques. Deeper still lie the rocks that reservoir the light oil of the Prudhoe Bay and Kuparuk River fields.
In Alaska, people distinguish between viscous oil and heavy oil on the basis of water flood capabilities: Viscous oil can be flushed out from the reservoir using water, but heavy oil cannot, Chmielowski said.
Geologists believe that oil became trapped in the Ugnu and Schrader Bluff formations after spilling upwards from the deeper Prudhoe Bay reservoir, as that reservoir tilted during the geologic past. And microbes that are inactive in the relatively high temperatures of deep reservoir rocks chomped into the cooler oil in the shallower rocks, degrading the originally light oil into heavier fractions. The shallower and colder the oil, the more active were the microbes, thus leaving viscous oil at intermediate depths and heavy oil in the shallow Ugnu, Chmielowski explained.
Slopes east A cross section of the central North Slope reveals the layered cake of rock strata to be sloping gently west to east.
Where the Ugnu is shallowest, to the west, above the Kuparuk River field, the microbes have been most active, rendering the oil especially dense. And, with low subsurface temperatures not far below the base of the permafrost, the dense oil is particularly viscous. Towards the east, above the Prudhoe Bay field, with the Ugnu becoming deeper, the oil is less dense and less cold, and consequently less viscous.
Many techniques There is a large arsenal of potential techniques for the extraction of heavy oil. And, because of the range of properties of the heavy oil at different locations in the central North Slope, different extraction techniques would be appropriate in different places, Chmielowski explained. The key factor in selecting a particular technique at a particular location is the viscosity of the oil — the ease with which the oil flows, he said.
The especially high viscosity of the heavy oil above the Kuparuk River field would require the application of heat for successful oil production, using one of a number of thermal technologies such as the injection of steam into the reservoir. Over Prudhoe Bay, where the oil is less viscous, a cold oil production method would be the technique of choice — cold production typically does not achieve such high oil recovery factors as thermal production but, without the need for expensive, heat-inducing technology, cold production is more cost effective, Chmielowski said.
With the Milne Point location where BP is conducting its heavy oil pilot being at the midpoint between Kuparuk and Prudhoe Bay, BP could have tested either thermal or cold techniques. However, the company opted for cold extraction, given the better economics of this approach, Chmielowski said.
Use CHOPS With the Ugnu reservoir rock consisting of unconsolidated sand, BP had to decide whether to try to keep sand out of wells during oil production, or whether to allow sand into wells, potentially damaging pumps and other equipment in the oil production facilities. But an early test well failed to produce when sand plugged screens intended to keep the sand from entering the well. BP subsequently opted for a technique known as cold heavy oil production with sand, or CHOPS, in which oil production is maximized by deliberately extracting sand from the reservoir along with the oil.
CHOPS has been used successfully for some heavy oil production in Canada, Chmielowski said.
BP’s implementation of CHOPS involves the use of what is called a progressive cavity pump, a device consisting of a long, augur-like rotor deep inside the well. The pump motor sits at the wellhead, connected to a rotating rod that passes down through the well to drive the pump’s rotor. The spinning rotor draws down the pressure in the well, sucking a mixture of oil and sand into the well and pushing the mixture to the surface.
Foaming effect In the reservoir, minute gas bubbles in the oil expand as the pressure drops, causing the oil to foam, a bit like shaving cream from a can, driving oil towards the well and allowing the oil to flow.
At the surface, the slurry of sand and oil is directed into a heated settling tank, where the sand drops out, to be removed and disposed down a suitable injection well. The heavy oil, now devoid of sand, can then be mixed with light oil and processed through conventional production facilities.
In the subsurface oil reservoir, the extraction of sand into the well causes fractures called wormholes to propagate outwards from the well, providing channels through which oil can travel to the well. Unlike with a conventional oil well, where production typically peaks quickly and then declines, production from a CHOPS well grows slowly as the wormholes propagate through the reservoir, with production then plateauing perhaps for several years before eventually declining, Chmielowski said.
“Typically a wormhole network takes six to 18 months to develop,” he said.
Test facility Although the North Slope oil producers have been interested in the region’s heavy oil potential for many years, BP “really got serious about it” in 2003, establishing a formal heavy oil team in 2005, Chmielowski said. Eventually the company built a $100 million heavy oil test facility on S-pad in the Milne Point field, with that facility coming on line in April 2011.
One particular challenge that the company faced was the discontinuous nature of the Ugnu reservoir. Laid down millions of years ago as sand in meandering river channels in a river delta system, rather like the existing rivers on the North Slope, the individual sand channels are too small to be resolved in an image of the subsurface derived from seismic data. And because of the thick, viscous nature of the oil in the sand, there is relatively little possibility of the oil flowing or communicating between one sand body and another.
Four wells BP elected to try four test wells in relatively thick sands in what are referred to as “the upper and lower M80,” the sand units that form “anchor horizons” in the Ugnu, Chmielowski said. The plan was to drill two steeply inclined wells in the lower M80 and two horizontal wells in the upper M80, he said. The target vertical depths of the wells were around 3,700 feet.
The first of the horizontal wells, the Milne Point S-41A, achieved a horizontal length of 2,700 feet. However, constraints resulting from geologic faults limited the length of the other horizontal well, the S-39, to 1,400 feet, Chmielowski said. Some poor rock quality also constrained the effective length of the S-39 well, he said.
500 barrels per day The S-41A well, the first well to go into a production, came on line at 300 barrels per day in 2011. Production eventually reached more than 500 barrels per day, before the drive rod for the pump wore a hole in the well casing in the area where the rod rubs against the casing in the heel of the well, the area where the well bore bends into a horizontal configuration.
BP brought the second horizontal well, the S-39 well, on line in April 2012. Much to people’s surprise, given the well’s relatively short horizontal length, that well also started at about 300 barrels per day, eventually peaking at similar maximum rate to the S-41A well. And, as with the S-41A well, the pump rod eventually wore a hole in the S-39 well tubing.
Each of the wells ended up producing oil for about four months before failing. In the future BP wants to try using a tubular lining something like Teflon in the well pipe, to reduce wear from the pump rod and push the time to failure out to perhaps one year, Chmielowski said.
After an unsuccessful attempt to repair the S-41A well, BP decided to plug and abandon the well. A similar attempt to repair the S-39 well succeeded, but the test team spend several months trying to restore production in that well — heavy oil wells do not like to be shut in, Chmielowski said.
The plan now is to test the two steeply inclined wells, running those wells until they fail, with the heavy oil pilot shutting down in the summer of 2013, Chmielowski said.
Conclusions And the conclusions so far from the testing?
The completed well tests demonstrated that the Ugnu has the reservoir pressure and gas content to successfully drive a CHOPS system, Chmielowski said. Production rates exceeded those in commercial CHOPS wells in Canada but were less than the 750-barrel-per-day rates in horizontal heavy oil wells in Venezuela, he said. The on-pad heavy oil facility worked, and heavy oil was successfully shipped to market.
The successful operation of two wells has shown to some extent that successful production can be repeated, rather than being a fluke of luck in a single well. However, further tests are needed to demonstrate repeatability over multiple wells, Chmielowski said. In addition, the sustainability of production over long periods has yet to be demonstrated, especially given the mechanical problems with the test wells.
And, since production from each well did not continue long enough to reach a production plateau, with fully developed reservoir wormholes, the tests did not demonstrate the ultimate potential of the wells.
Furthermore, although models of potential production profiles suggest that heavy oil production from the Ugnu could prove commercially viable, BP has not yet demonstrated commerciality.
“Until we figure out some of the mechanical issues (with the wells), it’s in the grey zone right now,” Chmielowski said. And it will be critical to produce the heavy oil while there is still plenty of North Slope light oil production, to provide diluent for the transportation of the more viscous product.
In summary, there is a lot of good news, but many challenges remain, he said.
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