Hilcorp to resume heavy oil tests at Milne Point field
Hilcorp Energy hopes to take a new look at a massive heavy oil accumulation in the Milne Point field of the North Slope, where Hilcorp is the field operator and a 50 percent-owner with partner BP.
The company is considering a restart of a test production program from the Ugnu formation that was operated by BP for several years but then suspended in 2013, Hilcorp spokeswoman Lori Nelson confirmed.
BP conducted a four-well production test in the Ugnu formation, and achieved a rate of 600 barrels per day in some tests.
Two vertical wells and two horizontal test production wells were operated by BP, but Hilcorp is considering resuming the test with one well, Nelson said.
The tests were considered a technical success by BP in that new technologies being experimented with, mainly a Cold Heavy Oil Production System, or CHOPS, showed increased daily production rates, but there were also mechanical problems.
BP shut down the wells to address those but then never restarted the program. Sources familiar with the program said BP was also shifting its Alaska priorities, and resources, to commercialization of stranded North Slope gas at the time.
“We’re very interested but we also have potential conventional oil projects on our plate at Milne Point,” Nelson said.
A custom-built grind-and-inject facility in Milne Point, which disposes of waste rock underground, would also have to be restarted for the program, she said.
Alaska Natural Resources Commissioner Mark Myers said his agency is pleased at Hilcorp’s aggressive stance in tackling new Slope projects.
“It’s exciting to see them this engaged and grabbing opportunities,” Myers said.
North Slope producers have looked at ways heavy oil might be produced for years, investigating techniques like in-situ heating to warm the oil. One promising approach that BP pursued was CHOPS, a technique borrowed from Alberta where it is used to produce heavy oil.
CHOPS involves an auger device that rotates in the well, bringing the oil and sand from the shallow producing formation, to the surface. Unlike viscous oil production also done on the North Slope, and where operators work to keep sand out of a well (the sand can damage pumps), an inflow of sand into an Ugnu well is encouraged in the CHOPS approach.
With CHOPS, as sand falls out of the rock into the well bore it opens up channels, or “wormholes” in the rock, enhancing the flow of oil fluids. As more sand is extracted, the wormhole network expands in the reservoir. The idea worked in Alberta and BP’s tests showed it can work on the North Slope.
A key operational problem pointed up in BP’s test was that CHOPS, as a mechanical procedure (using the auger), requires frequent maintenance. This is affordable in Alberta where there is a well-developed industry support sector, sources familiar with the program said.
However, it is less affordable on the North Slope where costs for drill rigs and other equipment are high, the sources said. A lower-cost approach to drilling and maintaining wells will be needed for heavy oil production to succeed, the sources said.
There are other challenges, too, among them that heavy oil would be discounted in sales because of its lower quality. Its value would be adjusted downward in the Trans-Alaska Pipeline System Quality Bank, a mechanism used by TAPS shippers to adjust for quality differences in crude oil value in the pipeline. Ugnu oil is 10 to 15 degrees API gravity compared with 29 API gravity or better for North Slope conventional “light” oil.
Another problem is that the Ugnu oil won’t flow by itself in a pipeline and must be mixed with conventional “light” oil on almost a one-to-one ratio.
All this has given heavy oil a bit of a bad reputation.
“The resource is considered high cost and low return, but this need not be true,” said one person knowledgeable with Ugnu deposit. “This assumes you use existing equipment, such as drilling rigs, under the contracts that exist today on the Slope. If you do that you will get high costs and low return.”
CHOPS showed that daily well rates could be boosted, but to operate the wells on a commercial basis new types of lower-cost drill rigs must be developed, which might be possible because the Ugnu is very shallow, and ways of maintaining the wells for lower costs must be found.
The potential resource is huge, however.
“The oil-in-place estimate of heavy oil in the Ugnu deposit ranges up to 21 billion barrels, of which 5 to 10 percent is considered technically (but not yet economically) recoverable,” said Paul Decker, a senior geologist with Alaska’s Division of Oil and Gas.
The deposit is shallow and extends across areas of the Prudhoe Bay and Kuparuk River fields as well as Milne Point, Decker said. Some of it is actually frozen in the permafrost layer that underlies much of the North Slope, he said.
Ugnu’s oil originated in the same places that the conventional “light” oil on the North Slope, the large shale formations south of the Prudhoe Bay and Kuparuk River fields. Over millions of years, oil seeped out of the shale “source rocks” and migrated upward, and northward, along faults and other pathways through the rocks, Decker said.
Some of it was trapped at deeper levels in the large sandstone formations that are now the producing conventional oil fields, and some kept migrating to shallower levels, where temperatures were cooler, and became the “viscous” oil deposits that were also found and which are producing today, such as the West Sak formation in the Kuparuk field.
Some of the migrating oil missed both the deeper and shallower traps and kept seeping upward to even shallower, cooler levels, to accumulate in what is now the Ugnu deposit beneath the permafrost.
Over the years a lot of ideas have been considered for Ugnu including ways of warming the oil in-situ, or in the underground formation, so that it will flow. Steam injection, for example, is used to lighten and produce heavy oil in other places.
The concern for steam injection on the North Slope is that injecting the steam from the surface will also warm the permafrost and thaw it, an undesirable outcome. Also, the cost of producing the steam at the surface would be a consideration.
Other ideas have been toyed with including placing electrical heating devices underground. Those would create cost barriers too, however. So far the CHOPs approach of augering the oil and sand mixture to the surface appears to be the most workable course, and one that Hilcorp would like to continue pursuing.