KUPARUK ANNIVERSARY: Two rigs drilling West Sak at 1J pad
In 2004 ConocoPhillips and the other Kuparuk owners committed to expanding West Sak heavy oil production. Because of that commitment, Kuparuk River drill site 1J is the busiest in Alaska.
ConocoPhillips Alaska has two rigs drilling West Sak development wells at the new pad. At times during 2006, there were three rigs — two Doyon drilling rigs and a Nordic workover rig.
West Sak development drilling began at 1E in 2004 and will continue at 1J through 2007. The new wells are expected to increase West Sak oil production to about 40,000 barrels per day by 2008. (Production averaged about 10,000 bpd when the 1E and 1J development project was announced in 2004.)
In late 2006 there were 65 West Sak wells at Kuparuk drill sites 1B, 1C, 1D, 1E and 1J.
$1 billion in investmentsThe shallow West Sak viscous accumulation was discovered at Kuparuk in 1971. ConocoPhillips and co-owners BP, ExxonMobil and Unocal have so far committed $1 billion to its development.
Half of that, some $500 million, was spent over 20 years in experimentation to bring viscous development to the commercial stage at the deepest West Sak accumulation in the Kuparuk River unit, ConocoPhillips’ North Slope development manager Matt Fox said in December 2004. (At the time Fox was the Kuparuk area development manager.)
The $500 million West Sak investment announced by ConocoPhillips and BP in 2004 at one existing Kuparuk drill site, 1E, and one new drill site, 1J, includes 13 wells at 1E, 31 wells at 1J, expansion of 1E facilities and construction of a new pad at 1J, including facilities, pipelines and power lines.
Fox said the deeper viscous oil on the North Slope, called West Sak at Kuparuk and Schrader Bluff at Milne Point and at Orion and Polaris in Prudhoe Bay, combined with the shallower Ugnu formation, accounts for 23 billion barrels of oil in place, which is equivalent to the original oil in place at Prudhoe.
But this isn’t Prudhoe. Viscous oil suffers from “a triple whammy effect,” Fox said. “You’ve got the low rates, the low recovery factor and the low price.”
Cold, heavy oilWest Sak oil isn’t just heavy oil, it is “cold, heavy oil, and that means it’s extremely viscous,” he said.
The reservoirs are shallow, from roughly 3,000 feet below the surface to some 4,500 feet and they lie under some 1,800 feet of permafrost, so the reservoir temperatures vary from about 40 degrees Fahrenheit to about 90 degrees F, “and that combination of these cold temperatures and the relatively low API means that we have extremely high viscosities,” Fox said.
Prudhoe Bay and Kuparuk oil have about the same viscosity — ability to flow — as water, he said. West Sak has about the same viscosity as olive oil and the shallower Ugnu has viscosity similar to maple syrup.
In terms of production this is a big whammy, Fox said: West Sak is about 100 times as viscous as water. The flow rate of oil is “indirectly proportional to viscosity, so if viscosity increases by a factor of 100, which is what we have here going from the Kuparuk to the West Sak, rates will decrease by a factor of 100.”
In addition, recovery rates are lower because West Sak oil is very difficult to move out of the pore spaces in the formation, “it’s very difficult to displace because of its viscosity,” he said.
And refineries pay less for lower API oil than for Prudhoe or Kuparuk oil.
Technology changes allow productionWhile the North Slope producers have been trying to make the shallow accumulations commercial for two decades, Fox said, the developments that finally made the best of this oil commercial have all been since the late 1990s.
Well types have changed from vertical to horizontal multilateral; drilling reach changed from moderate to extended reach; the recovery mechanism has changed from waterflood to waterflood enhanced by lean gas injection; and the method of dealing with sand has changed.
The viscous West Sak-Schrader Bluff and Ugnu reservoirs are unconsolidated, poorly cemented and sand is produced with the oil.
In the late 1990s, the focus was on keeping the sand in the reservoir by using costly sand screens in the well bores. The problem was some of the West Sak sand is as fine as flour and you couldn’t devise a screen that could keep it back; plus, restricting sand with screens constrained the flow rate and was exacerbating the viscosity problem.
Fox said the solution was to focus on flow rate and deal with the sand that came to the surface by re-injecting it.
Well spacing has also changed, from 1,100 feet to 1,250 feet. It may not look like a big deal, he said, but the more distance you can put between the wells, the fewer you have to drill — a “big deal for lowering costs.
Keeping the oil flowingAnother thing that’s changed is keeping the oil flowing.
Electric submersible pumps were used to move the heavy oil to the surface, but they break down, and wells had to be shut in for months waiting for a workover rig. “And that would kill the economics of the project because of the level of the failures,” Fox said.
They are still using electric submersible pumps, but now they are building in backup: the ability to use gas lift when the pumps fail, “so we can keep some level of production going, and that made a surprisingly big difference to the economic viability.”
An oil-based mud system replaced a water-based mud system for drilling, improving both drillability and productivity.
And how the oil is handled at the surface changed, Fox said.
The initial plan was to mix West Sak oil with Kuparuk production since both occur at the same drill pads, but experimentation showed that wasn’t enough, Fox said, so heaters are being added at the drill sites and chemicals are added to allow the sand to drop out of the oil.
And the volume of oil that can be accessed from a single well has changed because extended reach multilateral wells are now possible because of “new technologies like rotary steerable systems and more efficient torque reduction tools (and) more efficient mud systems,” increasing production from some 200 bpd from 1980s vertical wells to 2,500 to 3,000 bpd from long tri-lateral wells.
Waterflood plus gasViscous oil is difficult to displace from rock pores because of its viscosity, Fox said. With waterflood, a recovery rate of some 18 percent is possible. In the deeper North Slope conventional reservoirs miscible gas injection is used for enhanced oil recovery, a type of gas injection where the gas injected mixes with the oil in the reservoir.
But viscous oils “don’t lend themselves to a miscible process,” Fox said, so instead of miscible gas, lean gas will be used. ConocoPhillips is pilot testing this process now, he said.
The lean gas doesn’t mix with the oil, but “some molecules in the gas link to the oil and very little exchange is enough to drop the viscosity dramatically,” for example from 60 centipoise (a measure of viscosity) to 10 centipoise, which produces “a significant increase in the displacement.”
The expected increase in recovery with lean gas injection is 20 percent over waterflood, increasing total recovery to about 22 percent.
Slope-wide sharing“The only way we were really able to exploit these technology advantages is because we made a concerted effort to share knowledge across the slope and within the operating companies,” Fox said.
In an early 2007 comment to Petroleum News, Don Dunham, performance unit leader at BP, agreed with him, saying viscous oil production across the North Slope (BP-operated Prudhoe Bay and Milne Point plus ConocoPhillips-operated Kuparuk) has benefited from industry cooperation and technical challenge.
“BP realized that viscous oil in Alaska is so economically challenged that if the owners did not all put our heads together, we would not realize the best outcome. Alaska has benefited from this cooperation which BP hopes will continue as we look ahead to finding solutions to the Ugnu challenge,” Dunham said.
“The advances in the production of the North Slope’s viscous oil resources and the related technology breakthroughs would not have been possible without knowledge sharing among the West Sak co-owners,” Georg Storaker, ConocoPhillips vice president of North Slope operations, told Petroleum News in January 2007. “It is unprecedented to see companies like BP, ExxonMobil, ConocoPhillips and Chevron work together to tackle the North Slope’s massive undeveloped heavy oil resources.”
The North Slope viscous inter-company technical team is mainly driven by ConocoPhillips and BP with some ExxonMobil participation.
“Other co-owners supporting the team’s activities are kept informed of best practices and knowledge sharing which may have broader applications,” ConocoPhillips Alaska spokeswoman Dawn Patience told Petroleum News in January 2007.
One thing the viscous team has been asked to do was to improve the ability to predict rates. “We had a track record of over-promising and under-delivering and it was killing our credibility outside Alaska when we would go looking for funds,” Fox said.
Sand control is another issue the viscous team tackled, as was depletion planning, getting the oil out of the ground, “and that team came up with the idea of doing viscosity-reduction gas injection,” he said.
The team is continuing to work, learning from implementations and looking at what can be done next.
What about the rest?Of the 23 billion barrels in place, some 15-16 billion barrels are at Kuparuk, with 1C and 1D, the experimental pads, developing about half a billion barrels and the 1E and 1J pads exploiting oil in place of about a billion barrels. “And that same technology that we’ve unlocked for 1E and 1J, we can apply to somewhere between another 800 million to a billion barrels,” Fox said.
But technology breakthroughs will be required to unlock the rest of the potential.
The drilling technology can be used, “but not the recovery mechanism, not waterflood: you can’t effectively waterflood.” It will take new technologies, Fox said.
The exotic, heavy oil “fish bone” wells drilled in Venezuela work there because it’s primary depletion only; the oil is too viscous for waterflood. They’re pumping out the 10 percent they can get with primary depletion and leaving the rest in the ground, Fox said.
At West Sak, with waterflood, wells need to be in straight lines for efficient waterflood sweep.
The exotic wells might be a possibility, he said, in shallower portions of West Sak or for the Ugnu, if primary depletion were to be used there.
Steam assisted gravity drainage, used in Canada, wouldn’t work for the West Sak because the sands are too thin, but it might work in the thicker Ugnu formation, and “we’re running laboratory experiments and reservoir simulation experiments to try and see if we can make this viable,” Fox said. “But there are some big challenges in this environment: we have 1,800 feet of permafrost (and) pumping steam through that — that has to be thought through.”
The technology advances that allowed 1E and 1J to be commercial “have been rapid and they’ve been dramatic,” Fox said. “And we’re actively working on the next technology breakthrough we need to get to the even more viscous stuff.”
Results to dateThere was a West Sak pilot project in the mid-1980s but sustained production only began in December 1997.
Alaska Oil and Gas Conservation Commission records show 25.9 million barrels produced from West Sak through the end of November 2006, with 490,616 barrels produced in November, an average of 16,355 barrels per day from 36 producing completions.
Total Kuparuk River field production for November was some 4.4 million barrels, so West Sak accounted for 11 percent of Kuparuk production in November.