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Technology driving West Sak viscous development More technology breakthroughs will be needed if more of 23 billion barrels of heavy oil at West Sak-Schrader Bluff, Ugnu is to be developed Kristen Nelson Petroleum News Editor-in-Chief
It has taken a lot of technology — and a lot of money — to make some of the West Sak and Schrader Bluff viscous oil on the North Slope commercial. And more money and more technology breakthroughs will be needed to develop shallower West Sak-Schrader Bluff accumulations and the even shallower and more viscous Ugnu.
Matt Fox, ConocoPhillips Alaska greater Kuparuk area development manager, told the Alaska Support Industry Alliance Dec. 15 that it took 20 years, and $500 million in experimentation, to bring viscous development to the commercial stage at the deepest West Sak accumulations in the Kuparuk River unit. That’s $500 million in addition to the $500 million in capital the field owners just sanctioned for development of the West Sak accumulation at the 1E and 1J pads in Kuparuk.
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, combined with the shallower Ugnu formation, accounts for 23 billion barrels of oil in place, Fox said: a volume of oil equivalent to the original oil in place at Prudhoe Bay. Low rates, low recovery, low price But, he said, the viscous oil suffers from “a triple whammy effect: you’ve got the low rates, the low recovery factor and the low price.”
This oil isn’t just heavy oil, he said, it is “cold heavy oil, and that means it’s extremely viscous.” The reservoirs are shallow, from roughly 3,000 feet below the surface down 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.”
Prudhoe Bay and Kuparuk oil have about the same viscosity, ability to flow, as water, Fox said. West Sak has about the same viscosity as olive oil. Ugnu has about the same viscosity as maple syrup.
In terms of production this is a big whammy: 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 the 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.”
And refineries pay less for lower API oil than for Prudhoe Bay or Kuparuk oil. Rapid changes in last few years While the North Slope producers have been trying to make the shallow accumulations commercial for two decades, Fox said, the things that finally made the best of this oil commercial have all been recent developments, since the late 1990s.
Well types 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 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 sand screens in the well bores. Fox said there were three problems with this: some of the West Sak sand is as fine as flour and you couldn’t devise a screen that could keep it back; restricting sand with screens restricted the flow rate and “was exacerbating the viscosity problem;” and the screens were costly.
The solution was to focus on flow rate and deal with the sand that came to the surface by re-injecting it, Fox said.
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 wells, the fewer you have to drill, “And that’s a big deal for pushing down the cost.” Keeping the oil flowing Another thing that’s changed is keeping the oil flowing. Electric submersible pumps are used to move the heavy oil to the surface, but they break down, and because Kuparuk doesn’t have a fulltime workover rig, wells could be shut in for six months at a time. “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, he said.
The initial plan was just to mix West Sak production with Kuparuk production, since both occur on the same drill pads, but experimentation showed that wasn’t enough, Fox said, and so heaters are being added at the drill sites and chemicals are being 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 barrels per day from 1980s vertical wells to 2,500 to 3,000 bpd from long tri-lateral wells. Waterflood plus gas The viscous oil is difficult to displace from the 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 oil 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. This is in pilot testing now, he said.
The 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 (centipoise is 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, and called the level of knowledge sharing “unprecedented.”
The North Slope viscous team included technical staff from ConocoPhillips and BP, with some ExxonMobil participation.
One thing the team was 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 creditability outside Alaska when we would go looking for funds.” Sand control was 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,” Fox said.
The North Slope viscous team is continuing to work, he said, 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,” he said.
But technology breakthroughs will be required to unlock the rest of the potential, “because once you move out of that eastern part of the West Sak, the viscosity’s too large to use the technology that we have,” Fox said.
The drilling technology can be used, “but not the recovery mechanism, not waterflood, you can’t effectively waterflood.”
It will take new technologies, he said.
The exotic, “fish bone” wells drilled in Venezuela’s heavy oil fields work because that is 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. “The knowledge sharing across the slope … — and across the world in fact — has been very leveraging …
“And we’re actively working on the next technology breakthrough we need to get to the even more viscous stuff.”
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