You’ve heard of driverless cars, but how about unmanned SAGD projects?
“If we can put production systems on the seabed, we can de-man oilsands,” says Kieron McFadyen, Cenovus’s executive vice-president and president of upstream oil and gas. Speaking at Cenovus’s annual investor day in June, McFadyen said, “For new next-generation SAGD projects, it’s a longer-term vision to move towards zero manning in the field during production operations.”
In fact, something similarly futuristic is already occurring, although not in production operations.
Rather than build everything in the field where costs are higher and schedules are less reliable, Cenovus builds ready-to-assemble modules at metal fabricating shops. But who ensures those modules will all fit together when they arrive in the field? “A robot that we leave alone at night in the Nisku module yard,” said Harbir Chhina, Cenovus’s chief technology officer and executive vice-president.
“This robot basically goes around the module yard and figures out how much work got done on each module,” he told analysts. “It also takes the 3-D drawings and compares it to the module. And so it will figure out, ‘Once we send this module to the field, will it fit together or won’t it?’ And so we’d rather do the rework at Nisku rather than do the rework in the field.”
Returning to McFadyen’s vision of zero personnel in production operations, Chhina said, “Is it possible to get there? I don’t know if we’ll get to zero. Can we get close to zero? That’s what we’re trying.”
$2 billion for diluent
Alberta oilsands producers have always faced the challenge of shipping to distant markets. Do you spend billions of dollars to convert the semi-solid bitumen into light crude that can flow through pipelines? Or do you spend a fortune on diluent—which itself costs more than light crude—to make the bitumen pipelineable? Each has its downsides.
Upgrading bitumen to light crude oil lightens carbon-heavy bitumen molecules by adding hydrogen. But manufacturing hydrogen on such a massive scale is so expensive that producers, such as Cenovus, have concluded if you’re going to convert bitumen to light crude, you might as well go all the way and produce premium products, such as gasoline and jet fuel.
But letting refineries do the upgrading means pipelining non-upgraded bitumen to those distant plants, which takes a hell of a lot of high-priced diluent. Chhina said Cenovus expects to spend about $2 billion on diluent this year. That’s because it takes roughly one barrel of high-priced diluent to pipeline two barrels of low-priced bitumen.
Surely there’s a better way? Cenovus thinks so. The company has been evaluating ways to cheaply upgrade bitumen just enough to be pipelined with no diluent—or at least a lot less than is used now.
At a 1,000-bbl/d pilot plant run by Fractal Systems, Cenovus has extensively tested a partial upgrading method called Enhanced JetShear with Acid Reduction Process.
In a nutshell, Fractal’s process heats up the bitumen to about 400 degrees Celsius and 3,000 pounds per square inch of pressure. It is then instantly depressurized, which helps break the heavy molecules, reducing viscosities.
Like most proposed partial upgrading processes, Fractal’s process uses hydrogen—but only to remove olefins, so hydrogen consumption is on a much smaller scale and at a much lower pressure than for full upgrading.
Cenovus estimates the process would reduce diluent requirements by 40–50 per cent and cut costs by $3–$5/bbl. It would reduce the total volume being transported by about 15 per cent since there would be less diluent per barrel of bitumen shipped. In a world where it’s increasingly hard to get new pipelines built, this would free up capacity on existing pipelines. Fractal’s process would also raise the value of the oil by reducing the total acid number to 0.5. “Most of the blends that we produce today are closer to one,” Chhina said. “This technology is scalable—anywhere from 5,000–10,000 bbls/d to 100,000 bbls/d.”
Chhina said the completion of engineering designs this year will give Cenovus a better idea of the next step toward commercializing the process. However, he noted the company is also working on “three or four other [upgrading processes] that we’ll talk about once we reach the stage where we feel very comfortable that we can commercialize these technologies.”
Burning less gas
As they plan for long-term growth, oilsands producers face two challenges. One is to cut costs to better compete with the flood of light crude from the U.S. shale plays. The other is to cut greenhouse gas emissions so production can continue to grow amid climate mitigation constraints.
Since oil prices fell three years ago, no new oilsands megaprojects have begun construction (though some deferred projects have been restarted). In an era of oil price uncertainty, the bar is much higher than when WTI traded above US$100/bbl. What if oil prices fall further? Would major new oilsands developments be profitable? Amid such uncertainty, no brand-new megaprojects have broken ground.
A harbinger of future oilsands investment is evaluation drilling as companies try to determine whether their acreage holds enough bitumen to support decades of production. Only 465 permits for oilsands evaluation wells were issued last year, compared to 1,728 in 2014 and 3,448 in the boom year 2008.
And then there are the looming regulatory constraints. With the support of several major oilsands operators, Alberta last fall passed legislation capping the sector’s greenhouse gas emissions at 100 megatonnes per year. Oilsands operations currently emit roughly 70 megatonnes per year. When the limit might be reached is a matter of debate, but there’s no doubt it would cap oilsands growth unless per-barrel emissions could be lowered.
The industry believes technology can help solve both the economic and climate challenges. The Canadian Association of Petroleum Producers estimates that if steam to oil ratios could be cut by five per cent, the province could add 140,000 bbls/d of bitumen production within the emissions cap.
One such technology is Cenovus’s solvent-aided process (SAP), which adds a small amount of a solvent such as butane or propane to the steam injected into SAGD wells. The light hydrocarbon solvent goes into the solution with the semisolid bitumen, thinning it so less steam is needed to get it to flow to production wells.
The less steam needed, the less natural gas burned to boil water—hence the reduction in greenhouse gas emissions. Burning less gas also improves a project’s economic performance, as does the increased bitumen recovery Cenovus expects to achieve with SAP.
So far, no one has built a large-scale greenfield oilsands project using solvents. Imperial Oil uses solvents with its liquid addition to steam for enhancing recovery (LASER) process at Cold Lake. But while LASER is used extensively there, Cold Lake wasn’t developed as a solvent project. Rather, the solvent—in this case, diluent—is added to mature cyclic-steam wells. Separately, Imperial has sought regulatory approval for commercial-scale use of solvent-assisted SAGD (SA-SAGD). Imperial, a pioneer in steam-assisted bitumen recovery, hopes to use SA-SAGD at its Aspen oilsands property, northeast of Fort McMurray, and in the Grand Rapids Formation at Cold Lake.
However, Cenovus expects its proposed Narrows Lake SAP project will be the industry’s first commercial implementation of solvents at a greenfield project. Narrows Lake was deferred after oil prices crashed. The company hasn’t decided when to built Phase A, which is expected to produce up to 65,000 bbls/d of oil. Meanwhile, Cenovus will begin converting an existing SAGD well pad at Foster Creek to SAP before year’s end.
So what else does the company have up its sleeve? Cenovus has always said it’s working on many new technologies, but it doesn’t usually discuss them publicly until they are sufficiently advanced. What it does say is to stay tuned for big changes.
“We are transforming our company at what I believe is a pivotal time in the industry and the beginning of a technological renaissance,” Brian Ferguson, Cenovus’s president and chief executive officer, told analysts on the company’s first quarter earnings conference call in April.
How big will these changes be? Ferguson believes new technologies have the potential to transform Alberta’s oilsands sector in the way drilling and hydraulic fracturing improvements produced the U.S. shale revolution that added about five million bbls/d of oil to world markets.
“We have exactly that same opportunity from 2016 to 2020 in the oilsands to have that kind of technological innovation,” he told reporters after Cenovus’s 2017 annual meeting. Technologies that are commercially deployed on a large scale in other sectors are only now getting attention in the oil and gas industry. Ferguson says, “We’ve only just started to scratch the surface in terms of big data, digitization [and] automation.”
Image: Cenovus Energy