The Search for the Lowest-cost Barrel and the Future of the Alberta Oil Sands
In a sector long-defined by its sky-high costs, being able to bring them down has suddenly become a matter of survival. How oil sands development is changing – for good
With its giant concave TV screens, soft lighting and automatic sliding-glass doors, General Electric’s Customer Innovation Centre feels more like a Google satellite office than a place where people come to discuss heavy oil technologies. But the downtown Calgary center plays a major role in GE’s attempt to solve various issues surrounding oil development – including how to cut costs in the oil sands. “This is where we’re building on what we can do today and tomorrow to reduce costs,” says James Cleland, the global general manager for GE Heavy Oil Solutions.
In the current environment, there is a heightened level of urgency to do just that. Steve Laut, the president of Canadian Natural Resources, captured that sentiment when he told his audience at an event on February 19 in Fort McMurray that failure to cut costs would send the oil sands industry into a “death spiral.” Producers have already posted major cost reductions by trimming their workforces, shelving expansion projects and taking advantage of rising competition between vendors. But there are also longer-term, structural changes taking place, from how new projects are constructed to how existing projects are monitored and maintained. The result could make oil sands development leaner, more predictable and more efficient. More importantly, it could make Canada more competitive with U.S. shale producers. Amid a low price environment, the very mentality of oil sands producers has changed – as has the way the barrels are being produced.
One of the biggest cost-saving developments involves replication, the process in which engineers work toward designing the ideal facility and then stick to that same design through successive phases of construction. “We’re working toward having a SAGD plant that is ‘cookie cutter’ and repeatable,” Cleland says. Suncor Energy is filing an application to develop its Meadow Creek East project, located just south of Fort McMurray, where it plans to target small pockets of oil that together total between 400 and 600 million barrels using small-capacity SAGD plants that will be built once and then copied. “In terms of project-to-project similarities, the engineering will be as identical as possible,” Erin Rees, a spokesperson for Suncor, said in an email. Together, the projects could amount to about 250,000 barrels per day of new production spread across its Meadow Creek, Lewis, MacKay River and Firebag leases, the first of which wouldn’t come online until 2019 at the earliest.
The strategy marks a shift away from larger-scale projects as producers try to gauge the highest per-barrel return on investment. After years of experimenting, researchers and engineers are closer than ever to finding the ideal size for a typical SAGD plant – and it’s well below megaproject volumes. “We’ve been after the optimum size plant for years,” Cleland says. “We started large-scale [roughly 100,000 bpd] then scaled back a bit to 10,000 or 12,000 barrels, then tried a couple plants at 5,000. Now we’re going back to something more in the 20,000- to 40,000-barrel range.”
Most SAGD operations cost between $20,000 and $50,000 per flowing barrel, or as much as $1.5 billion for a 30,000 bpd project. Producers and companies like GE are attempting to reduce that, and replication could be central in doing so. It is difficult to determine how much money successful replication strategies could save an oil sands operator, but a 2008 report in the Journal of Product Innovation Management says savings through repeated designs across various industries averages 67 per cent. But while producers continue to struggle with high construction costs, installation costs are improving. Cleland says GE has brought its total installed costs multiplier down from five or six to less than two (for equipment costing a total of $1 million, for example, it would then cost less than $2 million to procure and install the facility).
Replication is not new to the oil sands, mind you. MEG Energy, ConocoPhillips, Imperial Oil and Devon Canada have used replication for years. The most often-cited example is Cenovus Energy’s Foster Creek and Christina Lake projects, where per-barrel costs are among the lowest in the industry. Each of the company’s well pads are identical, and are fabricated in a Cenovus-owned shop in Nisku, which simplifies construction and supply chain management for the company. But uncertainty in oil sands operations can make replication difficult to carry out, and different reservoir characteristics can force engineers to change design plans or introduce new technologies. Suncor’s Firebag project, for example, started stage one using warm lime softeners, then switched to evaporators in stage two only to go back to warm lime softening in stage three.
Such adjustments are common, but they can cause unnecessary complications, and raise project costs accordingly. “There are a few companies who are doing [replication], but it requires a great deal of discipline,” says Alnoor Akberali Halari, the author of a report called “Replication of Oil & Gas Projects: A Model for Achieving Predictability on Oil Sands’ SAGD Plants,” published by the University of Calgary. Halari, who has worked on various replicated SAGD plants and well pads, interviewed over 140 people in the field for his report in order to determine how companies can successfully replicate designs. “It comes from the CEO all the way down to the engineers and the contractors,” he says. “They need to know that this is the philosophy they are working under.”
Ken James, the CEO of Oak Point Energy, says that’s a departure from the traditional approach of oil sands companies, which tended to prioritize production volumes over operational efficiency. “Everybody talks economies of scale,” he says. “When most people hear that, they think bigger. When I think economies of scale, I think of the automotive industry, which is not bigger but makes the same thing over and over again.” His company has patented small-scale mobile SAGD facilities which can theoretically be disassembled and moved to a new location after a reservoir has been depleted.
The technology has yet to be deployed in such a way, but hypothetically it would allow producers to target new formations using existing infrastructure. The company piloted the technology with privately held Grizzly Oil Sands, but the project was deemed uneconomic and was shelved in 2014 – and it’s no wonder, given that the company had steam-to-oil ratios (SORs) over eight, a figure that’s nearly triple the industry average. James is now focusing on leasing even smaller modular plants, each with just two well pairs, so companies can cheaply predetermine their SORs before building an entire well pad or central facility, reducing risk.
Companies can also lower costs by making existing projects more efficient. This applies especially to site turnarounds, where producers have been regularly over budget in the past. Dieter Körner, a managing partner at T.A. Cook Consultants, says 80 per cent of turnarounds are at least 15 per cent over budget across most industries, and while costs for the oil sands aren’t easily comparable he expects they are among the highest. “In the oil sands you can see a lot of turnarounds not meeting their expected costs because they are poorly prepared, highly complex and not well executed,” he says.
Part of the problem is the productivity of contract workers. Körner estimates on-site contractors are only productive for 30 to 35 per cent of the time they spend at work. Another issue is scheduling. Preparation for turnarounds ideally would begin 24 or even 36 months before the start date, but often doesn’t begin until 18 or even 12 months out. “If the time is compressed, you have to make decisions under pressure and expose yourself to risk,” Körner says.
It might seem obvious that trimming just a few days off a $50-million turnaround would save a nice bundle of cash, but even changes to small pieces of equipment can make a difference. Darren Massey, a program leader at GE’s Customer Innovation Centre, says the monitoring of electronic submersible pumps, for example, can be significant. “Every two to three per cent can make a difference if you have thousands of pumps that cost millions of dollars,” he says. Companies are already monitoring pumps for basic readings like temperature and speed, but Massey and others are now working on a smarter monitoring system that would use sensors to provide more predictive information such as a single pump’s wear over time. “Eventually, you start thinking, ‘I want to know if that pump is going to fail before it actually fails,’” he says. Similar sensors could be installed in other areas of the plant such as separators, steam generators and upgraders to give operators a broader view of the plant’s overall performance. “Now you have software that is constantly running diagnostics, like where are the chokepoints in the system, what pumps are wearing fastest [and] how regularly equipment is working.” And while nobody in the patch has installed a system that fully optimizes a plant’s operations yet, due mostly to the huge volumes of data that need to be processed in order to get the necessary information, it stands to reason that it’s the next logical step.
With oil prices not expected to recover back to their early 2014 highs any time soon, producers will increasingly seek lower costs by making their operations as predictable as possible – whether by replicating the plants they build, or through better monitoring of the plants they already have. And if there’s one glimmer of hope amid slumping oil prices, Cleland says, it’s that they might have a better chance this time to get it right. “When oil’s in the 50s and 60s, they can spend a little more time planning, they can execute it better, and generally bring in more efficiencies.” In time, that could prove to be of lasting benefit for everyone.
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