​Oilsands producers wrestle down costs through better technology and well design

Image: Joey Podlubny/JWN

Reducing operating costs has been a huge focus for the oil and gas industry in the downturn, but nowhere is that focus more intense than in the oilsands sector.

A few top players gave a taste of some of their efficiency advances in their results for the third quarter of 2016.

Mining costs have reached levels not seen in 10 years.

Suncor Energy reduced its overall oilsands operating costs to $22.15/bbl in the third quarter of 2016, an 18 per cent reduction from the prior year’s same quarter and the lowest in over a decade.

Syncrude’s cash operating costs decreased to $27.65/bbl from $41.65/bbl largely because of improved reliability combined with lower operating expenses, according to Suncor, one of Syncrude’s owners.

In situ operations are also driving down costs.

Cenovus’s overall oilsands operating costs declined nine per cent in the third quarter of 2016 versus the previous year. At its Foster Creek SAGD project, the company says operating costs declined 15 per cent to $9.63/bbl in the quarter. Non-fuel operating costs were $7.19/bbl, a 17 per cent decrease from a year earlier. At the Christina Lake SAGD project, Cenovus’s operating costs were $7.72/bbl in the quarter, a slight decline from a year earlier.

Cenovus’s overall oilsands non-fuel operating costs were $6.37/bbl in the third quarter compared with $6.99/bbl in the same period a year ago.

“We’ve spent the last two years perfecting our game for the new business reality so that we can have a robust business model in the mid-$50-WTI range,” says Drew Zieglgansberger, Cenovus’s executive vice-president of oilsands manufacturing. “This was a really big culture shift for people and our industry in order to remain competitive.”

Even since before the downturn, Cenovus has been a leader in driving down operating costs, but Zieglgansberger says most of the heavy lifting has been done since the end of 2014.

“It has been a two-year process. Through the end of the third quarter of 2016, Cenovus’s non-fuel oilsands operating costs were almost 30 per cent lower per barrel than they were for the full-year 2014,” he says.

Like every other oil and gas company, Cenovus has had to slash its capital and general and administration costs, which included reducing its workforce by about 30 per cent from the end of 2014. It also asked for discounts from its suppliers. But some of the biggest efficiencies came from looking more closely at its production facility well pads.

“We’ve redesigned these to reduce the amount of equipment needed to move the steam into the wells and then take the production from the wells back to the main plant, reducing those costs in the order of 40–50 per cent,” Zieglgansberger says.

Jared Wynveen, vice president of technical consulting firm McDaniel & Associates Consultants, drills down into some of Cenovus’s infield innovations.

“Cenovus has been leading the way on a number of wellbore design changes and start-up changes,” Wynveen says. “They focus quite a bit on steam distribution systems and dilation start-up systems, so ways to improve the initial conformance along the horizontal wellbore. With new start-up technologies—water dilation, steamed dilation—and with better steam distribution systems, they’re able to create very homogeneous steam chambers along their well bores.

“Basically you’re getting almost a pro rata increase in productivity with incremental conformance improvements. In the old world, if you had 70 per cent conformance on a 1,000-bbl/d well, that was pretty good. But if you can get your conformance up to 90 per cent, you’re essentially looking at almost a 25 per cent productivity increase.”

Fluid control devices “are a big thing in the industry right now” for ensuring even steam distribution along injector and producer wells, he notes.

“Cenovus is also looking at extended-reach horizontals. They’re really pushing the envelope on the lateral length,” Wynveen says. “If you drill a 1,200-metre lateral, versus a 750-metre or 800-metre lateral, and get good performance, you’re going to get higher productivity and lower capital costs because you’re drilling more subsurface area from a single pad. So you’re getting a double whammy of benefits.”

Unlike the gains made in reducing staff and service costs, technology-driven operating cost reductions can progress more or less indefinitely. Zieglgansberger confirms Cenovus’s technology bias in its list of initiatives to potentially drive operating costs lower: continued improvements in wellbore conformance, reducing the number of well pads required in the future (due to wider well spacing and longer wells), continued improvements in drilling and completion efficiencies (further reducing the time it takes to drill and complete wells), and redesigned well pairs and pads.

In its results for the third quarter of 2016, MEG Energy also discussed its progress in reducing its operating costs. It showed net operating costs at its Christina Lake SAGD project were $7.76/bbl compared to $9.10/bbl in the third quarter of 2015.

Non-energy operating costs (which exclude natural gas consumption) were $5.32/bbl, an 11 per cent improvement from the same period in 2015.

The company attributed these reductions to its eMSAGP program, which involves non-condensable gas co-injection (such as methane), infill well drilling, new well pairs and facility debottlenecking. MEG noted that its net operating cost reductions were also helped by a decrease in the use and cost of natural gas as a source fuel for the company’s SAGD facilities.

“Co-injecting trace amounts of non-compensable gas helps maintain pressure support in the reservoir for longer but also frees up steam that we can redeploy into additional wells. That increases your production, spreads your steam over more wells and reduces your cost per well, while decreasing our [greenhouse gas] emissions intensity,” says Davis Sheremata, MEG’s senior external communications adviser.

About 55 per cent of MEG’s $590-million 2017 capital budget will be directed to eMSAGP growth. The resulting full production increase is expected in early 2019, with 80 per cent of the associated $400-million capital spend to come this year.

Production improvement volumes from the successful implementation of eMSAGP at Christina Lake starting this year is expected to provide a 20,000-bbl/d production increase.

“To date, we have applied eMSAGP to about 25 per cent of our production,” Bill McCaffrey, MEG’s chief executive officer and president, said in a statement in January. “This phase of eMSAGP growth offers some of the highest economic returns available to the company today…. When fully implemented, this growth is anticipated to bring MEG’s total production to approximately 100,000 bbls/d, significantly improving the sustainability of the business by driving cash costs down by as much as $4–$5/bbl."

Another technology that MEG will leverage to lower its operating costs is eMVAPEX. About $70 million of MEG’s 2017 capital budget is being allocated for an eMVAPEX pilot.

“MEG is another company that is very aggressive with technology implementation as well,” Wynveen says. “Their eMSAGP program has been very successful. Their work on eMVAPEX—using solvents, whether it’s butane or propane or C-5 plus-based solvents—while there is probably some pretty big potential there, it’s unfortunately just a little bit earlier in the game.”

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