The oilsands industry has been waiting for years for someone to commercialize solvent-assisted SAGD and prove its efficiency benefits. The time might be right for this to happen, but not necessarily in the way it was expected.

SAGD is currently responsible for more than 40 per cent of total oilsands production, according to the DOB’s Canadian Oilsands Navigator. Modeling and field-testing has indicated that solvent co-injection could significantly reduce steam requirements, lowering GHG emissions while providing a meaningful uplift in oil recovery as SAGD wells age.

 There’s been a shift in mindset for some producers in that the technology may be better suited for incremental deployment pad-by-pad versus in a single swoop at the central processing facility (CPF). If it works, this would be cheaper and more flexible. And it is a great idea, says Jared Wynveen, executive vice-president with McDaniel & Associates Consultants Ltd.

CPF deployment requires a significant capital expenditure, he says, and may not even be necessary for optimum results.

“Part of the issue with field-level deployment is that it’s a big undertaking, and certain parts of your reservoir may not require it. If you can deploy it on the areas where you’re getting maximum economic benefit and you can still be confident that the recycle ratios can be maintained, then that would be very appealing to many,” Wynveen says. However, “it’s all speculation at this point.”

Solvent-SAGD on the whole has yet to be proven, he adds. It’s not just the high costs; there’s also limited data, making it difficult for producers to be in the “first to be second” sweet spot for new technology implementation.

“There’s a bit of chicken and egg here,” Wynveen says. “People are running pilots, [and] they get, call it, some uplift or inconclusive results because they don’t carry out the pilot necessarily correctly. It’s, ‘we know the science is sound. The pilot was okay, but now are we going to put the money behind that?’ Unfortunately they can’t look to anybody else other than maybe a few well pairs to show with significant evidence what sort of uplift they should be expecting. We’re light on data, and there’s a big cost.”

The cost to retrofit a CPF with equipment for solvent-SAGD, primarily solvent recovery facilities, could run between $150 million to $400 million, estimates Trevor Phenix, co-founder and vice-president of business development with Hive Innovations Inc. He says a pad-level system could reduce that cost to $10 million per pad.

The bottom line is that the viability of solvents as a recovery technology will be strongly tied to the success of the related surface facilities, he says.

“The infrastructure on surface ultimately is there to satisfy the best way and the most economic way of extracting the resource.”

Who will be first?

The largest SAGD producer is taking the pad-level pathway. After years of pilot testing, Cenovus Energy Inc. announced this summer that it has shifted its approach to solvent deployment.

“We changed our minds on how to implement solvents by not going [through] the central plant,” chief technology officer Harbir Chhina told Cenovus’s Q2 analyst call (DOB, Aug. 1, 2018). “We think we can do the solvent implementation a lot faster by doing it on the pad level, and we feel we can do it a lot cheaper too.”

Cenovus received regulatory approval in May 2018 for a solvent co-injection scheme including pad-level solvent recycling at its Foster Creek SAGD project. Chhina noted, however, that there has been a schedule delay and the company does not plan to implement its pad-level approach until “probably 2020.”

Much like its predecessor, Alberta Energy Corporation, the first company with a commercial SAGD project, Cenovus has long been expected to lead the way on solvent-assisted operations. The company has demonstrated that the science is sound, Wynveen says, and he expects Cenovus will eventually get there, but it’s not necessarily going to be first.

“I don’t know if it’s Cenovus anymore, because the baseline performance from their wells is so good now. They’ve gone the route of flow control devices and better startup techniques, and the amount of uplift they’ve gotten from that is quite significant and the cost is quite low, relatively speaking. Now we’re seeing recovery factors and productivities that are basically at or better than what previous expectations for solvent uplift would have been.”

MEG Energy Corp. already has a new pad-level solvent recovery system in the field.

 The company received regulatory approval in November 2017 for expansion of its eMVAPEX solvent pilot, including a pad-level propane recycle system. Construction was completed in late August, and MEG is now in the process of converting up to seven additional well pairs onto eMVAPEX, the company said in a statement to the DOB.

While it is too early to comment on the additional rollout, MEG said “we continue to be encouraged by the SOR and propane recovery we’ve seen to-date on the three well pairs that have been previously converted to eMVAPEX.”

The economics of solvent technologies in the oilsands “largely hinges on the recycle ratio, as solvents generally trade at a premium to WTI, and you are using that to replace relatively inexpensive gas (lowering SOR). A strong recycle ratio better supports solvent recovery economics,” MEG said.

If the eMVAPEX pad-level propane recycle system is proven successful, that does not necessarily mean it is how the technology would be deployed commercially, the company added.

“For the purpose of pilot testing eMVAPEX on a small scale, it makes sense to scale our solvent recycling testing to a pad level. We continue to assess how it could be rolled out in the future.”

Solvent-SAGD timing

There’s a long history of solvent injection to augment production in non-thermal heavy oil operations, notes Clay Bilton, director, in situ with Wood plc. Thermal operators started to get involved when they saw its potential to mitigate steam-to-oil ratios rising as SAGD projects age, he says.

“Aging wells are seeing the SOR increase and solvent can assist with that. Early on in the industry when the price of oil was high and the differential wasn't as bad, there was a lot of concentration on increased production and drilling a lot of wells. Now that some of those assets are aging, they’re drilling new wells but the ratio of new wells to older wells is changing and they’re seeing the SOR increase overall in the field,” Bilton says.

“Solvent will assist with that, and of course the byproduct is also decreased natural gas burning for steam generation.”

From a project planning and timing perspective, a pad-level deployment may make better sense than a CPF-deployment. Phenix says that’s one of the benefits of the standardized design that Hive has developed for pad-level solvent recovery.

“It had to be modular and mobile so that we could target a relatively isolated period of time over the life cycle of these projects,” he says.

“Maybe your pad has a life span of 8 to 15 years; our thought on the design side was that we wanted to be sure that we could accommodate really short utilization times, a 4 to 5 year window, and then they could shift it to another pad.

1/40^th the scale

Designing surface facilities for pad-level solvent recovery is basically just about changing the location of some equipment and decreasing the need for the distribution piping to take the solvent from the CPF, Bilton says.

Hive’s goal is to isolate solvent recovery infrastructure to the well pad.

“The intent is we’re basically recovering about 90 per cent of what comes back to the wellhead,” Phenix says, adding there may be adjustments based on reservoir characteristics, solvent selection and operational philosophies.

“If you were to design this for full field, you’d basically have to design it for what the facility was sized for, whereas here there’s 40 pads maybe that feed some of those massive facilities; we’re really taking this down to 1/40 of the scale.”

Hive expects its first standardized pad-level solvent system to be in the field and near commissioning toward the end of next year, Phenix says.

 Solvent selection

Research continues into which solvent is best for SAGD implementation, and the choice will impact the requirements for surface facilities. While some producers, such as Cenovus and MEG, have been public about their preference for propane, others are looking at something heavier — Devon Canada Corporation recently started the regulatory process for a new project called Pike 3 that would incorporate diluent co-injection field-wide (DOB, Oct. 3, 2018).

“For a butane or propane you might need 60 per cent instantaneous recovery. If you can’t get that recovery, and if you’re just burning something that is arguably more valuable than the bitumen, then it’s a fairly tough economic case to make,” Wynveen says. “That’s even more so when you’re talking about diluent, where the price premium is quite significant. For more of a diluent-based solvent, if you can’t recover at least 80 per cent, then your economics don’t really stand a chance.”

According to Bilton, there may not be any need to recover diluent at all.

“You might be able to leave that in the emulsion and in the oil that you sell and not have to add as much diluent in your sales line,” he says, but adds that diluent may not be as effective as lighter solvents downhole.

“I think that the fact that Cenovus has publicly stated they’re using propane is a strong indicator of its effectiveness.”

Efficiency and GHGs

When it comes to big new projects in the future, Phenix believes the pad-level approach will have benefits despite the efficiencies that can be won through full pre-designed CPF implementation.

“I think once people start to go down this path where they have so much flexibility and optionality on a pad-to-pad basis, they may rethink the benefit that’s created by doing the CPF all up front,” he says.

Whatever the deployment approach, it’s important for solvents to become part of in situ oilsands development, Wynveen says.

“I think that by and large, irrespective of the GHGs, companies should be moving in this direction. And then when you layer on the incremental cost from GHGs, it just further reinforces the fact that this is a commercially viable next step.”