While investment in new Alberta oilsands megaprojects has stalled, heavy oil activity in Saskatchewan is proceeding apace, albeit on a much smaller scale.

Saskatchewan’s total thermal oil production, for example, is roughly 100,000 bbls a day. In the Alberta oilsands, a single project can be that size.

But size increases capital risk. And at a time of oil price uncertainty and political/regulatory uncertainty, megaprojects are riskier because of long lead times and multibillion-dollar price tags.

In both Alberta and Saskatchewan, well licences, rig releases and land sales more than doubled in the first half of this year compared to 2016.

But where Alberta hasn’t rebounded is on capital spending plans, which remains far below 2014 levels.

In Saskatchewan, 2017 capital spending is expected to rebound to roughly the amount invested in 2014 before the benchmark West Texas Intermediate (WTI) crude began its slide from over US$100 a bbl to under $50.

Industry investment in Saskatchewan is expected to total $6.1 billion this year, compared with $3.5 billion in 2016, $4.2 billion in 2015 and $6.7 billion in 2014, estimates the Canadian Association of Petroleum Producers (CAPP).

Meanwhile, Alberta capex is expected to total $31.1 billion this year, compared with $27 billion in 2016, $39.9 billion in 2015, and $60.6 billion in 2014.

Alberta disadvantage

CAPP cites several reasons why it expects only about half as much money to be invested in the Alberta oil and gas industry this year than during 2014.

These include lower project spending following the oil price drop, lack of timely pipeline and LNG developments to allow Canadian oil and gas to reach world markets and “mounting costs and barriers to growth due to changes in provincial and federal government policies and regulations,” said Chelsie Klassen, a CAPP spokeswoman.

Alberta oilsands capex is expected to total $15 billion in 2017, less than half the $34 billion spent in 2014, CAPP said last month (DOB, June 13, 2017).

Saskatchewan’s shift to thermal

In Saskatchewan, meanwhile, thermal technologies commonly associated with the Alberta oilsands are changing that province’s production profile.

As recently as 10 years ago, only about 15 per cent of Saskatchewan’s heavy oil output came from thermal (steam-assisted) projects and 85 per cent came from CHOPS (cold heavy oil production with sand).

And until 2016, Saskatchewan’s overall heavy oil output had been falling for about 10 years as output from CHOPS, or conventional heavy oil wells, declined.

In recent years that mix has changed dramatically. In 2016—for the first time in about a decade—Saskatchewan’s overall heavy oil production rose, thanks to the surge in thermal output.

Thermal projects now account for about 60 per cent of the oil production from the province’s Lloydminster heavy oil belt, said Ed Dancsok, an assistant deputy minister with the Saskatchewan Ministry of the Economy.

While Saskatchewan’s light and medium oil output fell in 2016—one of the oilpatch’s worst years in recent memory—the province’s heavy oil production actually rose compared to 2015, thanks to new steam-assisted projects coming onstream, Dancsok said.

Saskatchewan’s 2016 surge in thermal output came from five projects that either came onstream or ramped up to full production in 2016, Dancsok said. Three of those are owned by Husky Energy Inc. while BlackPearl Resources Inc. and Serafina Energy Ltd. have one each.

Overall output down

But while the surge in thermal recovery was enough to lift Saskatchewan’s heavy oil output last year, the province’s overall oil production fell due to the drop in light oil drilling.

As oil prices fell to less than half their 2014 levels, drilling declined as producers slashed capital spending. This had the biggest impact on light tight oil production because of relatively high initial decline rates.

Dancsok estimated overall Saskatchewan oil output (heavy, medium and light combined) fell by about five per cent in each of the past two years. However, he noted the pace of drilling in Saskatchewan this year is double last year’s tally, so that decline may eventually be reversed.

Increased light oil weighting

Even with the drop in light oil output in 2015 and 2016, overall Saskatchewan oil production has become lighter over the past decade or so as capital poured into unconventional plays such as the Bakken, the Viking and the Torquay.

However, the future trend for light tight oil production is unclear. Bakken production peaked at about 70,000 bbls a day before dipping below 40,000 bbls a day in 2016, Dancsok said.

“But we’ve already started to see a bit of a rise in the spring of 2017. So it’s back up to about 40,000 barrels a day,” he said. “So hopefully we’ve seen the bottom as companies start drilling again.”

Given how technology improvements led to a rebirth of the Bakken and the Viking plays in recent years, Dancsok said it’s too soon to predict what the long-term production trends will be in those plays. “The next resurgence of production increases, I think, [will be] the application of waterflood and secondary recovery in those reservoirs as they start to deplete, and hopefully we see a rebound again.”

Husky thermal leader

The leader in the Saskatchewan thermal oil business is Husky with about 80,000 bbls a day of thermal production from nine steam-assisted projects in the Lloydminster area.

And the company plans to make that business much bigger.

The tenth project, Rush Lake 2, is already under construction and is scheduled to reach nameplate capacity of 10,000 bbls a day in 2019.

Three more Lloyd thermal projects, with combined design capacity of 30,000 bbls a day, are slated to come onstream in 2020. Those projects are Dee Valley, Spruce Lake North and Spruce Lake Central.

Those four projects will boost Husky’s Saskatchewan thermal capacity to about 120,000 bbls a day around 2020, up from about 80,000 bbls a day now.

Beyond the nine projects now onstream and four in development, Husky has 14 more Lloydminster area thermal projects in the wings. In 2021 and beyond, the company plans to bring onstream two small thermal projects per year.

Saskatchewan advantage

So why is Husky so enthusiastic about 10,000-bbl-a-day Saskatchewan thermal projects?

Andrew Dahlin, Husky's senior vice-president for heavy oil, lists several factors that help the economics.

The project build time for the 10,000-bbl-a-day projects is very short—about two years from shovel to first oil. (While those projects have a nameplate capacity of 10,000 bbls a day, they typically produce at higher rates.)

The projects are sanctioned on the assumption that at least 50 per cent of the oil in place will be recovered, but some pads that have been on steam for many years have achieved recovery factors of up to 70 per cent.

“Sustaining capital requirements are in the range of $5 to $7 per barrel,” Dahlin told the company’s recent investor day conference. “The [per-bbl] op costs for newer builds are in the neighbourhood of $8 to $9 per barrel with steam/oil ratios averaging 2.2.”

Dahlin also emphasized Husky’s Lloydminster heavy oil is better quality than Fort McMurray area bitumen. “Less heat is required and it commands a higher realized price. This combination of lower cost and higher realized pricing delivers higher netbacks.”

John Festival, president of BlackPearl Resources Inc., also cited several advantages of doing thermal oil projects in Saskatchewan.

BlackPearl’s Lloydminster area Onion Lake project ramped up to beyond its design capacity of 6,000 bbls a day in 2016. Last winter, BlackPearl began construction of the 6,000-bbl-a-day second phase of the Onion Lake thermal project. The company recently completed the final leg of the financing needed to finish construction.

“We’re near infrastructure, so we don’t have to build pipelines and roads. That cuts down on our costs,” Festival told the Bulletin.

He said the heavy oil BlackPearl produces at Onion Lake is 12 degrees API gravity versus as low as seven or eight API on some oilsands projects. “So we get a higher price for our oil—anywhere from $3 to $10 [a bbl] more.”

Also, because of more favourable oil viscosity and reservoir permeability than in the oilsands, a small percentage of Lloydminster heavy oil can be produced cold, so less heat is needed to increase recovery.

“And the other thing is our capital costs are less because we have less requirements to recycle the water,” Festival said. “So just all around, it’s just a more economic business—putting steam in the ground in Saskatchewan.”

He said the other two advantages of doing thermal oil projects in Saskatchewan versus Alberta are that the regulatory process is much, much shorter and so far there’s no carbon tax.

“And on the regulatory side, it’s even better,” he said, noting that it only takes about four months to get a new project approved in Saskatchewan.

In the Alberta oilsands, it took about four years to get provincial approval, albeit for a much bigger project then Onion Lake.

In 2012, BlackPearl filed a commercial development application for its 80,000-bbl-a-day Blackrod thermal project in northern Alberta. In 2016 the project finally received Alberta cabinet approval. In those four years, WTI fell from about US$100 a bbl to below US$50 a bbl.

BlackPearl hasn’t decided when to start the first commercial phase at Blackrod. But for now, the Alberta thermal project has taken a back seat to the Onion Lake thermal development.

“So all these things all add up to a very favourable environment to operate in in Saskatchewan,” Festival said. The Saskatchewan thermal projects, he said, are economic at a WTI price of about $40 a bbl. “That means we get a return on our capital at that price or even lower. So it really is excellent economics for us.”

Onion Lake Phase 2 will use the same modified SAGD process that was proven up on Phase 1.

Instead of using conventional SAGD well pairs of parallel horizontal steam injectors and oil producers, BlackPearl opted for vertical or slant steam injectors and horizontal oil producers (DOB, Sept. 12, 2016). Many of the steam injectors are former primary production wells, so fewer wells needed to be drilled for thermal recovery.

BlackPearl hopes to start steam injection on Phase 2 by mid-2018 and to ramp up to design capacity of 6,000 bbls a day by mid-2019, bringing total Onion Lake output to 12,000 bbls a day.

Cold heavy versus thermal

Husky and BlackPearl are examples of how Saskatchewan heavy oil investment is shifting to thermal from CHOPS.

Thermal production now accounts for more than 60 per cent of BlackPearl’s total oil output, and the company’s long-term strategy is to transition from a conventional heavy oil producer to a major thermal operator.

Husky stopped drilling CHOPS wells because it found thermal oil economics are much better.

Thermal recovery factors are much higher, finding and development costs are lower, and the logistics are more compact because fewer wells are needed and there’s no need to truck huge volumes of produced sand.

“So operating costs per barrel on the thermal projects are less than half of what they are on the CHOPS wells,” Husky CEO Rob Peabody told the Bulletin after the company’s 2017 annual meeting.

However, Saskatchewan still has significant cold heavy oil production. Husky has about 40,000 bbls a day of non-thermal heavy oil production, the lion’s share of which is from CHOPS wells in the Lloydminster area.

“While we will continue to invest in some CHOPS production, our primary focus going forward will be on thermal developments,” said Mel Duvall, a company spokesman.

Canadian Natural Resources Limited has more than 20,000 bbls a day of oil production in Saskatchewan, but that includes light and medium as well as heavy, Julie Woo, a spokeswoman, said in an email.

In areas that meet its return criteria, Canadian Natural continues to invest in primary heavy oil and has budgeted for up to 25 wells in Saskatchewan this year, Woo said. In Saskatchewan CNRL’s primary heavy oil operations are in the Lloydminster area.

Also in Saskatchewan, CNRL has thermal oil projects at Senlac and Tangleflags, and a polymer flood at Lone Rock.

Betting on cold heavy oil

While thermal is getting more attention, cold production in Saskatchewan can also offer compelling economics, according Cona Resources Ltd.

Cona is the renamed Northern Blizzard Resources Inc., which paid nearly $1 billion for Nexen Inc.’s conventional heavy oil assets at the start of this decade (DOB, May 20, 2010).

When the deal was announced seven years ago, Nexen said the properties were producing about 16,100 boe a day from 750 net wells. For the first quarter of this year Cona, which is still focused on Saskatchewan, reported output of 17,201 boe a day (16,974 bbls a day of heavy oil and 1.36 mmcf a day of natural gas). However, Cona has sold some assets and, like other producers, cut back on drilling after oil prices crashed.

The company’s operations, infrastructure and core areas are in southwest Saskatchewan.

These include two types of pools—conventional higher-viscosity Lloydminster Mannville heavy oil pools and lower-viscosity heavy oil in the Kerrobert Bakken formation. The company says its lower-viscosity Bakken pools typically exhibit in-situ viscosities of less than 1,000 centipoise while the higher-viscosity Mannville oil pools have dead oil viscosities in the 4,000-36,000-centipoise range.

Three fields—Cactus Lake, Winter and Court—supply about three-quarters of Cona’s production with Cactus contributing about half of the total.

So what’s the appeal? Low decline rates, for one thing.

“Decline rates really are one of the absolute keys to sustainable production,” says Jim Artindale, until recently Cona’s president and chief operating officer. “It’s very difficult to sustain your production if you’re facing a headwind of a very significant decline rate.”

Cona’s decline rate has gone from 22 per cent—one of the best in the industry—all the way down to about 12 per cent, Artindale told the company’s recent annual meeting.

A 12 per cent decline rate means the amount of sustaining capital needed to replace production is low, therefore free cash flow is high.

“What we’re seeing here is the impact of a couple of our major fields that have had dramatic response to EOR [enhanced oil recovery] projects,” Artindale said. “And in fact, some of the fields are on a base incline. If we didn’t drill any wells, they’ll still incline over the short term.”

He displayed a chart of Cactus production, saying output grew by an average of 18 per cent a year since 2011. And that’s despite a big drop in drilling during the oil price downturn.

So why more production amid less drilling? At Cactus, Cona operates what Artindale believes may be North America’s biggest vertical polymer flood. The company began the polymer flood in 2012 and started to see the response in 2014. Sixty-five per cent of the Cactus field is now under polymer flood.

As a result, “the wells we drilled five years ago—their production [is] increasing, not decreasing,” he said.

Another attraction is low operating costs. Artindale said Court and Winter are still profitable at a WTI price of US$40 a bbl and Cactus, which generates about half of Cona’s production, is profitable at US$30.

“If you go back to 2016 [when] the average price was $42 a barrel ... Cactus made approximately $70 million of cash flow,” he said. “That field grew by 11 per cent that year. We invested $25 million and it grew by 11 per cent in one of the worst years we’ve had.”

Cona has drilled more than 300 wells at Cactus and has about 300 left to drill—but the field’s production growth “actually has nothing to do with the number of wells drilled,” Artindale said, referring to the polymer flood response. “This is, in my opinion, one of the top oil assets in Western Canada.”

Low capital costs are also part of the appeal of cold heavy oil. Unlike unconventional plays, there’s no hydraulic fracturing.

To drill, complete and tie in one of Cona’s cold heavy oil wells, which will produce “for decades,” costs just over $400,000, he said. “Compare that to our Viking play.... We just sold our Viking asset. They cost about $1 million—$900,000. They’ll produce 40,000 barrels of oil in their lifetime, maybe 50,000 if you get a good well.”

Whereas a Cactus well will produce 140,000 bbls over its life at less than half the drilling, completion and tie-in cost, Artindale said.

Raising cold recovery rates

In his final presentation to shareholders, Artindale said only nine per cent of the oil in place at Cactus would be recovered through primary production.

When Cona (then called Northern Blizzard) bought the field it was under waterflood at 40-acre spacing. The recovery factor for the 40-acre waterflood was estimated at 18 per cent.

Cona began downspacing to 10 acres and optimized the waterflood. Just the waterflood on 10-acre spacing would have recovered about 28 per cent of the oil in place, Artindale said.

With the 2012 kickoff of the polymer flood on 10-acre spacing, “we’re very comfortable we’re going to get in the high 30s, maybe even approaching 40 per cent recovery,” he said.

That’s in contrast with CHOPS production which often leaves 85-90 per cent of the oil in the reservoir, according to a Saskatchewan Research Council (SRC) brochure.

CO₂-based heavy oil recovery

Cona and the SRC aren’t the only ones working to increase recovery rates in cold heavy oil in Saskatchewan.

Husky’s shifting of capital to thermal from CHOPS coincides with a growing global focus on greenhouse gas emissions. As the company’s Saskatchewan and Alberta thermal oil production continues to grow, so do carbon dioxide emissions.

So the company has been looking for an economic way to cut emissions and simultaneously boost recovery rates for cold heavy oil. A few years ago, Husky began piloting CO₂ capture technologies at its Lloydminster thermal operations in Saskatchewan. The company says the most promising of these may cut the cost of carbon capture by half.

“At the same time, we’ve been developing CO₂ injection technology for the past 10 years, so in the field pilot this has actually increased our oil recovery in our CHOPS wells from about eight per cent to about 20 per cent,” Dahlin told the company’s investor day conference.

He added: “We’re still in the early stages, but this is actually a unique opportunity that marries our legacy CHOPS production with our growing Lloyd thermal program, and it can really benefit both. So the big prize here is leveraging our emissions from the steam plants as a CO₂ source to increase the oil recovery from the vast field area currently not justifying thermal application.”

At the company’s recent second-quarter earnings conference call, Rob Symonds, Husky’s chief operating officer, said a planned 30-tonne-a-day CO₂ capture plant for its Pikes Peak South thermal oil plant is now in the design stage.

Duvall, the media spokesman, said Husky currently captures about 250 tonnes of CO₂ a day at its Lloydminster ethanol plant. It is also capturing 30 tonnes a day at Pikes Peak South from the initial pilot project at that facility, which uses HTC CO₂ Systems Corp.’s technology and has been operating since September 2015.

HTC CO₂ Systems is a subsidiary of Regina-based HTC Purenergy Inc.

Meanwhile, a demonstration project using Vancouver-based Inventys Inc. technology has been capturing a half tonne a day at Pikes Peak South since January.

“Based on that initial testing, we are moving ahead with a 30-tonnes-per-day pilot project, which we expect to be commissioned in Q4 2018,” Duvall said in an email. “We believe this technology has the potential to reduce the cost of carbon capture, compared to existing technologies, and could turn Lloyd thermal production into a lower carbon source of energy.”

Duvall said Husky continues to evaluate additional technologies. The company hasn’t disclosed the cost of the planned CO₂ capture facility nor an estimate of the expected increase in CO₂-based EOR.

Symonds said Husky has already produced about three million bbls of heavy oil through CO₂ injection and is currently producing about 2,000 bbls a day using the technology.

Husky has 2.2 million net acres of land in the Lloydminster heavy oil belt, so the prize could be huge if it can boost recovery from parts of the field where thermal recovery is uneconomic. Boosting recovery would also be a huge win for Saskatchewan by enabling production of some of the billions of bbls of heavy oil that can’t currently be recovered by conventional methods.