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As an oil producer, Saskatchewan seems to have it all. The Bakken light oil trend is a play of frenzied activity. So is Cenovus Energy’s carbon injection enhanced oil recovery operation at Weyburn (the world’s largest carbon capture and storage facility). But the province’s meat and potatoes—conventional heavy-crude production in the Lloydminster and Kindersley areas—are hidden behind these high-profile developments. Saskatchewan’s first 2010 land sale tells the story clearly, if one digs deeply into the numbers.

Out of nearly $40 million in bonus bids, about $26 million went for land in the Weyburn-Estevan region, a reflection of the importance of Bakken and Weyburn. Dig a bit deeper into the numbers, though, and one finds that the highest price paid for a single parcel was $2.1 million, for a 1,552-hectare exploration licence in the Lloydminster area. In another sale, one operator, Baytex Energy, paid $6,512 per hectare for a 16-hectare parcel near Maidstone, also in the Lloydminster area—by far the highest bid per hectare.

Combined, the two heavy oil producing regions in Saskatchewan brought in nearly $10 million in bids in the first land sale of 2010—not bad for the Cinderella sister of light oil. The message is clear. The resource has been on production since 1946, but despite its longevity is an increasingly valuable asset.

This applies to conventional heavy oil in Alberta as much as it does to production in Saskatchewan. In today’s market, the commodity is sizzling, and the explanation lies in increased access to North American markets and declining imports of heavy Mexican and Venezuelan crudes into the United States, where refineries have been increasing their ability to process heavier oils. The result is record light-heavy differentials that have heavy oil producers smiling in the expectation that they are here to stay for some time.

Riding the high life in a tight differential spread

Three years ago, producers had to contend with 42 per cent differentials, but since then the spread has steadily narrowed, averaging 28 per cent in 2008, about 17 per cent in 2009, and 13 per cent in January of this year, says Kevin Gibson, president and chief executive officer of Palliser Oil & Gas, which is involved in about five different heavy oil areas in the Greater Lloydminster area. “Heavy oil is almost priced the same as light oil now.”

In January, Flint Hills/Lloyd Blend gained more than $7 per barrel to an average of $72.30 per barrel with a differential of $6.71 per barrel, while another heavy benchmark, Bow River crude, averaged $73.30 per barrel with a differential of $6.40 per barrel.

In a report last year, analysts at Peters & Co. concluded that at US$69 per barrel, Lloydminster vertical wells were the most economic play in the Western Canadian Sedimentary Basin, with a 112 per cent rate of return on finding and development (F&D) costs.

For Alberta and Saskatchewan, the current market for conventional heavy oil is a bit like a winery selling this year’s plonk for 13 per cent less than a vintage wine. Like plonk compared to fine wine, heavy oil is intrinsically less valuable than Edmonton Par, the Canadian standard for light oil. In most refineries, after all, heavy feedstock results in less high-value-added gasoline and more low-value-added asphalt.

But the big U.S. refining complexes are changing that. “It’s a matter of adding vessels to the refinery,” says Steven Paget, vice-president of energy infrastructure at FirstEnergy Capital. “Those longer-chain hydrocarbons need more work to break up, but new pipelines from Canada are accessing the refineries at Wood River [Illinois] and Cushing [Oklahoma].” Those refining complexes have the capacity to break heavy oil into lighter feedstock. “Therefore, the differential becomes minimal or close to equivalent to actual operating cost.”

The good news continues in that the two heavy oil provinces have a lot of plonk left to sell. According to the Canadian Association of Petroleum Producers (CAPP), Alberta and Saskatchewan have more than a billion barrels of established reserves left to produce (see chart on p.36). More importantly, each has estimated heavy oil in place many times the volume of reserves.

CAPP estimates that initial volumes of heavy oil in place (including both conventional and non-conventional heavy) were about 15 billion barrels in Alberta, and 20 billion barrels in Saskatchewan. Established reserves will continue to grow as new in-place volumes will continue to be found.

Heavy oil activity on—make that in—the ground: new drilling and old well reactivation

The Saskatchewan government is expecting a 10 to 15 per cent increase in wells drilled in the province this year, says Ed Dancsok, assistant deputy minister in the petroleum and natural gas branch of the province’s Energy and Resources Department.

“It’s a healthy increase but I certainly wouldn’t be surprised if I saw more than that.”

Last year, operators drilled 591 conventional heavy oil wells, down from 909 in 2008. As of February 26, this year operators had drilled 95 oil wells in the Lloydminster area, up from 54 in the same period in 2009. Another 36 oil wells were drilled in the Kindersley area, compared to none in the first two months of last year. Although the area has heavy oil deposits, it also includes some lighter oil.

As prices improve and the differential remains narrow, some oilfield services companies are beginning to see gradual signs of improvement after a rough 2009, although they aren’t yet prepared to describe it as a stampede back to heavy oil.

“Some of the smaller producers are starting to become more active,” says Richard Leyes, president of Wizard Well Servicing in Lloydminster.

Steve Sych, a partner in Source Energy Tool Services, which has offices in several Alberta and Saskatchewan locations including Lloydminster and Bonnyville, has noticed a gradual pickup in business beginning late last year among some of the larger heavy oil players after a year or two of lower activity. In his company’s case, its ability to diversify into southeastern Saskatchewan’s light oil offset the reduced heavy oil activity.

Heavy oil is not for every company, emphasize those involved in it. Primarily because of its high sand-and-water content, it is quite different from light oil.

“Basically, you can’t be a company that chases gas and then jump into heavy oil,” says Palliser’s Gibson. “You need guys that understand the heavy oil region from a geological perspective, and you also need good operational people like we’ve got. Without that then you are not going to be very successful if you are chasing heavy oil.”

“You have to understand the vagaries of heavy oil to love it,” adds Rich McKenzie, vice-president of engineering of Avalon Exploration, a small private Calgary company that operates mainly in Saskatchewan. “A lot of people don’t and that’s why I end up buying [assets] off people who don’t.”

Avalon has been the only small operator that has been drilling consistently through the recession, he notes. The company plans to drill 50 wells over the next 12 months, but that number likely will rise if the differential and price remain at the current level.

For companies such as Avalon that are up to the challenge, heavy oil can be extremely profitable with its low drilling and recompletion costs, along with low F&D costs.

“What’s attractive to us is large oil in place,” says Tom Greschner, president and chief executive officer of heavy oil producer Emerge Oil and Gas. “There are millions and millions of barrels of oil in place in that Lloydminster area.”

This year, the company plans to drill its heavy oil wells at a cost per well of about $240,000 all-in to drill, complete, and equip. With initial average production of 50 barrels per day, he says the wells pay out in eight to nine months.

“Our F&D costs on new wells alone are running in the $6- to $7-per-barrel range.”

The company also plans to reactivate and recomplete another 110 wells that have been shut in because they were uneconomic with higher differentials.

“It is very cheap to bring a well back on, just a service rig with no drilling involved,” says Greschner. An average workover will cost $30,000 to $50,000, as in most cases the equipment is still in the well, although costs could climb to as much as $140,000 to equip a well.

“A lot of times with heavy oil the fluid moves around so much you will go back and there will be fluid production again.”

Production from recompleted wells can average 20 to 30 barrels per day. Palliser also has several reactivation opportunities in its inventory, and current plans provide for four wells to be re-energized this year in addition to 13 newly drilled wells, mainly in Saskatchewan.

“It’s a huge resource that’s out there, and being able to go in to an old field and extract an incremental few-per cent recovery can be millions of barrels recoverable of oil,” says Allan Carswell, Palliser’s vicepresident of exploration. “There’s still a big, big prize to be had there because of the relatively historical small recovery rates of about 10 per cent.”

Production techniques can play an important role in recovery rates, according to Avalon’s McKenzie, who attributes improved rates in recent years to the introduction of the progressing cavity pump.

“There’s still a few pumpjacks scattered around east of the border, but they are fewer and farther between than they ever were,” he says. “Some of the wells we restarted had pumpjacks, and I lick my lips when I see them because I am so excited; I know just by mechanical means [that I can improve recovery factors].”

Winnipeg-based Nordic Oil & Gas, which has 15 wells in the Lloydminster area, including nine on production, is also looking to a new technology to increase production rates.

The company has hired Calgary-based RadCan Energy Services to apply its radial drilling method using modified coiled-tubing technology to enhance production. “We think that this is something that is going to greatly enhance production out there,” says Donald Benson, Nordic president and chief executive officer. Production from existing wells is 10 to 20 barrels per day, with new wells producing about 25 barrels per day. “If we can get those types of increases [up to a 200 per cent increase] we are really talking about something substantial,” he says. “If the procedure [which will cost $52,000 to $80,000 per job] does what it says it will do, it will be economic.”

But it isn’t only smaller companies that find heavy oil attractive. Longtime players such as Baytex Energy Trust, Canadian Natural Resources, and Husky Energy are still active in the heavy oil belt.

“Heavy oil is still the biggest share of our production [60 per cent] and still our main business and it is very attractive,” says Tony Marino, president and chief executive officer of Baytex. We have good infrastructure in the heavy oil areas that we produce in, we think that we’ve got pretty good expertise, we have been helped by the heavier oil [differentials].”

This year, Baytex plans to drill roughly 100 wells of various types including verticals, horizontals, and some waterfloods. Devon Canada has budgeted $82 million this year in the Lloydminster area to drill 140 wells, to roughly maintain current production levels of about 41,000 barrels of oil equivalent per day.

The looming question: how long will flourishing heavy oil economics continue?

Conventional heavy oil is an appealingly profitable resource right now because differentials are narrow. But, especially in a market of declining production, the question of how long this dynamic will remain is critical.

According to AJM Petroleum Consultants vice-president Ralph Glass, the basic reason differentials are so low “is an increased demand for the heavier crude oils from U.S. refineries. Over the last few years there has been a movement by U.S. refineries to enhance their ability to handle the heavier crudes. With the downturn in U.S. demand, OPEC cut their [heavy] volumes. As a consequence, the U.S. refineries found themselves short of heavier crudes to process, and are now paying a premium for Canadian heavier crudes to reduce the shortfall in their systems.”

Glass suggests that the demand for heavy oil to fill for new pipelines to the United States—TransCanada’s Keystone pipeline into Patoka, Illinois and Enbridge’s Alberta Clipper line to Superior, Wisconsin—may narrow the differential even more in the short term.

FirstEnergy’s Paget says, “The reason the differential has gone down is that we have more transportation infrastructure out of western Canada…. This allows nearly 90,000 barrels per day of crude to access the Gulf Coast refining complex.”

He says that the need to fill new lines will increase demand over the short term (narrowing the differential), but the more important factor is that those new pipelines will provide increased access to markets, making conventional heavy oil more competitive in the United States. “The narrow margin is likely to continue.”

Glass takes a more cautious view. In 2011 and 2012, he says, the industry will experience “widening on implied concerns of heavy OPEC production coming online and increased Canadian heavy production.”

Source: June Warren - Nickle's Energy Group

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