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Featured Articles
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Sep 2007
| Source: Oilweek Magazine
| | | Slow Flow
| | | With conventional heavy oil activity running strong all across the region,
| | | Paul Stastny
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| Northeast Alberta has become synonymous with oilsands. And the oilsands has become synonymous with surface mining and steam assisted gravity drainage. But the petroleum bearing formations of central and northeastern Alberta are a lot more diverse than people think.
Just below the Athabasca oilsands deposits, the Lloydminster heavy oil fields have been pumping crude since the 1920s. At Cold Lake, Imperial Oil has been huffing and puffing heavy oil/bitumen since the 1960s. Further north, the Pelican Lake field in the Wabasca region of Alberta is, by all accounts, an oilsands play, but it shares characteristics common to conventional heavy oil. And throughout most of northeast Alberta, there are significant shallow natural gas pools in the Mannville sands and Devonian Wabamun, Grossmont, and Nisku carbonates.
"In northeast Alberta, the low-hanging fruit was the gas," says Bill MacFarlane, president of the Canadian Heavy Oil Association. "It wasn´t until much later, after much of the gas was produced, that people realized it was likely hydraulically connected to the oil."
So the challenge becomes, MacFarlane says, to recover the bitumen among depleted gas zones that act as "thief zones." When steam is injected into the ground in a SAGD or cyclical steam stimulation operation, the ideal situation is to recover most of the steam along with the bitumen. Steam losses within the formation drive down efficiencies. So more make-up water is needed along with more fresh water, and more energy needs to be put into the equation to make steam-and the running of artificial lift under these conditions becomes more technologically challenging.
"Heavy oil" or "bitumen?"
There has always been a grey area between heavy oil and bit-umen-and the various competing definitions haven´t helped.
A common definition of heavy oil is crude with an API gravity of below 22 degrees while anything below 10 degrees API is generally referred to as bitumen. Oilsands is understood as bitumen soaked sands.
But another variation on the API grading scheme adds viscosity. Dr. George Stosur, a former U.S. Department of Energy official, advocated the following classification at in situ conditions:
• Heavy crude: 10 to 20 degrees API, viscosity between 100 and 10,000 centipoise
• Extra-heavy crude: less than 10 degrees API, viscosity between 100 and 10,000 cP
• Bitumen: less than 10 degrees API, viscosity of more than 10,000 cP.
A more empirical approach discussed in a report titled CHOPS: Cold Heavy Oil Production with Sand in the Canadian Heavy Oil Industry, prepared by Maurice Dusseault for the Alberta Department of Energy in 2002, is "produceability."
Heavy oil becomes oilsands if it is essentially an immobile fluid under existing reservoir conditions and requires thermal or other special stimulation techniques to be produced economically.
The problem with this definition is that certain heavy oil/bitumen deposits have a degree of mobility under naturally existing conditions and can flow to wells. A low-cost operator may consider this production rate feasible, whereas an integrated oil company may not.
And then there are regulatory definitions. Alberta Energy and Utilities Board classifications for royalty and tax purposes are based on a geographical line, the southern boundary to Township 53. Dusseault writes: "North of this line, exclusive of the surface mining area in the Athabasca Deposit, the EUB classifies all deposits as oil sands, and the royalty regimes are determined by this classification. Primary oil production…is referred to as ‘primary bitumen´ production north of Township 53, but south of this Township, such production is called ‘primary heavy oil´ production, even though the technologies may be identical, the strata contiguous, and the reservoir and oil properties completely similar."
Finally, and as might be expected, the National Energy Board in its studies uses yet another classification system. Heavy oil is crude above 12 degrees API gravity or less than 10,000 cP viscosity. "Conventional heavy oil" describes heavy oil that can flow naturally into a well under primary production conditions, which is analogous to the EUB term "primary heavy oil."
Pelican Lake
Call it what you will, but the oilfields at Pelican Lake have some flow to them. "Because it is mobile oil, it´s more of a conventional oil project," Allan Greeves, Pelican team leader for EnCana, told Oilsands Review in a recent interview.
"We´re not spending a lot of capital compared to some of the other big resource plays, but when you look at production, it´s very significant to the company. It´s a big field. It´s quite staggering really."
The viscosity of the hydrocarbon in this play even makes it amenable to waterflood. This enhanced recovery technique is common in conventional oil and gas production, but not so in oilsands.
Beyond waterflood, both EnCana and Canadian Natural Resources Limited, the field´s major operators, are going to polymer flooding to further improve recovery rates. Polymers cause water molecules to stick together to form longer molecules that can make a better sweep of the reservoir.
In 2006, EnCana converted 26 wells to polymer injection and 36 wells to water injection, increasing production by five per cent. Production was 23,563 barrels per day from its Pelican project in the same year.
In 2007, EnCana expects to complete a central battery expansion in the area and increase capacity to 40,000 barrels per day. EnCana´s EOR techniques are expected to yield an additional 12 per cent from this resource play.
Lloydminster
The top heavy-oil producers in the Lloydminster area are Husky Energy Inc., with approximately 105,600 barrels a day in 2006, followed closely by CNRL, which produced about 96,000 barrels a day. Nexen pumped 26,900 barrels a day, Devon Energy Corporation averaged about 21,400 barrels a day and Baytex Energy Trust contributed 21,265 barrels a day.
In 2007, the biggest heavy oil gains are expected from Devon. It says it is ramping up production to about 33,000 barrels per day, a 25 per cent jump from 2006. It expects to do this by drilling almost 400 wells, which is about the same as in 2006.
Enhanced recovery methods are key to improving recoveries, but EOR in heavy oil reservoirs typically yield lower recovery factors than conventional oil reservoirs. This opens the door for new technology.
Nexen, which has approximately 52 per cent of its Canadian conventional production in heavy oil, is currently working on three Saskatchewan-based EOR pilot projects.
Two of these involve VAPEX (vapour extraction) technology, in which gases such as propane and butane are injected into the reservoir to act as a solvent to thin the heavy oil and allow it to be pumped to the surface. The third uses chemical flooding. The oil is mobilized by injecting water laced with a chemical designed to change the chemistry of the reservoir.
"With VAPEX, we can potentially see the recovery factor increase by 10 to 30 per cent," says Alex Solberg, Nexen´s general manager for heavy oil exploitation and development in Canada.
Imperial Oil
One company in particular that has led the way in extraction technology is Imperial Oil. When company spokesman Pius Rolheiser says technology is the key to success at Cold Lake, he speaks from the context of a company history that spans decades of research and development.
Not only did Imperial Oil pilot and patent cyclic steam stimulation-a thermal recovery process that involves injecting steam into the ground at high pressure-but it also piloted and patented the now widely used SAGD process.
"People sometimes ask why we don´t use SAGD, assuming that as a newer technology, it´s therefore more effective," says Rolheiser.
But extraction methods obviously need to be tailored to specific formations, and cyclic steam stimulation works best at Cold Lake, a formation characterized by good horizontal permeability. SAGD works better in deposits with good vertical permeability, such as the Athabasca oilsands deposits near Fort McMurray.
Imperial Oil is Canada´s largest oil producer and arguably the biggest "heavy oil" producer in the world. Its current production in the Cold lake area is about 165,000 barrels per day of raw bitumen.
Rolheiser says these volumes are very close to record production levels. "We time our production cycles so that we get our higher production cycles during the summer months, which is generally when the bitumen markets are strongest."
Imperial Oil´s Cold Lake facilities have seen numerous expansions over the last two decades. In 2004, it received regulatory approval for expansion over three new commercial phases-14, 15, and 16. But it has not made any decisions on putting those plans in effect.
The company is, however, going ahead with a northward expansion of its existing phases 9 and 10. That involves drilling a number of new pads in a new development area.
"At any given time, we have one or two rigs working full-time doing development drilling of new pads to replace production from pads that are declining," Rolheiser says. In 2007, Imperial Oil plans to spend $300 million to drill about 200 wells.
Innovations
A portion of Imperial Oil´s development drilling budget will go into a new innovation it calls "mega-pads." One pad will see a combination of 25 to 30 horizontal, vertical, and deviated wells. One-third of these are typically horizontal wells. The other two-thirds are vertical wells.
Rolheiser says one mega-pad will access the same resource as three standard Cold Lake pads. The tactic will also reduce Imperial Oil´s overall footprint-in part, an effort to be a good neighbour to the farmers in the region.
"We expect to add an additional 30,000 barrels per day with [the mega-pad] strategy by the end of the decade," Rolheiser says.
Another innovation Imperial Oil is introducing at Cold Lake is a new solvent technology it calls LASER (liquid addition to steam to enhance recovery). The pilot work is under way on this patented modification of the cyclic steam stimulation process.
The idea behind LASER makes perfect sense in the context of how bitumen is moved through pipelines. Since heavy oil/bitumen is too thick to flow with any speed, a condensate diluent-or sometimes a light, synthetic crude diluent-is added to make it less viscous. So what works in the pipeline may work in the reservoir.
"LASER involves the addition of a small amount of hydrocarbon diluent to the steam being injected into the ground. Usually 5 or 10 per cent of the overall volume of steam that we inject," Rolheiser explains.
Imperial Oil´s research on LASER dates back to 2002. The first full production cycle test was completed in 2004. It showed promising results, with bitumen recovery rate improvements of between 30 to 50 per cent when compared to straight cyclic steam stimulation.
Production at that site is now into its second cycle (CSS uses the same wells for steam injection and resource production, hence the cycles, hence "huff and puff"). To date, the wells are showing similar elevated results as on the first cycle.
"So the results were sufficiently encouraging to proceed with a commercial application of the technology on all of our well pads at Cold Lake," Rolheiser says. In January 2007, Imperial Oil received Alberta Energy and Utilities Board regulatory approval for the first nine of its 200 well pads in the area.
LASER will require additional construction, including tanks and mixing facilities. The exact cost per pad is proprietary at this stage, but Rolheiser says the incremental investment is modest. Solvent/steam injection is expected to begin in late fall.
"LASER has the potential to significantly enhance the overall potential of the Cold Lake heavy oil fields," he says.
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