Analysis: Rising natural gas prices and concern about availability about supply are helping spur interest and investment in new ways of producing heavy oil and bitumen (an extra-heavy crude usually derived from oilsands) in Canada.
Spiraling gas prices, while producing dizzying increases in profits for gas producers, induce nausea for Canada's oilsands producers. Shell Canada officials, for example, have said each increase of C$1 per million British thermal units (mmBtu) jacks up operating costs by 60 Canadian cents per barrel (bbl) at its massive C$5.7 billion Athabasca development.
Spot gas prices in Alberta this year have averaged about C$8.50 per gigajoule (which is slightly smaller than a mmBtu), up from C$5.40 in the fourth quarter of last year. The hurt has been mitigated by fears of a U.S. war against Iraq cranking oil prices up to about $36 per barrel, which has worked better than two Tylenol to ease the pain.
Oil prices will eventually come down, but the same cannot be same for gas prices in Alberta. Production appears to have peaked while demand for gas in the oilsands hub of Fort McMurray in northern Alberta is climbing as more multibillion-dollar projects are built.
Analysts have predicted daily gas consumption by the unconventional oil industry in Alberta could rise to 2 billion cubic feet per day (bcf/d) by 2011, up from the current total of 900 million per day. Field production in the province now averages about 10.5 bcf/d.
Some of the forecasted increased demand reflects the fact that up to three-quarters of Alberta's oilsands reserves, estimated at about 300 mmbbls of recoverable oil, is buried too deep for strip mining. This means thermal applications such as steam assisted gravity drainage (SAGD), which burns gas for steam that is injected underground to enhance production, will be crucial to future development of the oilsands.
The crunch on gas supply and price is creating opportunity for firms like Petrobank Energy & Resources Ltd., a small Canadian producer that recently formed a heavy oil business unit called Orion Oil Canada.
The subsidiary was set up to pilot and, if successful, commercially develop two patented technologies: Toe-to-Heel-Air-Injection (THAI) in situ combustion and CAPRI in situ catalytic upgrading.
Chris Bloomer, head of Orion, says the plethora of oilsands projects currently proposed could absorb the 1 bcf/d expected to flow from the Mackenzie Delta by the end of the decade.
SAGD, which burns premium-priced gas for steam to increase production of lower valued bitumen, does not make a lot of economic sense, he notes.
"We're going to have to look for other technologies in the long run," he told Oil & Gas Advisory. "If this technology (THAI) works even to a modest degree, the petroleum industry is going to have to look at it."
THAI combines a vertical air injection well with a horizontal producer, a substantially different model from other in situ combustion processes used in Canada. Oxygen contained in the injected air allows combustion of subsurface hydrocarbons, warming the bitumen and creating pressure that pushes the loosened oil into the horizontal well. A version of the procedure has been used for years in countries such as India and Romania.
According to models developed by Petrobank, a near-vertical combustion front is created that sweeps the oil from the toe of the horizontal producing well to the heel. Not only would THAI recover up to 80 percent of the oil in place (compared with 60 percent for SAGD), it would provide some in situ upgrading.
Incremental to THAI, CAPRI adds a refinery catalyst around the horizontal wellbore which, if successful, will further upgrade the crude oil as it is produced.
Orion intends this year to ask Alberta's regulators to approve a field pilot test of THAI at Christina Lake, where Petrobank owns more than 26,000 acres. The oilsands-rich area has attracted the interest of numerous companies, including EnCana Corp.
The unit of Petrobank expects this year to spend C$4 million on seismic, drilling, and project engineering and planning. A full pilot project will likely cost at least C$25 million, Bloomer says.
Another alternative to SAGD is being piloted by the Canadian unit of Devon Energy Corp. It is leading a multi-firm venture trying to find out whether propane and other liquids can replace steam as the driving mechanism that separates bitumen from the sand and increases production.
Vapex, as the latter technique is called, and Orion's THAI hold promise on environmental grounds as well as economics. They could reduce water use, an increasingly controversial issue in drought-ravaged Western Canada, and cut down on greenhouse gas emissions by paring the amount of gas burned for steam.
Additional research programs and pilot projects are delving into field upgrading and other areas in the search to improve the economics of heavy oil and bitumen production in Canada.
Enbridge Inc., the largest oil pipeline operator in North America, is considering allowing the Ensyn Group to build a demonstration unit of its partial upgrading technique at its Hardisty oil terminal in Alberta.
Genoil Inc., a small public company, has built a pilot plant for its heavy oil upgrading process just outside of Edmonton, Alberta's capital and second-largest city. The firm, which says its proprietary method can boost refinery output by up to 25 percent compared with conventional carbon rejection processes, recently had officials from PetroChina observing its operations.
Still in the early stages are a couple of initiatives involving the National Center for Upgrading Technology (NCUT), a federally funded think-tank located near Edmonton.
The Western Research Institute (WRI), a non-profit group from Laramie, Wyoming, is working with NCUT scientists to see whether WRI's oil tank remediation technique, called TaBoRR, can be used for field upgrading.
TaBoRR's processing steps, a light hydrocarbon flash followed by distillation and coking, imitate the starting unit operations at a refinery. WRI and NCUT have experimented with a variety of stripper temperatures to determine the stability of the produced crudes.
The process, if successful, would eliminate or sharply reduce the amount of blending agent, called diluent, needed to make the oil flow in pipelines. This would be a big benefit in the future as growing oilsands production is forecast to put increased pressure on the supply and price of the gas liquids used by pipeliners to dilute bitumen.
Some results from the WRI/NCUT research will be presented during the American Chemical Society's conference March 23 to 27 in New Orleans.
NCUT is involved with EnCana staffers and University of Calgary scientists in the SUPOX process, which involves partial oxidation of heavy oil in supercritical water. Using very high pressures and temperatures cuts the amount of time the heavy oil spends in the reactor, meaning a smaller plant that does not cost as much as conventional upgraders.
A pilot plant to demonstrate what is essentially a hydrogen addition technique has been built, but participants say more work is required to prove the viability of the process.
NCUT is also working with the University of Alberta on bio-upgrading, where bacteria will be used to reduce the viscosity and sulfur content of heavy oils and bitumen.
It's unlikely all these ideas will bear fruit, but this brief overview shows there are a lot of seedlings trying to take root in the Canadian oilpatch.
"We're learning things as we go and that's giving us confidence as we move forward," says Bloomer of Orion. "We're pretty keen and we want to light a fire soon."
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