Potential For New EOR Technologies Touted
- Category: Archived News
- Published on 2006-04-10
"We need to take a more holistic approach to enhanced oil recovery, more than simply looking at the methods of thermal, miscible and chemical flooding," Blaine Hawkins, manager of the ARC's conventional oil and natural gas unit, told executives and analysts attending the Calgary event.
"There are many complementary technologies available to us that we can combine with reservoir processes," he said. "We believe we can almost double waterflood recovery in heavy oil reservoirs and reduce water usage by a factor of six. There is good potential for EOR to add reserves, ... in concert with [these] technologies."
Of world crude oil production estimated at 72 million barrels per day, EOR projects represent only about 2.3 million bbls or 3.2% of the total, Hawkins said, noting the figure includes thermal EOR projects. Some analysts predict global EOR volumes will rise to 30 million bbls per day by 2020. In North America, however, roughly 13% of oil comes from EOR projects.
Hawkins estimated Canada has about 32 EOR projects producing 270,000 bbls per day, although the volume drops to 58,000 bbls per day if only non-thermal, conventional EOR projects are included. The latter group is dominated by miscible solvent floods, he said.
Of 55 hydrocarbon floods carried out in Alberta in recent years, 29 were still active in 2004, including the Swan Hills, South Swan Hills and Judy Creek projects, among others.
Since the late 1980s and early 1990s, Hawkins said, there have been no new hydrocarbon miscible floods in Alberta.
"I don't think we'll see many more [such projects] in the near future," he said, citing the high cost of methane, butane and hydrocarbon solvents. "Because of the price of methane, many of these [projects] have been converted to water-chased fluid [projects]."
Much of the interest oil producers have shown in carbon dioxide floods can be attributed to the lower cost of that gas, compared to methane or other hydrocarbons, he explained. At roughly $6 per mcf, he estimated hydrocarbons cost about three times as much as CO2. Translated to costs per bbl of oil produced, hydrocarbons come in at $18 to $24 per bbl, versus CO2 costs of about $8 to $10 per bbl of oil produced.
Western Canadian producers considering CO2 floods have some barriers to overcome before proceeding, including a lack of adequate CO2 supply and insufficient pipeline infrastructure to accommodate the industry. Hawkins estimated it could be eight to 10 years before the situation is remedied.
In the U.S., because CO2 floods are an established technology, there are more of them than in Canada. Another reason for their popularity there is the relative abundance of natural CO2 -- including underground sources -- in the U.S. That abundance means proponents of CO2 floods south of the border can count on the availability of the gas at a low cost. In Canada, the gas is not so easily available, nor so cheap.
"[CO2 flood] technology holds promise for Canada, but because our major CO2 sources are generally [synthetic], we have a different economic situation. We have the high cost of compression, and need to be able to capture, treat and deliver the CO2 [before injection]," he said.
Hawkins said the remoteness of Canadian CO2 sources, relative to prospective EOR targets, continues to highlight both the lack of CO2 infrastructure in Canada and the lack of a CO2 pipeline.
In an interview following Thursday's session, another conference speaker suggested the need for pure or nearly pure CO2 for EOR projects in Western Canada may have been over-stated.
While injecting nearly pure CO2 at its Midale, Saskatchewan project, Apache Corp. senior production engineer Bruce Beveridge said that, after months of recycling, the gas stream eventually becomes about 40% CO2, the balance consisting mostly of hydrocarbon gases. Yet, in terms of incremental oil recovery, he said the yield is much the same as the company has seen from nearly-pure CO2.
As for Apache's decision to buy CO2 from a U.S. rather than a Canadian supplier, Beveridge suggested Canadian sources might have been an option, but "the timing and economics" of federal government incentives were not right.
Other government incentives for EOR-proponents were also discussed, and the ARC's Hawkins drew the audience's attention to an existing program that will see the Alberta government grant roughly $200 million, mainly through royalty adjustments, to producers that make use of new technologies in EOR projects over the next five years.
The Innovative Technologies Program (IETP) is not restricted to oil recovery, however, but will also consider projects geared to improving coalbed methane recovery and addressing the gas-over-bitumen issue. Nevertheless, the program is taking applications for pilot and demonstration projects that offer to improve oil recovery, a broad category that includes conventional waterfloods, CO2 and solvent floods and EOR projects that inject chemicals, such as polymers.
Hawkins said chemical flooding has generally not lived up to its potential. "Will $60-a-barrel oil change that? We don't know yet, but I believe it will happen eventually, because people are testing these processes and there are reservoirs for which miscible CO2 flooding is not [ideal]."
The ARC has been promoting chemical floods recently, and Hawkins said the use of polymers may ultimately double the recovery of heavy oil in waterflood applications. At least one company, Canadian Natural Resources Limited, has gained approval to begin injecting polymers, using horizontal wells, at a flood in the Pelican Lake field in northeastern Alberta. Among other chemical floods, Hawkins cited an alkaline flood pilot project that Husky Energy Inc. is pursuing in the Taber, Alberta area.
Among the attractions of polymers is their low cost, which Hawkins said translates to about $3 to $4 per bbl of oil produced, making them cheaper than both hydrocarbons and CO2.
"We need to take a more holistic approach to EOR... we have to have improved reservoir access through horizontal or other infill drilling methods, [and] we have to be able to characterize the reservoirs better."
Despite issues that have arisen, he said there are still opportunities for improved waterflooding, through conformance control and immiscible, water-alternating-gas (flood) techniques. As for issues, he warned that public concern about the industry's use of water may affect producers' approach to waterfloods and their selection of water sources.
"Public concern ... is increasing, even though the statistics [suggest] the oil industry really doesn't [use] an awful lot, compared to agriculture, for example. But [the oil industry] handles an awful lot of water, [and] that can be expensive, and affects the economics," he said.
As a result of increased public concern, however, he said the industry may ultimately be forced to rely more on brine for water, than fresh water.
Currently, companies proposing using fresh water for new waterfloods must apply to Alberta Environment before submitting their project applications to the Alberta Energy & Utilities Board. Increased use of brine will in turn mean EOR proponents will have to review the use of some chemicals, the effectiveness of which may be blunted by the use of non-freshwater sources.
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