As a new generation of thermal production begins, Alberta oilsands developers are admitting that they use too much natural gas and are beginning to cut consumption by introducing new technology on a large scale.
At summer technical conferences of engineers, earth scientists and scholars, the professionals were blunt. Eddy Isaacs, an oilsands veteran who is executive director of the provincial government’s Alberta Energy Research Institute (AERI), drew no quarrels when he said “we’re losing value by using natural gas to produce bitumen.” By reducing operational temperatures and tweaking a variety of production technique the existing, 1.3 million b/d network of northern plants has since 2000 trimmed gas use to an average of 0.47 Mcf per barrel from 0.6 Mcf, IHS consultant Robert Fryklund calculated.
But the experts also acknowledged such average figures mask a wide performance range, and the encouraging trend could reverse unless action is taken because oilsands production is changing. Developers will increasingly employ in-situ or underground extraction with heat injections rather than the open-pit mining technique of the industry’s founding plants. The change is only natural. More than four-fifths of the resources lies in deposits too deep to dig up with shovels and trucks.
Current in-situ operations, using steam injections and horizontal wells, typically burn 1-1.2 Mcf of gas per barrel of bitumen produced once they are up and running at capacity. Gas consumption is often much higher in early development stages, when the oilsands ore formations are being heated. Plants that continue to operate at the lower end of the efficiency scale in effect burn more than one-sixth of the energy they produce, on the industry-standard conversion yardstick where one barrel of oil equals 6 Mcf of gas.
One of two new mega-plants currently starting up — the 60,000 b/d Long Lake project by Nexen Inc. and OPTI Canada — is pioneering a breakthrough by switching to synthetic gas to make the steam for its in-situ wells near Fort McMurray in northeast Alberta. While Nexen operates the wells, technology specialist OPTI runs an upgrader that incorporates a gasifier into its production line for converting asphalt-like bitumen into refinery-ready synthetic crude oil. The Long Lake plant will make its synthetic gas from heavy residues of the upgrading process that in other plants wind up as charcoal-like petroleum coke. The byproduct is sometimes burned as power plant fuel or exported to steel manufacturers, but mostly ends up in colossal and growing piles beside plants.
“We have a mountain of coke stockpiled,” Isaacs observed. By AERI’s count, 54 million tons of the stuff has already accumulated and the piles currently rise at a rate of 20,000 tons/d. Oilsands coke output will about double to 40,000 tons/d by the time projects currently being built or poised to enter construction raise bitumen output to 3 million b/d in the 2015-2017 time period, the provincial agency estimates.
OPTI leaders describe the Long Lake approach as a step change that will prove to the industry it can make big money on an energy conservation and environmental improvement.
While a gasifier plant increases initial construction expenses, it will cut production costs by about C$10/bbl as a result of eliminating natural gas purchases, OPTI predicts. The Long Lake project alone expects to replace 100 MMcf/d of natural gas with synthetic fuel.
A second and larger plant currently in the production start-up stage — the 110,000 b/d Horizon Project by Canadian Natural Resources Ltd. (CNRL) — is a mining and upgrading complex on a choice shallow deposit north of Fort McMurray that does not need or include a gasification add-on plant for in-situ extraction. But CNRL is also a highly active in-situ oilsands developer and it is keeping close tabs on trials of technology aimed at reducing or replacing natural gas consumption.
CNRL is performing lengthy trials of a technology known as vapex, short for vapor extraction, which performs underground bitumen extraction with a solvent such as propane rather than steam.
In theory the system has potential to make a five-fold improvement in the reserves recovery rate to 50% as well as cut gas consumption, CNRL Vice Chairman John Langille reported. In practice the engineers are still only working gradually toward making the idea work on a large scale. In laboratories new oilsands ideas often work. “Going out into the field is always a completely different story,” Langille said.
But with oilsands gas use currently forecast to top 2 Bcf/d by about 2015, the CNRL executive predicted that the conservation and cost issue could become big enough to ignite collective action. “If all projects went ahead to full capacity, we’d probably have to look at gasification projects as an industry.”
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