Demand destruction is creeping into the biggest emerging Canadian industrial natural gas consumer, Alberta oilsands operations. The biggest new development, Canadian Natural Resources’ (CNRL) 500,000 bbl/d Horizon Oil Sands Project, includes a C$1.4-billion (US$1.2-billion), long-range commitment to adopt “gasification” technology for making plant fuel from bitumen.

“If we can replace purchased gas we really enhance the economics of the project,” CNRL President Steve Laut said in an interview. “We’re not banking on oil prices being anywhere near where they are today.”

CNRL’s long-range planning expects to make oilsands development profitable at annual average prices of US$28-$35/bbl — a level most Canadian producers and analysts regard as the most likely “economic” value for oil if geopolitical speculation and supply fears are stripped out of commodity markets.

Horizon is a 12-year project of C$20 billion (US$16 billion) in virtually continuous construction of bitumen mining and synthetic-oil upgrading facilities in the Fort McMurray district of northeastern Alberta. Gasification technology will be retroactively installed in 2013 into the first 132,000 bbl/d stages of Horizon, which are currently under construction.

The system will be incorporated into subsequent stages at the outset of construction. Current mining and upgrading plants show improved efficiency over older operations but still consume 0.6 to 0.7 MMBtu of gas for every barrel produced by heat and power generation in energy-intensive oilsands production. The initial 132,000 bbl/d phases of Horizon will burn 200 MMcf/d when fully operational, CNRL predicts.

“In-situ” underground extraction processes used on oilsands deposits too deep for mining easily double and sometimes triple the gas consumption of mining complexes, Laut said. CNRL is also an in-situ oilsands producer and intends to achieve output of about 300,000 bbl/d from deep bitumen deposits outside the Fort McMurray district over the next dozen years. Continuous heat injections, using steam from gas-fired boilers, are the cornerstone of in-situ oilsands production. A variety of alternatives are under study, ranging from entirely new heat-generating systems such as forced-air injections to replacing gas-fired boilers with a nuclear reactor.

But the mainstay of development planning remains a system known as SAGD or steam-assisted gravity drainage, which uses pairs of horizontal wells for simultaneous heat injections and flows of hot bitumen. The nuclear option, sponsored by government-owned Atomic Energy of Canada, has generated little interest because it would require construction either of multiple small reactors or a sprawling steam distribution pipeline grid. Gasification systems are catching on.

Two oilsands projects now under construction — Long Lake, a SAGD program south of Fort McMurray by Nexen and Opti Canada, and the Heartland Upgrader near Edmonton — will make their own plant fuel from bitumen. Among independent engineers and analysts, including the National Energy Board’s economics department, the systems are regarded as in trial stages where they are too new for reliable projections of results.

The NEB forecasts oilsands gas consumption will about double to 1 Bcf/d over the next two years. But not all large-scale oilsands developers are eager to be early adopters of new gas replacement technology.

Gasification is notably absent from plans announced by EnCana Corp. to increase its in-situ oilsands production 12-fold to 500,000 bbl/d over the next 10 years with C$5 billion (US$4 billion) in plant construction and C$7.5 billion (US$6 billion) in SAGD drilling. Rather than try its hands at pioneering on new technical frontiers, EnCana is concentrating on making SAGD drilling efficient and looking for “downstream” partners for the heat-intensive process of upgrading oilsands bitumen into refinery-ready light crude. EnCana aims to secure a processing partner by the time its bitumen production hits 100,000 bbl/d in about 2009, COO Randy Eresman said. One candidate has stepped forward so far in the United States, refiner Valero Energy Corp.

Previously announced technical studies continue into converting a Valero plant in Lima, OH, for oilsands output. The arrangement calls for EnCana to take part ownership and contribute about C$1.5 billion (US$1.2 billion) for construction if the scheme goes ahead. EnCana’s strategy, unveiled at corporate “investor day” sessions for financial analysts in Calgary and New York, highlighted the role of gas in oilsands development.

Non-energy plant operating costs of SAGD bitumen production have been pared down to C$2-$2.25/bbl (US$1.60-$1.80). Improved SAGD drilling technique has cut the time needed to put paired horizontal wells across bitumen reservoirs to two weeks from seven weeks.

Drilling costs are down by 75% over the past four years. But total operating costs of EnCana’s SAGD production, including purchased natural gas for heat processes, are projected to be C$7.40 (US$5.92) per barrel of bitumen output. With even efficiency-minded EnCana facing such high gas costs, improving the “steam-oil ratio” of in-situ oilsands systems has emerged as a priority engineering issue throughout the Alberta industry.

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