* Steam operations risk additional cost for shutdown and
restart
* At least one company considers keeping production shut
* Conoco exec says 'big learning curve' for operation
By Nia Williams
CALGARY, Alberta, May 11 (Reuters) - The massive wildfire
raging in Canada's oil sands region has forced some thermal
projects to shut down steaming operations entirely, taking
producers into uncharted territory, as delicate reservoirs that
require continuous production could be at risk, analysts said.
Six companies have completely shuttered 115,000 barrels per
day of thermal operations as a precaution against a wildfire
that forced nearly 90,000 residents to evacuate the oil sands
hub of Fort McMurray last week. That represents
only about five percent of overall production from Alberta's oil
sands, but for the companies involved, it is among the most
expensive to restart.
At least one company is considering keeping a project
shuttered indefinitely in the aftermath of the fire, reflecting
how operators have had their hands forced by the blaze, as some
were already considering curbing production because of low
prices.
The technology needed to pump high-pressure steam to unlock
bitumen deposits makes production costs expensive for thermal
operators. But the costs of idling, and then cranking production
back up, is also high, and the process involved in restarting
production is delicate, especially for newer projects.
Producers that invested billions of dollars in oil sands
reservoirs chose to operate at a loss rather than shut barrels
in even at the peak of the crude price rout in the first quarter
of 2016.
Thermal production is expected to take longer to restart
than the roughly 900,000 bpd of mining output halted, both
because of the steaming and heating processes involved and
because some thermal projects are still inaccessible due to the
fire.
Some companies are unsure as to how they will proceed.
Conoco Phillips COP.N Canada President Ken Lueers said the
company would face a big learning curve on its 30,000 bpd
Surmont project, which was evacuated last Wednesday.
"The asset is very new, the maximum time we have had steam
under the ground is under a year and we don't know how developed
those steam chambers are and how they may or may not have
dissipated," he said, adding Conoco may have to redrill some
wells if temperature differences cause steel liners to buckle.
The length of time operations are halted and the maturity of
the reservoir are crucial for determining how difficult and how
costly the restart process is.
"For a company that has just started up, the heat injected
into the reservoir will be far less than those that have been
operating for years. They (the reservoirs) might react
differently when they start to go back (online)," said Bernard
Leung, a consultant and former oil sands production engineer
with Devon Energy (NYSE:DVN).
By contrast, Toshi Hirata, President of Japan Canada Oil
Sands Ltd, which shut down its 5,000 bpd Hangingstone plant last
week, said he was confident the reservoir would not be affected
because the facility has been steaming for 15 years.
However, he suggested Hangingstone may do what was
considered unlikely - keep the operation offline for some time
because of low global oil prices.
LOOKING AT THE UNKNOWN
Companies are unsure what the exact effect will be on
carefully-engineered bitumen reservoirs, which are produced by
injecting steam underground through well bores to heat and
pressurize tarry bitumen so it can flow through pipelines to the
surface.
If facilities are offline for three to six months steam
could condense into water in the reservoirs, which would have to
be pumped out, treated and disposed of before new steaming can
begin, industry players said.
Other risks include sand collapsing into the reservoir, or
engineers struggling to find the right steam pressure needed to
optimize bitumen production.
"A general number we work off is that there is a three or
four-week period where the reservoir can maintain pressure, but
every reservoir is different," said Wood Mackenzie analyst Peter
Argiris. "You increase the risk beyond that period."
Operators stop steaming through some wells for up to three
weeks at a time during planned maintenance, and last year
Cenovus Energy shut down its entire Christina Lake facility as a
precaution against forest fires for 11 days.
During the last oil price crash in 2008-09 Connacher Oil and
Gas CLC.TO was the only company to reduce production, shutting
in half its 10,000 bpd Great Divide thermal output for two
months. It struggled to hit output targets for years afterwards.
Athabasca's 12,000 bpd facility - also called Hangingstone -
shut down on Thursday and is intact but still threatened by the
fire, Alberta Premier Rachel Notley said on Tuesday. Nexen
Energy's Long Lake facility, which produces 20,000 bpd, Husky
Energy's HSE.TO 30,000 bpd Sunrise plant, and Statoil's
STL.OL 20,000 bpd Leismer project are also offline.