In the oil sand mines in Alberta, Canada, geothermal energy provides the
opportunity to
reduce CO2 emissions from the heat-intensive process of extracting the oil. To
separate 1 m3
of oil from the sand, 5 m3 of heated water are required. The energy to heat this
water is
generated by burning natural gas. To generate 1 MWth, 2300 m3 of natural gas
have to be
burned (theoretically), resulting in 4.4 T of CO2 emissions and costs of 600 US$
every day.
For the same power output from geothermal energy, (theoretically) 50 borehole
heat
exchanger (BHE) - heat pump (HP) systems with 400 m depth, or 6 BHE/HP
systems with
2000 m depth are necessary.
In the Athabasca Oil Sands area, granitic basement is relative shallow (200-800
m),
making EGS an alternative option. Temperature gradients in the sediments
range from 20-40
K/km, and heat flow is 30-60 mW/m2. The industry consortium GeoPOS plans to
drill an
appraisal well 500 m into the granitic basement to study the thermal and
hydraulic conditions
in the granite. If conditions are favourable the well can be the first step to
develop an EGS
system. The aim would not be to produce electricity but direct heating of
separation water. If
conditions are not favourable for EGS, the well will be used for a BHE/HP system.
Shell will invest 1.4 bln US$ to double daily production from the oil sand mines
until
2010, other operators have similar plans. Besides water usage, gas
consumption
(commercial) and CO2 emissions (environmental) become major issues that
need to be
addressed for these expansions. This situation provides an ideal opportunity for
geothermal
energy applications where they are needed and not where subsurface
conditions are
favourable because initial profitability is of secondary importance and any level
of heat
supply is a success.
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