There have been numerous starry-eyed
projections of the cost of producing shale oil over the last
four decades. Many have said it can be produced at $18-$40/bbl,
but these projections ignored the realities of rapidly increasing
costs of materials, labor, and energy, as we will show in the
following brief summary of our analysis. Our estimates in 2007
were in the range of $110-150/bbl. As of late 2010, we think
these estimates are still accurate.
Oil shale production peaked globally in 1980 at about 46 Mt/yr, with an energy
content equivalent to ~0.02% of current global energy usage. Oil shale production
has been steadily declining since then, and today is about half that amount.
Undoubtedly, oil shale and shale oil production will begin growing again, as
oil seems likely to average $120/bbl in 2012, at which point shale oil could
begin to look attractive. However, it will not grow quickly because the capital
investment required will be enormous and there will be strong resistance on the
basis of environmental concerns, whether real or perceived. Investors will choose
to put their money into lower cost and cleaner options, such as Windfuels.
A recent
small demonstration of the Shell In-situ Conversion Process
(ICP) showed that after
several years
of in-situ central
heating with peripheral wall freezing, a small array of holes
about 500 m deep (in a choice location) can produce ~10,000 bbl
of light, sweet crude before running dry. A lot of processes
have been tried for getting oil from oil shale, but only ICP
appears
likely to satisfy both environmental and economic concerns. However,
it has economic limitations. First of all, because of both drilling
costs and heat leaks, ICP is practical only in the thickest and
richest formations – those containing over 20 gal/ton,
over 30 m thick, and extending over areas of at least tens of
acres.
There is an enormous amount of oil shale in deposits less than
10 m thick, and there is an enormous amount containing under
15
gal/ton.
However, the total US resources that meet all three requirements
for ICP is a small fraction of the total 2 trillion barrels often
cited. A resource 50 m thick containing 30 gal/ton is equivalent
to 400,000 BOE (barrels of oil equivalent) per acre.
The economics of shale oil are firstly limited by the time constant
for thermal diffusion from the heater wells. (This time constant
is proportional to the product
of the logarithm and the square of the distance from the well). Heater and
producer wells will be required on a grid spacing of about 10
to 12 m if oil production
is desired in a reasonable period of time – two to four years of pre-heating,
followed by a year or two of good production. The 30-m minimum deposit thickness
is needed for acceptable vertical heat losses over the development period.
The drilling costs for fairly shallow heater and producer wells (300 to 600
m) are about $500K per grid surface unit – that is, a 100 to 150 m2 surface
square containing one heater well and one producer well. The heating energy required
for a deposit 100 m thick for a grid spacing of 10 m is about 13,000 GJ per heater
well, over two-thirds of which is needed in the first two years of preheating.
The only practical final-heating option is electrical, as the heating must be
applied with a complex dependence on both depth and time that is responsive to
the local conditions. Some of the initial heating could be done with a cheaper
source.
The current mean cost of industrial electrical power is $18/GJ, but the cost
from clean coal with 90% of its CO2 sequestered
will probably be $28/GJ by 2015. Hence, the total heating cost (mostly during
the first two years) will be $360K
per heater (again, for a deposit 100 m thick, with a 10 m grid). Oil production
would begin two years after initial heating, rise for a year or two, and then
quickly decline. The total yield may be 12,000 bbl per heater well. The above
up-front costs just for drilling and preheating are over $60 per barrel of
crude, and these estimates really appear optimistic from more recent trends
in well drilling costs. They come straight from the physics,
mature
drilling technologies, and realistic clean electrical energy prices less than
a decade from now. Another $10/bbl will be needed for heating and freezing
over the remaining life of the well.
It might be argued that the above drilling costs will come down with scale-up
and a slightly coarser grid (12 m). However, material costs have skyrocketed
over the past decade. Moreover, the drill casings must withstand much higher
temperatures than normal wells and be of rather large diameter (at least 30
cm) for adequate
heat or vapor transfer. The heating energy per barrel of product is independent
of the grid spacing and usually will be higher than calculated above, as generally
(after a few extremely choice sites are claimed) there will be layers of non-producing
rock between layers of oil shale.
There are a number of additional components to the costs, but they are more
difficult to estimate precisely. The down-well costs at 800 K for the sensors
and the electrical
insulation (that still must provide the high heat transfer to the well casing)
will be substantial. A realistic estimate is that these costs might be half
of the heater-well drilling costs – about $150K per unit, or ~$12/bbl.
The outer perimeter freeze-wall costs (wells, refrigerators, and power) will
add
another $10/bbl, and a similar amount will be needed to cover site reclamation.
The crude oil produced from the pyrolyzed oil shale is high in nitrogen compounds
(much higher than heavy oils), which are more costly to remove than sulfur,
though otherwise the oil
is of very high grade. Thus, a reasonable estimate is that petroleum (not including
a carbon tax) will need to average over $110/bbl for prime oil-shale deposits
to be competitive – not the $18 to $75/bbl claimed by proponents. The
carbon tax recently recommended by the IEA will eventually add about $30/bbl
to the
cost of petroleum and at least that to low-carbon shale oil.
The energy from the final fuel products (about 10,000 bbl) will be about 60,000
GJ per heater well, or about 5 times the electrical heating required. However,
the input energy in a clean-coal power plant is three times its output, and
there are substantial additional energy inputs to the ICP process – especially,
the drilling and the freeze wall. The net result is that energy in the liquid
fuel produced is not much more than the total coal input energy if the CO2 from
the power plant is sequestered.
As each pair of wells (heater and producer) produces only 10,000 bbl of fuel
over their lifetime (for a deposit 100 m thick), tens of millions of wells will
need to be drilled over the coming decades if shale oil is to make a significant
contribution to our energy needs. For comparison, a convention oil well will
produce 3 to 50 times as much oil in one day as a shale-oil well produces over
its entire lifetime.
The 160-acre site Shell plans to use for its first demonstration (The Mahogany
research Project, in northwestern Colorado) is indeed exceptional.
It contains 2 million
bbls
per acre in a formation that averages over 300 m thick at about 26 gal/ton
with very
thin non-producing interleaved zones. It also has excellent natural seals
above and below. The heating requirement per barrel for this site may be 10%
less than the above estimate for the more typical (but still prime) 100-m-thick
deposit, and Shell’s energy cost will be much less, as there are no plans
for CO2 sequestration.
In summary, “low-carbon” shale oil (carbon intensity similar to
conventional oil) from prime deposits 100-m thick should compete when oil averages
over $110/bbl,
but there are still concerns about ground water contamination after the freeze
walls are abandoned. High-quality deposits 30-m thick should compete in a carbon-constrained
world when oil averages over $130/bbl. However, the scale-up of shale-oil will
be slow for a combination of reasons: (1) it developed a very dirty reputation
over the last three decades, (2) the demonstrations for at least the next six
years are likely to have carbon intensity 80% greater than that of petroleum,
and (3) it is not clear if Shell plans to license its ICP patents to competitors.
Hence, shale-oil is unlikely to contribute more than 0.5% to global oil production
by 2020 and thus will have negligible effect on the price of oil by then. Even
the most “environmentally sensitive” ICP shale oil (powered by
clean-coal plants, with 90% CO2 sequestration)
will still be 15% more carbon intensive than conventional petroleum, and both
will probably be taxed at $30/bbl by 2018. Moreover, peak
coal may be only
25 years away, so there really isn’t any spare coal for use in pyrolyzing
the oil shale.
1. Adam
Brandt, “Converting Green River oil shale to liquid fuels with
ATP and ICP technologies: energy efficiency and GHG emissions”, Univ.
CA, Berkeley, 2007, http://abrandt.berkeley.edu/shale/Brandt_Converting_Green_River_oil_shale_to_liquid_fuels.pdf
2.
http://en.wikipedia.org/wiki/Oil_shale
