Memorandum submitted by Neil Crumpton
Apologies for the late response to this consultation.
Developments in low-carbon technologies are moving quickly and
the emerging possibilities outlined in the response below are,
I believe, worthy of some consideration.
Even with increased and determined support for
renewable energy generation, new energy efficiency programmes
and possibly mandatory policies for the take-up of CHP schemes
and devices at all scales, there could still be a sizable electricity
generation "gap" to fill over the next twenty years
or so. The gap would be created as much of the existing nuclear
and coal power station capacity is closed down in the period to
2020. This proposal rejects the call for a new nuclear programme
to contribute to the filling of any gap and puts forward how a
significant capacity of carbon-neutral and, more importantly,
carbon-negative generating capacity could contribute instead.
Avoiding a new nuclear programme means that,
after demand reduction, any gap left after serious progression
of energy efficiency, low-carbon and renewables programmes would
likely have to be filled with a combination of new and or existing
centralised fossil fuel stations. There are several types of generating
technologies which could do this: next-generation gas-fired capacity
(CCGT), new coal/biomass fired capacity (IGCC gasification/AD
700), and modified existing coal station capacity. The selection
of such technologies would be much dependent on the emission reductions
achievable, capital cost of new or modified plant, biomass availability,
output cost and public support. A consideration of a fuel's pre-combustion
emissions and security impacts could also feature significantly
in informed public debate and decision-making.
Also, as part of an energy policy, emission
levels from such technologies could be reduced significantly by
the use of carbon capture and storage (CCS) if and as the various
technical and regulatory issues are addressed. CCS does have financial
costs and an energy "penalty" which would have to be
factored in. However, CCS costs would likely be reduced if used
for "enhanced" oil and gas recovery (EOR) in the depleted
North Sea oil and gas fields. There may be pre-combustion impacts
and security considerations associated with the importing gas
and oil from longer distances and or certain areas that may benefit
North Sea EOR in that regard.
Yet, more significantly, carbon capture and
storage opens up the possibility of developing a "carbon-negative"
electricity generating technology, which could actually remove
carbon-dioxide from the atmosphere during operation. This could
potentially have significant benefits in reducing global warming
emissions. It would be achieved by co-firing as much biomass as
possible in either modified (retro-fitted) existing coal power
stations, new coal gasification schemes (IGCC), and or new advanced
super-critical coal plant, then capturing and storing the emissions.
The use of CCS in combination with a significant take-up of biomass/energy
crops could allow the UK to develop the world's first large scale
carbon-negative generation system. The UK could take a lead world
wide in developing and demonstrating such a system, with potential
benefits in other countries, particularly China and India.
The benefits of using co-fired coal technologies
and CCS in such a carbon-negative way would be:
(i) enable significant reductions in UK power
sector emissions to be achieved before 2020;
(ii) demonstrate carbon-negative technologies
to major coal using countries particularly India and China;
(iii) enable more biomass to be used in power
generation more quickly as part of the "renewables"
(iv) provide a large and viable biomass market
and supply chain from which smaller biomass CHP schemes could
(v) contribute significantly to UK energy
security by the use of an indigenous energy resource (backed by
strategic reserves of UK coal resources in an emergency); and
(vi) contribute to the rural economy.
(CCS) AND EFFICIENCY
Current estimates of the carbon dioxide capture
efficiency range between 85-90% of the emissions in the flue stack.
The process is energy intensive which produces additional emissions
albeit mainly captured ones. Improvements in capture technology
may raise the efficiency to 95%. The CCS process is estimated
to require nearly 20% additional energy so the additional emissions
would result in a slight loss of capture efficiency (eg down from
90% to 88% capture) per unit of output.
CCS as a concept has been successfully demonstrated.
Currently CCS is carried out in the US for enhanced oil and gas
recovery (EOR), in a Norwegian gas field (to reduce CO2
content of gas which would other wise be vented to atmosphere)
and in Algeria where BP are re-injecting CO2 from extracted
gas, again to avoid venting. The capacity of the UK North Sea
gas and oil fields for EOR is significant and storage potential
in other geological formations is huge.
The amount of biomass that could be co-fired
in what are basically coal-firing technologies is key to their
carbon-negative capabilities. There are basically three types
of coal-fired technology which could use significant amounts of
biomass, namely coal "retro-fit", IGCC gasification
and new build AD700 plant. The percentage capture, the capital
and or retro-fitting cost, the cost of CCS, and price of electricity
may differ between the options. Some provisional figures are shown
below but they show the potential.
(i) Retro-fitted coal stations
Existing coal stations (in UK, China, etc) can
be modified by fitting advanced super-critical boilers and feedwater
heaters which at least one leading power generation industry player
(Mitsui Babcock) estimate would improve typical efficiencies by
around forty percent (ie from 35% to 49% thermal efficiency).
The super-critical boilers would also be capable of being co-fired
with up to 20% (possibly 25%) biomass, rather than 6-7% in current
boilers. Furthermore, the feedwater heating could use biomass
boilers as an alternative to gas turbine/boiler plant. This would
significantly increase the amount of biomass used overall in the
scheme. According to industry sources (Mitsui Babcock) if the
main boilers are co-fired with 20% biomass and the feed water
heaters are also biomass-fired then the overall amount of biomass
used per output of electricity is around 40%. Hence, around 40%
of the emissions would be from biomass and hence carbon-neutral.
Assuming 40% carbon-neutral (biomass) emissions
and an overall carbon capture efficiency of 88% then 35.2% of
the emissions captured (40 x 0.88) would be carbon-neutral and
hence "carbon-negative" when stored. Of the 12% of CO2
that does get released to atmosphere 7.2% (12 x 60%) would be
from coal and 4.8% (12 x 40%) would be from the carbon-neutral
biomass. So, to account for the uncaptured emissions from the
coal the overall carbon-negative emissions capture would reduce
to around 28% (35.2-7.2) of the overall emissions. If CCS efficiency
rose to 95% then overall carbon-negative capture capability would
rise to around 34.6% (37.6-3).
An overall carbon-negative capture capability
of around 28% possibly more is significant. It would mean, broadly
speaking, that for every 10 power stations so fitted, then the
emissions from an additional 2-3 coal power stations could also
be neutralised (ie made carbon neutral).
(ii) IGCC gasification
Sill under development, the Integrated Gasification
and Combined Cycle (IGCC) technology would allow around 10% co-firing
with biomass according to one developer (Progressive Energy, who
proposing an 800 MW IGCC with CCS on Teeside). This figure might
be pushed upwards once the technology is proven. The benefits
of IGCC is that the carbon dioxide is captured in pipe at a temperature
and pressure that facilitates lower cost capture, possibly around
$15 per tonne as opposed to $30-45 from supercritical boiler flue
gases. Assuming a 90% CO2 capture efficiency then with
10% biomass co-firing the technology would be essentially carbon-neutral.
However, if the amount of biomass could successfully be increased
to 15-20% then a modest carbon-negative capability would be achieved.
A variation of IGCC, namely IGFC, which incorporates a robust
solid oxide fuel cell as the first of a three stage process could
raise the efficiency to over 50% which could result in cost reductions.
(iii) AD700 coal technology
The next generation of supercritical coal technology
would improve efficiency to about 54% about 5% more than coal
retro-fit schemes. The efficiency is improved by raising the super
critical boiler temperature to 700 degree Celsius. The boilers
would be capable of co-firing with up to 20% biomass. As this
new-build technology has a useful efficiency improvement over
coal retro-fit the price of electricity could be reduced while
the potential carbon-negative capability would likely be of the
According to Mitsui Babcock, all three technologies
have estimated price of electricity costs, including CCS, of around
3.2-3.6 pence/kWhr based on coal at £30.5 per tonne. This
may rise slightly depending on the cost and amount of biomass
fuel and may reduce depending on carbon (trading) price. For comparison,
CCGT with CCS is estimated at 3.9 pence/kWhr based on gas at 30
pence/Therm, or 3.4 pence/kWhr at 25 pence/Therm. Electricity
from new-build nuclear plant is estimated by the Cabinet Office
(PIU 2003 report) at 3-4 pence/kWhr. Wind energy from onshore
wind turbines is around 3.2 pence/kWhr currently. Offshore wind
energy, currently around 5.5 pence/kWhr is estimated by the Cabinet
Office to be around 3-4 pence/kWhr by 2020. So the cost is within
the price range at which other benefits could be considered without
As regards capital costs, some of retro-fit
technology is already operating and can be costed. It is likely
that investors would have more confidence in retro-fitting their
existing assets, rather than investing in next-generation IGCC
or new build coal plant. Yet CCS costs may give IGCC an edge in
the next decade albeit with much lower carbon-negative capability.
A DTI/Carbon Trust recently carried out a study
on the land area needed to grow a given biomass energy potential
(www.defra.gov.uk/industrialcrops). The study estimated that "biomass
might generate 6% of UK electricity by 2020 using 350,000 Ha".
Assuming 2020 electricity demand is around 400 TWhrs/year (the
current figure) then this would represent 24 TWhrs/year of electricity.
If this is so, assuming 40% biomass use in coal retro-fit schemes
then 24TWhrs/yr would result from 60 TWhrs/yr coal/biomass overall
output. This order of output could be generated by 10 GWe of coal
retro-fit stations operating at 70% load factor. To replace the
"baseload" output of the existing UK nuclear stations
(88 TWhrs/yr) would require 12 GWe of coal retro-fit capacity
(at 80% load factor) and around 500,00 Ha of biomass. In the latter
scenario there would be a significant carbon-negative capture
benefit rather than an additional nuclear waste disposal problem.
It is currently generally considered that any
biomass used in electricity production should be used in good
quality CHP plant as the biomass would be used at the highest
overall efficiency. Yet, very few such biomass schemes have come
to fruition in the UK to date. Indeed, the potential resource
according to studies by the Royal Commission on Environmental
Pollution, the DTI and the Carbon Trust, would likely exceed the
forseeable maximum usage likely in decentralised mini and micro
CHP schemes. Furthermore, co-firing in super critical boilers
may actually be nearly as an efficient way to get the most energy
value from the resource as a good quality biomass CHP. Mitsui
Babcock suggest this is arguably the most efficient use of the
resource, though Grid transmission losses may not have been included
in the overall analysis. The increased use of biomass would likely
be, at some point, moderated by public attitude and biodiversity
factors assuming the costs are reasonable. Biomass could be grown
indigenously and or possibly imported.
Yet, by providing a large UK market for biomass,
co-firing coal schemes may actually build a stable biomass market
from which decentralised CHP schemes would benefit from. So current
concerns may be overstated and in any event policy could incentivise
the best use of the resource.
It could also be argued that using biomass,
rather than gas imports, for electricity generation would reduce
the amount of biomass available for the production of bio-fuels.
Yet, in energy security terms, electricity production could probably
be more easily disrupted than the supply and stocks of transport
fuels and hence should be considered a priority in that regard.
For example, long distance gas pipelines and LNG tankers and facilities
are vulnerable to terrorist attack which could reduce supply capacity
significantly and quickly. In contrast, coal and biomass can much
more easily, cheaply and safely be stockpiled in the UK, and there
are indigenous sources of both coal and biomass on which to rely
or fall back on (a strategic reserve of opencast coal sites could
be established). Furthermore, global gas resources are estimated
to peak far sooner than coal by some margin (and obviously biomass
is renewable). The estimated global resource is around 50 years
for gas and 200 years for coal. So, price increases for gas are
more likely as a finite and diminishing resource, and the availability
less certain in comparison with coal. Coal would also be imported
from more secure countries than gas (eg coal from South Africa,
gas from Middle East, Russia).
It is worth noting that in terms of combustion
within a gas or coal electricity generating technology the best
efficiencies and lowest emissions per kWhr to date have been obtained
from North Sea gas-fired CHP then by CCGT with sub-critical coal
lagging some way behind. However, when pre-combustion emissions
associated with gas are considered, namely venting (extracted
gas contains up to 20% CO2). flaring, pumping over
long distances, leaking pipes, or with LNG, liquefaction, transport
and re-gasification, then the "life-cycle" emissions
associated with gas and hence CCGT increase potentially significantly
(see Wuppertal Institute LCA analysis).
In comparison, the pre-combustion emissions
from coal can be relatively low, particularly for open cast coal.
The pre-combustion emissions arising from coal are mainly transport
and methane releases. Methane releases are by far associated with
deep-mined coal (particularly if no methane capture technology
is installed at the mine). Opencast coal contains little residual
methane as the seams are not nearly as compressed by overburden
as deep mine seams, so the methane has already mostly escaped.
If the pre-combustion emissions of coal and
gas are included in a life-cycle emissions analysis then efficient
super-critical coal plant narrows the emissions gap, co-firing
with 20% biomass potentially closes the gap, and biomass feed
water heaters could put coal/biomass schemes ahead of even next-generation
CCGT (all without CCS). In summary, when pre-combustion emissions
are included in the analysis then generating electricity by CCGT
with CCS would not have any particular environmental advantage
over coal / biomass with CCS.
A UK CARBON-NEGATIVE
It is estimated by Mitsui Babcock that around
2GW, possibly more, of current coal station capacity could be
retro-fitted per year, each taking two years to complete. Hence
a 12GW retro-fit programme (replacing the current nuclear output)
would take around seven years. Fitting CCS would take three years
per scheme, so a complete "retro-fit plus CCS" programme
would take around eight years to complete. So, if it began in
2008 it would be completed in 2015. Most of the retro-fitted capacity
would be operating before 2015 and so would likely preceed the
earliest date that any new-build nuclear stations would possibly
come on line (2015 ?). The availability of the required capacity
of the biomass resource could compromise the amount of carbon
captured as would the availability of viable CCS storage sites
(probably EOR in the North Sea but also possibly in saline aquifer
in the Irish Sea).
Such a 12GW retro-fit programme, generating
around 85 TWhrs/yr would likely fill much of the emerging "generating
gap" caused as existing nuclear and some existing coal and
CCGT plant is retired. The gap may be around 100 TWhrs/yr in 2015,
rising to around 150 TWhrs/yr in 2020 depending on a number of
variables. Either way this would be a substantial capacity and
importantly, with CCS, it would be a low carbon if not a significantly
carbon-negative output. This could additionally neutralise the
emissions from about 24 TWhrs/yr (85 x 28%) of output from efficient
coal plant without CCS (eg the 4GW Drax if it were not retro-fitted
as it is relatively more modern and efficiency anywayit
would produce 24 TWhrs at 70% load factor). In total, the carbon
neutral output could be around 110 TWhts/yr (85 + 24) which would
be a substantial part of the emerging generating gap.
Such a retro-fit programme would also answer
concerns about energy security, as the coal and biomass would
be sourced either indigenously and or imported from less volatile
regions than an alternative programme based on CCGTs and gas imports.
Neither would it give rise to nuclear proliferation concerns or
present a radio-logical hazard in terms of terrorism and accident.
Perhaps most importantly in global terms such
a programme could demonstrate to the world a carbon-negative generating
technology based on modifying existing coal-fired plant and a
renewable resource. As there is a very large number of such sub-critical
coal power plants worldwide, especially in China and India, which
are not due to be replaced for possibly decades such a demonstration
could be extremely important as befits a country wishing to show
global leadership on the issue of climate change. It may also
be beneficial to UK plc in terms of technology transfer.
The UK has the potential to develop what would
be at least a carbon-neutral if not a significantly carbon-negative
electricity generating technology which could be copied world
wide. The figures produced in this response are based on hard
data and on-going industry studies, and look promising. Also,
nearly all of the components of the overall technology are already
operating in a number of power stations around the world or in
oil/gas fields. As a carbon-negative capability is likely to some
degree from such technologies and fuels, and the benefits of carbon-negative
technologies potentially so useful, that more detailled studies
should be undertaken by the DTI and others with best speed so
as to inform the "energy review" in 2006.
If further investigation and debate does prove
positive then political backing and policies should speedily be
put in place to give carbon-negative energy generating technologies
the support they might need to come to fruition.
7 October 2005