Select Committee on Environmental Audit Written Evidence

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" portfolio;

    (iv)  provide a large and viable biomass market and supply chain from which smaller biomass CHP schemes could emerge;

    (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.


  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 same order.


  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 economic concerns.

  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 ( 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.


  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 anyway—it 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

previous page contents next page

House of Commons home page Parliament home page House of Lords home page search page enquiries index

© Parliamentary copyright 2006
Prepared 16 April 2006