Network Thermal Storage vs Dedicated Thermal Storage

When it comes to district heating I’ve often heard it said that there’s no point in adding a dedicated thermal storage vessel because there’s already plenty of storage in the network.
I just tested this theory on a real project. In this case the volume of stored water in the network was calculated to be 6m3. The principle in trying to use the volume of the network as a store is that you operate a flow temperature deadband of say 5C. So when the flow reaches 75C you turn off the supply plant and let the flow temperature drop to 70 before switching the supply plant back on.
Assuming this deadband of 5C then this water volume represents roughly 0.03MWh of energy storage in the pipes. So for a, say, 2MW heat pump running at full output you can run for 54 seconds before you have to switch off. In those 54seconds you’ve raised the 6m3 back up to 75C. In reality it’s little more complicated than that because if during those 54seconds there’s a demand on the network the demand will be sucking heat out of the stored water simultaneously to the heat pump putting energy in so it’s a little longer depending on what the demand is. If the demand was an average of 1MW it would take a further 54seconds to fill the store.
Once the heat pump has switched off then the network flow temperature will drop down the deadband and the heat pump will switch back on at 70C. If the load during this off period were 2MW it would take 54 seconds to reach 70C and trigger the heat pump to switch on – if 1MW then 108 seconds, if 200kW then 9minutes and so on. The smaller the demand the longer the off period.
This means that it is highly unlikely that the network will be able to operate as a satisfactory replacement for a dedicated store. A heat pump needs to be off for 15minutes to allow the motor windings to cool before restart. Our 6m3 network cannot provide for this without significant use of a backup gas boiler.
In contrast a dedicated thermal store of 50m3 provides a minimum of 30minutes of continuous run time and means that the heat pump could, at say a load of 500kW allow 2 hours of off time – as might be typical for a summer day as shown below. It is not simply the greater volume that allows this but also the larger delta T available to the store. In this case 1m3 of the water in the store provides 4x the heat storage capability of 1m3 of water in the network. And the network delta T is peanuts here. A delta T of 40C is typical in Denmark. So the same volume of water in a store would give 8x the storage ability of our network deadband in a well-designed network.
The Red electricity tariff period occurs between 16:00 and 19:00 in the London Power Network area – slightly different times apply around the country. The 50m3 store means that the heat pump can avoid operation for 2 hours of this period without the use of gas boilers. An even larger store of 75m3 would mean for the same conditions the entire 3 hours could be avoided. An even larger store would increase the load conditions for which this applies – as well as providing greater flexibility to capture other grid incentives.
My example here is of course a relatively small network but in a larger network you’d have larger supply plant and be comparing against a larger dedicated thermal store. As we get more and more intermittent generation on the electricity then there will be more and more variation in halfhourly electricity prices, incentivising more flexibility. In Demark they regularly seeing negative electricity prices – you’re paid to consume excess wind generated electricity. So my message here is don’t rely on the network as a store – put in a dedicated store every time.

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Batteries vs Thermal Stores

Assisting one of our energyPRO users modelling a newbuild multi-residential district heating project where the scheme includes PV, a ground source heat pump, electric batteries and a thermal store brought into sharp focus for me the relative cost benefits of thermal storage vs electric storage.
Thermal storage on a district heating network typically costs around £1000 per m3 – with a delta T (the difference between the flow and return temperatures of the heating system) of say 20 degrees and say 90% of the water content practically useable that’s £50/kWh of storage. A delta T of 40 would be more typical in a Danish district heating system halving the cost for the same volume of water.
Turning to batteries, a 13.5kWh Tesla Powerwall costs £5,900 equating to around £435/kWh of storage. Looking at the large-scale 200kWh Tesla Powerpack surprisingly doesn’t seem to reduce prices that much. Then when we look at lifespan the picture gets even worse for batteries. A thermal store could last 30 years or more. A Tesla Powerwall battery comes with a 10 year unlimited cycle warranty – when used in “self-powered” mode.
Obviously a battery provides a great deal more versatility than a thermal store. We can’t run our televisions and computers from a thermal store – we’re limited to space heating and hot water uses. But where in my particular newbuild modelling case above the aim of the storage is ensure that the heat pump can take electricity either from the PV or from the grid during cheap off-peak periods – it doesn’t matter whether the storage sits on the input to or output from the heat pump – the impact is the same. A store allows you to operate independently of the actual requirement for heat and so follow the electricity supply. A battery means you can operate independently of the electricity supply and follow the heat demand.
Of course whether you opt for the battery or the thermal store or both you’d need some software to control your scheme optimally. You need to be able to predict the output from your PV and the requirement for heat both based on weather data, predict electricity prices, check the status of your plant, crunch the numbers and then tell battery the heat pump and the store what to do. You might even want to bid into the electricity markets to buy or sell electricity. At this point I could introduce you to some software that can do all that and we happen to sell in the UK called energyTRADE…

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Ofgem’s Proposal to Remove Triad Payments from Embedded Generators

If you’ve been involved in any CHP/DH feasibility studies you will probably know that many projects are quite marginal. The high cost of building a heat network that has to compete with an existing gas network means that that very few projects are huge money spinners. One of the most critical variables is the value of electricity generated. And given the often derisory price for electricity exported any additional payments that CHP can obtain for providing grid services are often critical. These include payments for Stor, Capacity Market, and Triad.
These payments will become even more important if CHP is to play a role in backing up intermittent renewable electricity generation. In the future as renewables increase their penetration of the grid, gas CHP embedded in local distribution networks, combined with heat pumps, could either provide generation when wind and sun energy are low or demand when there is excess from these sources. For this to work grid service payments will be needed to ensure CHP still stacks up on much lower run hours.
It is therefore dismaying to find that Ofgem are proposing to remove Triad payments from embedded CHP plant. Triad payments (in the form of Transmission Network Use of System (TNUoS – and a smaller Balancing charge) charges are how the National Grid charges for the cost of its upkeep. Every half hourly metered nondomestic customer in the UK contributes to the upkeep cost by paying a charge relating to their kilowatt hour usage during three half hour periods in a year – the Triad periods. (Generators connected to the Transmission System are also charged). These are chosen retrospectively as the three half-hour periods with the highest electricity demand on the grid (between November and February separated by 10 days). The logic of paying embedded CHP operators during these triad periods is that generating electricity directly into the local distribution network CHP reduces demand on the National Grid. In exactly the same way if you are a consumer connected to the local distribution network and you’re able to reduce your demand during the triad periods then you are also reducing demand on the National Grid. For a 1 MWe CHP plant in London triad revenue amounts to around £50,000 a year – not a huge amount but potentially critical in tipping a project into financial viability.
Ofgem’s proposals are a step in the wrong direction. They will make low carbon heat networks even more difficult to justify financially and move the goalposts in a way which is favourable to large plant which overwhelmingly dumps its waste heat rather than putting its to useful purpose.
You can read Ofgem’s rationale here:
https://www.ofgem.gov.uk/system/files/docs/2016/07/open_letter_-_charging_arrangments_for_embedded_generation.pdf
Make your views heard by writing to Ofgem by Friday 23 September 2016. Contact details: Dena Barasi (dena.barasi@ofgem.gov.uk) or Andrew Self (andrew.self@ofgem.gov.uk).

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Electricity “Foregone”- Maximising CHP’s Virtual COP

In the Introduction to the government’s Heat Strategy (The Future of Heating), the chief Scientific Advisor to DECC, Professor MacKay, makes the point that waste heat from power generation isn’t free. When you make use of the waste heat for space heating or industrial processes, it comes at a cost – the cost being the loss of electricity generation. He calls it the electricity “foregone”. He then goes on to compare CHP to electric heat pumps. He says that CHP systems can be regarded as “virtual” heat pumps.  Both technologies effectively require some power to produce heat. What you might know as a CHP system’s Z factor is the same as the heat pumps Co-efficient of Performance (COP) – the ratio of power in (or foregone) to heat out.

Professor McKay goes on to state that whether we use heat pumps or CHP what we need to ensure that this COP (real or virtual) is as high as possible i.e. the minimum power use for the maximum heat delivered and the key to this is to reduce heating system temperatures to as low as possible. And to do this we need to insulate homes – that way our current radiators will still be able to adequately heat our homes even though we’ve reduced the temperatures at which they operate (in order to maximise our CHP/heat pump COP).

But temperatures aren’t the only critical factor in maximising a CHP’s virtual COP. In my last blog I talked about the idea of nuclear power operating in CHP mode. I stated that the COP for a nuclear power station could be as high as 14 (in fact the graph below shows this as just over 16) – based on 2 key design principles.  The first is to do with design and operation of the district heating system itself to achieve low flow and return temperatures. The second key principle, that no-one seems to be discussing or be aware of, is the design of the power station itself – or more specifically the power station’s steam turbine. This design idea has been put forward by William Orchard and while his other ideas about designing for optimal temperatures seems to be gaining ground, this idea seems to be largely unknown.

Almost all large thermal power stations in the UK use a steam turbine to generate electricity. Sometimes (in the case of gas combined cycle CCGT power stations) they combine a steam turbine with a gas turbine which gives an overall higher efficiency of electrical generation. The hot exhaust gases from the gas turbine are used to raise steam for the steam turbine. But you need your fuel in gaseous form to be able to do this – hence why this combining of cycles is generally limited to gas.  There are also power stations that use gas turbines on their own but these are predominantly used for peak load and operate for very few hours in the year.

So when we talk about large power stations operating in CHP mode it’s generally the heat that we extract from the steam turbine that is used for district heating. Conventionally when steam turbines operate in CHP mode there is just one point of extraction for the heat from the turbine. The innovation that William Orchard proposes consists of two parts. The first is to have multiple stages of extraction from the turbine and the second is to design the turbine so that the heat is extracted at lower temperatures and pressures using an automated system. By doing this you could dramatically reduce the electricity “foregone” when the heat is extracted. The following chart shows how this plays out for different types of power station and different flow and return temperatures. Three stages of extraction from a CCGT with a 75 degree flow and 25 degree return gives a COP of 17. For nuclear, at the same temperatures, the result is slightly lower at just over 16. In characteristic form William also shows how this compares to an air source heat pump with a COP of 3.

The implication of this is that if we do go ahead with building new nuclear power stations, we have a choice. We can build them with the turbines optimised for CHP and build district heating connected to them  in which case we only need to build an additional 6% of electrical capacity to make up for the electricity “foregone”. If we go down an electric heat pump route then (assuming a COP of 3) we’ll need an additional 33% of electrical capacity to supply the equivalent heat output.

In my next blog find out more out how these turbine modifications work and what happened when William wrote to turbine manufacturers to start making turbines in this way.

Source: ©Copyright Orchard Partners London Ltd 2012

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Nuclear CHP: why settle for less?

An intriguing title for a blog I hope you’ll agree. Firstly let me say that I’m not a fan of nuclear power. I’m concerned about the safety, the cost, the waste disposal issues and the fact that it’s not renewable. But I do recognise that the government seems to be absolutely determined to get the industry to build more nuclear power stations. For evidence of this see its willingness to provide a fixed price for nuclear power of double the wholesale price of electricity for 35 years with 65% of the capital costs covered by treasury backed loan guarantees. This is in addition to the  repeated mantra that we hear from government ministers that we need a “balanced” portfolio of electricity generation including nuclear, renewables and fossil fuels with (they hope ) carbon capture as we move towards our low carbon future.

This emphasis on nuclear being part of the generation mix is combined with a general desire to see the electrification of both heating and transport. This means that without a very significant reduction in demand “the balanced portfolio” will need to add up to a larger total than we currently have. Without any demand reduction at all nuclear power capacity would need to be around 3x its current level in order to maintain its contribution to the current mix. I recognise that these are very approximate figures but I’m talking in very ballpark terms here. If you think of our energy demand cake as roughly a third power, a third heat and a third transport, if you then move the heat and the transport into the power sector then you have 3 times our current power demand.

Now here I hope you can see where nuclear CHP comes in. If, rather than the electricification of heating, we build district heating systems and connect those to the waste heat from nuclear power stations then we can avoid having to build one third (very approximately) of those new nuclear power stations. We only have to double our capacity (to supply the newly electrified transport sector) not triple it.

Now I can imagine your objections already and I’ll try and deal with them in turn.

  1. Consumers will never accept heat from nuclear power stations in their homes.
  2. Water in district heating systems isn’t like sea water or ground water which we commonly hear associated with radioactivity concerns. It’s different because it’s treated to remove impurities. Pure treated water can’t carry radioactivity.

    Furthermore and rather obviously the water in the district heating network is not the same water as that heated directly by nuclear fission. This water is turned into steam by the heat given off by fission. This steam drives a steam turbine and then is re-condensed into water in the power stations condensers.  Generally sea water is used to condense the steam in nuclear power stations in the UK.  So the first (heat exchange) barrier is at the condensers.  Potentially you could have more heat exchangers in the system though those these come at a cost in that they increase the return temperature of the water back to the power station which increases the loss. We already have an infrastructure that connects our homes to nuclear power stations. It’s the electricity network. Arguably contamination is about as likely as contamination being transmitted through the wires that connect power stations to our homes.

    You also need to think through the scenario in which this district heating future would take place.  The first step would not be the construction of the pipes between cities and power stations. We’d most likely build up district heating within cities with local gas fired CHP (William Orchard’s Hub Concept). As we move towards 2050 we’d see more interconnection and in many cases nuclear would be one contributory heat source to those heat networks.

  3. Nuclear power stations are a long way from conurbations where heat is actually needed and heat unlike power can’t be cost effectively transmitted long distances.
  4. It is true that nuclear power stations are not ideally placed to provide heat to cities but it is entirely practicable to transport large quantities of heat long distances. William Orchard examined this in an article for the CIBSE Journal using Sizewell B (a nuclear power station on the Suffolk coast) and a 128kM 2meter diameter heat main to London as an example.  The water would actually arrive in London 0.1 degree hotter than when it left the power station. That’s because the energy inputs from pumping the water are lost into the water, increasing its temperature.  Additionally very large heat mains lose proportionately less heat than small heat mains because the surface area through which heat is lost (the outer surface of the pipe) is smaller as a proportion of the heat transmitted. Obviously the pipes are insulated as well. The costs of pumping water are less as well, proportionately, with larger diameter pipes – less friction per unit of heat transmitted.

    In Finland the Lovisa 3 nuclear plant was put forward as a CHP plant providing heat to Helsinki’s district heating system. It‘s around 100km from Helsinki. The proposed plant has been rejected by the government but not, as far as I can discern, because of the CHP element.

    If you look at a map of current and planned nuclear power stations then it’s easy to imagine how many of major conurbations could be supplied e.g. London from Bradbury and Sizewell, Greater Manchester from Heysham, Newcastle, Sunderland etc from Hartlepool, Birmingham from Oldbury and Bristol from Hinckley Point. Ok all of those would involve huge civil works but what route to 2050 carbon reduction doesn’t and how does building a few hundred miles of connecting pipes compare to building the double the number of nuclear power stations?

  5. Building district heating is too costly. You’d be digging up streets from now until 2050.
  6. Well we already are digging up streets. I’ve recently, with a mixture of frustration and sadness, watched as the gas network in the town where I live was systematically dug up and replaced with more gas network. And if we persist down a route where we electrify both heating and transport then we will need to dig up the electricity network and replace that to accommodate the increased electricity requirements. If you don’t believe this then take a look at the current activities of UK Power Networks who are responsible for the distribution networks in London, South East and the East of England. They are very keenly looking around for alternatives to digging up London because they envisage the problems. One of their alternatives is small-scale CHP embedded in the network. This has 2 functions – it provides an alternative to electrification of heat and because electricity is generated locally it can provide an alternative to new larger wires in the ground.

  7. Doing this locks us into nuclear power for a very long time. What if a future nuclear accident somewhere in the world causes a future government to shut down. We’ll then be faced with a double whammy – loss of a significant electricity supply and heat.
  8. The situation is not really different to the scenario which we are avoiding i.e. one where we build more nuclear in order to supply heating that is then generated electrically. In our district heating future, nuclear power won’t be the only heat provider to our networks and we’ll have large thermal stores with electricity as a back up so we won’t be dependent on nuclear as the heat supply. It will cause a serious problem if nuclear goes but only in the same way that it would have done had we gone down the electric heating with triple the nuclear capacity route.  Furthermore we decrease the chances of a nuclear accident as we have to build less nuclear plant so there is less nuclear around to go wrong in the first place.

    If, as we build up district heating, it turns out that, happily, we’re not going to go down the nuclear route then district heating is flexible enough to be able to take heat from a variety of sources whether that be large scale solar thermal (as is common in Denmark), geothermal  or surplus renewable electricity or hydrogen. If we go down the route of switching our heating systems to electricity and digging up the streets to put larger cables in then we won’t have that flexibility.

  9. Waste heat from power stations isn’t really free because when you start using the waste heat from a power station you sacrifice some electricity production.
  10. This is true but the amount of electricity you sacrifice depends on the design of the district heating system. Specifically it depends on the temperature at which you reject heat compared to the temperature you were rejecting heat before you made the connection. So let’s say your nuclear power station was rejecting heat at sea water temperature – as most do. You then connect up to your district heating system and the temperature of the water returning from the city’s radiators and hot water cylinders is the temperature at which you are now rejecting heat from the power station. In a conventionally designed system the “Z factor” i.e. the heat used divided by the electricity lost might be as poor as 4. However by optimising the design of the district heating to achieve a low return temperature then you can significantly reduce the electricity loss and increase the Z factor.  That’s why the various innovations put forward in William Orchard’s Hub concept are so important. If you can get the return water temperature down to approaching sea water temperature then you minimise this electricity loss. A further factor is the design of the power station’s turbine and the way heat is extracted from it (again William Orchard and Robert Hyde have come up with innovations here). This will be the subject of a separate blog so I won’t dwell on it here but taking all these Hub innovations together means that the electricity production lost can be as low as 1/14 of the heat supplied to district heating. If you thought of CHP as a sort of heat pump then that would be a Co-efficient of Performance (COP) of 14 – rather better than the COP of 3 we rather optimistically think of heat pumps achieving today.

It’s strange to write a blog proposing something you don’t really want but life is full of compromises. The advantage of going down the route where we allow for the possibility of nuclear CHP is clear: either nuclear does get built and less nuclear capacity is needed or it doesn’t and we have district heating that can draw its heat from a variety of other sources.

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Is Consumption Modelling inherently superior to Production Modelling?

The point is continually made that pure consumption modelling, whilst being possibly more difficult to do than a mixed approach or pure production approach, is inherently superior. I would like to question this. In my view both approaches are valid and in an ideal world we might do both but one is not necessarily superior to the other.

What’s the difference?

Production modelling of carbon emissions allocates the emissions geographically based on where they are produced. You burn gas in your home in the UK so the emissions are allocated to the UK. However if you buy goods produced in China then whatever carbon emissions associated with the production of those goods gets allocated to China.

Consumption Modelling allocates emissions from goods or services to where the goods and services are consumed. If a householder in the UK buys goods from China all of the emissions relating to their production, transportation and retailing are allocated to the UK.

Actually things are little more complicated than this. Both approaches will, to some extent, use fuel purchases not actual consumption or production. So for instance with transportation under NI186 fuel purchased in the UK is allocated to the road network based on traffic flows and assumptions about efficiencies of different vehicles. Some approaches used a blend of consumption and production. The NI186 figures produced by DECC which use a production approach for gas used in homes for heating/hot water/cooking but when it comes to electricity generation they allocate the emissions on a consumption basis.

So why do I think that one is not inherently superior to the other?

Let’s take the following example. If a company closes its operations in Leeds and moves them to China then under a production modelling approach the UK’s emissions will go down. Under a consumption modelling approach they should increase as now emissions relating to the embodied carbon in the goods produced will rise because of the increased transportation distance required. In this case the production approach seems morally questionable. Effectively the UK is cheating by shifting emissions elsewhere whilst continuing to consume in an unsustainable way.

However let’s take another example. Let’s say China now reduces the carbon intensity of its electricity production -while the UK does nothing. Under a consumption approach emissions in the UK will decrease. Under a production approach they’ll remain the same. The consumption approach then gives a morally questionable output. We’ve done nothing yet our emissions have reduced.

Or here’s another scenario. A factory in Leeds which produces goods for export reduces its emissions. Under a production approach UK emissions will reduce. Under a consumption approach they remain unchanged. Does that seem right?

It seems to me that neither approach is perfect. What is important is that globally we reduce our emissions – and fast.  To do this we need to ensure that everyone is working towards that end. Currently international negotiations are based on a production approach. And as long as everyone is working towards that under a global cap, counting emissions consistently and actually reducing them in line with climate science then that’s fine. Of course they’re not, but that’s not inherent in the modelling approach.

Chris Dunham, Managing Director of Carbon Descent

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Out with the old

Old, inefficient incandescent GLS light bulbs have started to disappear from the shops and will be phased out completely over the next few years. Halogen spotlights will also be required to meet new energy efficiency standards by 2016, which will involve the phasing out of some types of halogen lamps.  This means that lamps that you currently use may no longer be available and will need replacing with an energy efficient alternative.

Compact fluorescent lamps (CFL) and tube fluorescent lighting (TFL) are the most efficient alternatives that give the greatest savings, at around 80%. CFL’s are now available in a range of lamp types and fittings and are even available in dimmable versions.

I can’t tolerate fluorescent flicker!

For some people though swapping their traditional light bulb with any kind of fluorescent lamp is not an option due to the adverse health effects that can be experienced. The constant flicker of florescent can affect the sensory system in some individuals – some people’s sensory system can detect the flicker that others cannot. Some people also complain of headaches, migraines, eye strain and general eye discomfort from fluorescent lamps.

What are the energy efficiency alternatives other than fluorescent?

The good news is that as halogen lamps change to comply with new lighting regulations a new range of energy saver halogen lamps are becoming available to replace old phased out lamps. You can now replace your old light bulbs with equivalent halogen lamps that provide the same quality of light, and even look the same, just without the flicker.

LED Lamps

LED lamps will save more energy than halogen lamps and provide a decent quality of light to create good ambient lighting. There is now a full range of lamps available to suit every type of light fitting. However, the lamps are more expensive compared to halogen and CFL lamps.

What is the ‘Colour Temperature’ of Lamps?

Colour Temperature refers to the colour variation of light (the colour of the light) and is measured in Kelvin. This scale ranges from the flame from a candle at around 1,000 K to deep blue sky at around 10,000 K. In simple terms the colour a bulb emits is red at low temperatures, blue at high temperatures and white in the middle.

For a bulb or tube to be classified as “daylight” it will have a colour temperature of between 4,000 K and 7,000 K. It is commonly accepted that a colour temperature of 6,300 K to 6,500 K gives the closest reproduction of natural sunlight. A standard tungsten bulb is around 2,700 K.

All types of lamp are available in various colour temperatures so it is always worth considering this as another option when trying to get the right lighting effect.

An illustration of two booths lit by different colour temperatures

Final energy saving tips

  • Use energy efficient compact fluorescent lamps with high frequency ballasts which can help you save up to 80% electrical energy consumption for lighting.
  • Only use low energy lamps marked with an energy label to ensure luminous efficacy. The energy label guarantees that the lamp can operate a long service life and illumination output is able to meet international safety standards.
  • Use a timer control devices to limit unnecessary lighting in areas that are unoccupied.
  • Maximise natural light whenever possible and practical.
  • Ageing lamps or dirt on fixtures can reduce total illumination by up to 50%. Periodic cleaning can help increase illumination levels.
  • Use the appropriate number of low wattage lamps to replace the use of high wattage lamps.
  • Clean or repaint rooms with lighter colours to enhance light reflection.
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BluePrint Energy Auditing Tool

by Carbon Descent

BluePrint is Carbon Descent’s latest software solution in the low carbon sector. It is both a tablet PC application for collecting data during site visits and a desktop program for developing recommendations and producing automated reports.

My experience as an energy auditor began 5 years ago, working in a dedicated energy auditing firm. In that company we developed many of our own systems in house, including macro linked Excel sheets which partially automated the calculation of energy saving recommendations. Amongst the engineers we thought the next evolution of our systems, in terms of saving time and improving quality, was for the information collected onsite to be recorded directly onto a computer, ready for processing.

BluePrint does exactly this. BluePrint is a software tool, 4 years in development that streamlines the data handling in energy audits. It has been developed by Software Manager Julie Allen as the product of a Knowledge Transfer Partnership between Carbon Descent and London South Bank University.

Example of BluePrint loading on a tablet PC

The benefits of BluePrint above conventional auditing methods

Time saving – This is achieved through onsite data gathering with a tablet PC, robust recommendation calculators, automated report generation and inbuilt benchmarking features.

Consistency – The tool brings a consistent methodology from audit to audit as well as across a team of energy assessors.

Reuse of facility details for subsequent audits – Once an audit is complete, the layout of the site, clients, and other site specific information is contained in the software database. This makes subsequent audits faster with easily accessible historical data.

Configurable – The software is highly customisable. Additional recommendations can be added to the existing suite. The report generated following an audit can be tailored for different sites, such as, a factory, a swimming pool or an office.

Up to date reference data – Data such as emissions factors and the costs of measures are regularly updated to ensure accurate assessments are produced.

Future features planned

Additional resources – BluePrint can record many features about a site that relate to its resource consumption. Whilst currently only set-up for Energy, we plan to add water and waste functionality in following releases.

Management capabilities – The tool will provide a range of preformatted management information reports for single or multiple projects. This will enable an organisation to monitor various parameters across projects such as time spent by an auditor, CO2 savings identified, and an overview of project billing.

Display Energy Certificates – The benchmarking methodology employed in BluePrint closely follows that of the Display Energy Certificates. With some planned alterations, it is intended that the product become certified to deliver Display Energy Certificates in the near future.

The official launch for BluePrint will be towards the end of 2011. Please email us at software@carbondescent.org.uk should you wish to be invited to the launch or receive news updates for this product.

The official BluePrint Website can be found here

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Carbon reduction targets – looking forwards or backwards?

This entry looks at modelling the 34% 2020 greenhouse gas (GHG) reduction target set to an adjusted CO2 only 2005 baseline. The target adjustment formula is given below:

The UK Greenhouse Gas Inventory, 1990 to 2005 Annual Report for submission under the Framework Convention on Climate Change, gives a total greenhouse gas reduction from 1990 until 2005 of 15.4%. This includes land use, land use change and forestry (LULUCF). Excluding LULUCF, the reduction figure becomes 14.8%. When applying the above formula to translate the 34% reduction target onto 2005, the target adjusts to 22.0% and 22.5% respectively.

This all seems well and good, but there is the aspect of GHG vs. CO2 to consider. Whilst GHG reduced by 15.4% (inc LULUCF) and 14.8% (exc LULUCF) between 1990 and 2005, CO2 only reduced by 6.4% (inc LULUCF) and 5.6% (exc LULUCF). When applying the formula to translate the 34% reduction target onto 2005, the target adjusts to 29.5% and 30.1% respectively.

So which is correct?

It depends if you are looking forwards or backwards. If you are looking retrospectively at the 1990 baseline, and assuming that it is equally difficult to reduce all GHGs, then one could argue that taking the CO2 only reduction figures is correct.

If you are looking forward and setting 2005 as your baseline, then you could argue that the problem as it stands is to reduce emissions across the board up to the 2020 and 2050 target. It is interesting to note that local authorities were not tasked with reducing emissions until much later than 1990, and for most authorities the first glimpse at their carbon footprint came along with the National Indicator 186 and Full Local CO2 emissions data set which were both post 2005. The Climate Change Act also only came into legislation in 2008, so in consideration of this, it is best to look at the total GHG account in 2005 for the baseline. This means modelling 2020 targets of 22% (inc LULUCF) and 22.5% (exc LULUCF).

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