CIBSE Energy Performance Group

Mohammed, thank you for pointing out the error in the equation previously quoted in our answer to the question from Cathal Brady; we have now corrected this. With respect to your questions, the following pertains. The DCLG “Low or Zero carbon Energy sources: strategic guide” provides a calculation method for micro CHP and this can be adapted for larger units. CIBSE AM12 is currently being updated and should include a methodology. With respect to exporting electricity, any electricity exported should be counted as ELECTRICITY UTILIZED for the purpose of the carbon calculation but may only gain a low sell-back tariff so the cost savings are lower.

Azza Nabil of BRE’s SBEM Team writes: Users can model buildings that use district heating in iSBEM by selecting “District heating” as the heat source and fuel type of the HVAC system, and then defining the CO2 conversion factor of the district heating network. Section 7.6.1 of the iSBEM User Guide (available for download from the NCM website at www.ncm.bre.co.uk) includes guidance on how this should be calculated, including for district heating schemes supplied by Combined Heat and Power systems only. If users modeling buildings in iSBEM tick the box denoting that the HVAC system also uses a CHP generator (in the Building Services form > HVAC Systems tab > General sub-tab), they then need to define the CHP parameters in the “CHP generator” tab which appears in the Building Services form when the tick box is ticked, such as, its heat efficiency, electrical efficiency, fuel type, etc. Guidance on inputting the parameters in this tab are available in Section 7.6.7 of the iSBEM User Guide. Details of the calculation methodologies used in SBEM are available in the SBEM Technical Manual (available for download from the NCM website at www.ncm.bre.co.uk).

Phil: The CO2 savings can best be calculated using the following. CO2 SAVED = {(ELECTRICITY UTILIZED x 0.568) + [(HEAT UTILIZED x 0.194) ÷ 0.8]} - (GAS INPUT x 0.194). This equation is based on carbon emissions of 0.568 kgCO2/kWh for grid displaced electricity (Part L Building Regulations 2006), 0.194 kgCO2/kWh for natural gas, and 80% efficiency for the boiler it is displacing. Utilized means the electricity and heat actually used in the building (not necessarily what is generated).

David: Yes, it is fair to say that anaerobic digestion of food waste IS a realistic possibility to produce methance for CHP in urban areas. Around 30,000 tonnes per annum of ‘typical’ wet, source-segregated food waste should be sufficient to produce enough biogas from an anaerobic digestion plant to fuel a 1 MW electrical output gas engine (which would also be producing upwards of 1 MW thermal output). At this scale this relates to 3.42 kg of food waste per kWh electrical generation (or similarly 3.42 tonnes per MWh): be aware that with smaller plants the electrical efficiency of generation would typically reduce, and for larger engines it would increase, and as a result this rule of thumb would change slightly. It is possible to ‘blend’ biogas and natural gas in a gas train for use in an engine, although care should be taken with regards to in what proportions in order to not ‘fall foul’ of co-firing regulations for accessing incentives such as ROCs. Hence it would be our strong recommendation not to blend biogas and fossil fuels. Some engine manufacturers also offer dual-fuel gas/liquid fuelled engines, but at this time most are at a very large scale probably not suitable for an anaerobic digestion application. With respect to hygiene risks with these types of plants or processes our anaerobic digestion and biogas expert advises that there is no greater risk to processing these wastes in this way than for any other method. However, it is strongly recommended that the design of the overall plant should be in line with Animal By-Products Regulations and any waste containing animal by-products should be pasteurised.

Phil: Spot-on Martin. This is a real problem but I don't know of any move to standardise how the manufacturers present their data. A lot of efficiency numbers are net because Europe has always used net for boilers etc but I still believe in gross as 100% means 100% not 109%. Buyer beware! David: First and foremost I should state the position I am coming from is that of being an employee of a company which is an official distributor for a CHP engine manufacturer. Despite this I hope that I will put a balanced view on the matter. Within the industry it is considered that the use of lower heating value (net calorific value) vs higher heating value (gross calorific value) is pretty much standardised in manufacturer’s specifications. However, I would concede that this standard is very much based around using the lower heating value of the fuel. I would be very surprised to find a manufacturer using the higher heating value of the fuel in their specifications for the very reason you give, namely that using this value results in a lower ‘number’ value for the efficiencies of the unit. I am aware of some CHP packagers providing publications with specifications on higher heating value basis, most usually alonside the same specs on lower heating value basis for clarity, but would be very surprised to see a manufacturer doing the same. Of course all of this is just a ‘smoke screen’ of sorts. The CHP is behaving in precisely the same way whichever calorific value basis is used, irrespective of the absolute number value of the efficiency, and so long as different units are evaluated on the same basis, whether that be higher heating value or lower heating value, the comparison will be a fair one. Care must be taken with financial or carbon emissions savings calculations as fuel suppliers will invariably supply fuel charged on a higher heating value basis (for their own self interest as this makes it look like they are supplying more energy for your money!) and most carbon emission factors are quoted on a higher heating value basis also. In defence of the CHP manufacturers there is a technical reason for quoting performance of their units on a lower heating value basis. The higher heating value of a fuel is the total amount of energy in that fuel, but this can only be fully realised if the products of combustion are returned back down to essentially ‘ambient’ temperature. In particular higher heating value includes the latent heat of vaporisation of the water in the exhaust gases and in order to realise this energy the exhaust gases must be condensed. This is typically not something which is done on a CHP engine as condensing results in increased corrosion within the exhaust system due to the water and the impurities and products of combustion which condense out with it (in particular NOx) and will contribute adversely to exhaust back-pressure. As a consequence, the lower heating value of the fuel, which does not incorporate the latent heat of vaporisation, is actually the more scientifically appropriate value to use on the basis of a system with these higher exhaust exit temperatures.

Phil: I suspect that very high efficiency vapour compression electric chillers (COP > 6) would probably beat the CCHP. Trigen comes out best when there is a winter heat load then a summer cooling load. But where there is a constant year round cooling load then modern VC chillers are likely to have a better carbon footprint and economics. VC chillers are easier to start/stop. I am not an expert on absorption but they certainly don't like stopping and starting frequently and this could produce a maintenance problem. David: I would suggest that an office building of 30,000 sq ft should have electrical and cooling demands of an order of magnitude significant enough to present a good application for a CHPC or trigeneration application. In my view you are correct to be cautious over considering the performance available at part load levels from such a system if, as you suggest, you would be operating ‘off-grid’ electrically, as in such a circumstance the prime mover would be sized according to peak demand which would result in part load operation being the norm. To what extent exhaust heat loss should be considered depends upon the type of absorption chiller technology you would consider using in conjunction with the gas engine. One option would be for the gas engine to have ‘full’ heat recovery from the engine and exhaust into a low (or possibly medium) temperature hot water circuit and to use this in a single effect absorption chiller. The advantage of this scenario would be lower capital cost for the chiller and the exhaust heat loss could be disregarded. The prime disadvantage would be a low coefficient of performance for the absorption chiller. An alternative would be a direct-fired double effect absorption chiller where the exhaust energy would be used directly in the chiller. In this scenario the thermal losses from the exhaust system before delivery to the chiller should be considered, not only with regards to the effect on the chiller due to the lost energy itself but also due the degradation in the performance of the chiller coming as a result of a lower exhaust gas temperature. For these reasons it is of course very important to locate the chiller as close to the gas engine as is possible in order to minimise exhaust energy and temperature losses. The advantage of this type of chiller is a much higher coefficient of performance than for a single effect water driven type. The disadvantages are typically in capital cost and that such a unit can only be ‘powered’ from the exhaust heat of an engine and not from the lower grade thermal output available from the jacket water, turbocharger intercooler and lubricating oil heat recoveries. In response to the above disadvantage of direct-fired absorption chillers some chiller manufacturers now offer absorption machines, often described as “single-double” units, capable of taking both an engine exhaust directly and a low temperature hot water input into the same unit to produce a single chilled water output. These units in many ways combine the best of both worlds of the two types of systems. Start and stop times for absorption chillers vary from one unit to another so specific advice should always be taken from the manufacturer, however times of around around 30 minutes to full chilled water output are not atypical: this of course being on top of warm up time for the gas engine water circuit (if used) or time to full load for the engine in the case of a direct-fired chiller.

Phil: This sort of charging is not something I have come across. I understood there were no additional charges to parallel into the grid - just follow G59 regulations. However, if you are using the local network to supply to another building then a heavy distribution charge comes into play. David: This is indeed a very difficult scenario. Essentially to be grid-paralleled in these circumstances leaves no other option than to go through the process and incur the costs that you outline. In reality I believe that there is only one alternative approach that is available in these circumstances, and that is to operate ‘off grid’, i.e., in island mode, (sometimes referred to as isolated operation). However, as you can probably imagine this has a number of quite significant draw-backs for CHP. The first draw-back is that CHP is more usually and most sensibly sized around the baseload demands of the application, both electrically and thermally. In the event that the whole of a site, or part of a site which can be electrically isolated from the rest and from the grid, is identified to be powered by a CHP with island mode operation the CHP itself must now be sized electrically so as to be able to provide enough power to satisfy peak demands. Not only does this mean that a larger and more costly unit would be required but it also means that for much of the operation time of the system the CHP will be running at reduced load which invariably adversely affects the efficiency and therefore the financial and enivronmental benefits of the system. Of course the more electrically stable the demand of the site being considered the less the impact of this effect and the more suitable it may be for an island mode CHP system. It may also be possible to install multiple generation units on site to step in and out as required on the basis of electricity demand, and it may be that not all of these units would be CHP-enabled, depending upon prevailing thermal demands. Secondly, in island mode operation the CHP becomes subject to the instantaneous electrical demand fluctuations of the site - in grid synchronised operation the CHP will typically operate at a relatively stable output allowing the ‘grid’ to accommodate demand changes. The impact of this will depend upon the technology used as the basis of the CHP system. For example, a gas engine has a more limited load acceptance profile than would a diesel engine: e.g., from zero load on the unit a typical gas engine can take a maximum step load of around 30-35 % of its full load output without stalling whereas a typical diesel engine could accept around 65-70 %. This could lead to a requirement to further increase the installed capacity of a CHP in order to handle the load steps to which it could be subjected. Furthermore if equipment sensitive to fluctuations in supply voltage or frequency are installed on the site the load acceptance limit condition for the CHP of ‘not stalling’ will be replaced with a more stringent condition which could further drive up the size of the required CHP. Finally, the consideration of redundancy should also be considered. When a grid-connected CHP is unavailable the electricity supply from the mains is able to take over and supply the required amount of power to continue to run the site as normal. In the scenario where the grid supply to the building has been displaced by an island mode CHP this is no longer necessarily the case. If the grid supply has been retained it can still be used to supply the site in the event that the CHP is non-operational... however, this switching would not be instantaneous and would therefore create a ‘blip’ in the power supply to the site, which in many circumstances would not be acceptable. The alternative would be to install redundancy in power generation on the site so that in the event of outages for planned maintenance or caused by breakdowns the site island mode generation is still capable of handling the peaks in power demand. This could be in the form of additional CHP capacity (with the downside of causing even further reduction in CHP loading under the ‘normal’ operational scenario and further reducing efficiency) or through dedicated standby generation: though dedicated standby generation would also have a delay on start-up under unplanned CHP outages which would result in a similar ‘blip’ in power supply as would be experienced with the mains switching option. In fact there is a danger that if one CHP unit were to fail in island mode where redundancy under continuous operation was not incorporated the additional load that would be instantaneously shifted to the remaining operational CHP units would overload and stall them before the standby generation could come on line, causing a cascading effect down to a total blackout of the site. You will note from the list of problems that island mode CHP is far from an ideal solution to the grid connection problem you describe, and could in fact cause more issues, costs and payback problems than it solves. It could be considered that installing an ‘off grid’ CHP which incorporates a number of different consumers along lines akin to a private wire network could assist in counteracting to an extent the base load vs peak demand issues and the effect of demand steps by increasing load diversity.

Absolutely right! A payback period to start with but then you do need to look at CHP in great detail before spending what is likely to be a substantial amount of money. You need hourly heat and power demands across the whole year leading to a whole life economic analysis - NPV, IRR etc. There are no standard templates (see my answers on models). Sounds like you need a real CHP consultant that's done this before - try the CHPA members list.

I'm wondering why you are going to test dCHP V condensing boilers when this has already been done in the carbon trust field trial. See this presentation for the results: http://www.sbgi.org.uk/ContentFiles/Events/Micropower%20presentations/08-Kof i%20Atuh%20for%20Web%20circulation.pdf. Even though these are interim findings the results are pretty clear. dCHP only out-performs condensing where there is a large heat load. Surprise surprise - we learnt that in non-domestic buildings about 20 years ago but I'm still glad to see it thoroughly monitored and proven. Where are these domestic properties with large continuous REAL heat loads? Insulate, good controls etc., and then it comes down to the hot water load which is not going to be LARGE. Better to link houses on a small district heating scheme with a more significant CHP and some thermal storage.

Phil: Top three improvements to CHP are not always in the engine but the loads we connect to: (1) More district heating/cooling networks to pull together different building heat loads forming a more continuous year round heat demand (2) More thermal storage to smooth the loads (3) Condensing CHP to increase efficiencies into the 90’s. The top three CHP myths are (1) You have to throw LOTS of heat away (NOT TRUE - If you do then the payback will reduce) (2) District heating mains lose LOTS of heat energy (NOT TRUE - Current pipework might lose only 1 deg.C per kilometre) (3) CHP is uneconomic (NOT TRUE - CHP should be regarded as a key energy efficiency measure and can give 3-7 year paybacks in buildings with the right heat demand). David: Whilst making the comment that there is no technological reason which exists which is preventing a significant increase in the use of CHP over the next 5-10 years (these barriers are primarily financial, legislative, planning and permitting) the following three improvements in CHP technology would nonetheless be positive. (1) increase in electrical efficiency of CHP, driving higher savings both financially and in CO2 emissions, (2) improvements in engine/combustion design and engine management to facilitate tighter control of emissions, in particular NOx, to meet the likely demands for lower and lower emissions standards, in particular in city applications. Presently some manufacturers’ engines are available at a reduced 250 mg/Nm3 NOx emission standard without exhaust treatment but future requirements are likely to be for even lower levels in some applications. Note that exhaust treatment technologies to reduce emissions are often unsuitable due to space constraints, cost, or in the case of Selective Catalytic Reducers (SCRs) for reducing NOx emissions, due to the issue of ammonia carry-over in the exhaust. (3) development of gasification, and in particular the associated fuel gas clean-up technology, to enable suitable fuel gas derived from biomass or waste treatment to be delivered consistently and economically to engines. This will greatly help in meeting what is already a potentially large demand for renewable CHP installations and solutions for the direct treatment of waste diverted from landfill without resorting to incineration. Perceptions which need to change are (1) the belief which has appeared to exist in policy-makers that the potential for CHP installations in the UK will be fully realised without the need for additional legislative incentives to provide support and increased commercial certainty: potentially extending to Feed-in Tariffs to support natural gas CHP above 2 kWe for example. (2) the prime focus on Capex for CHP installations when this initial cost is massively outweighed by ongoing costs for fuel and maintenance over the lifetime of the plant: schemes should be evaluated on a through-life basis which would help ensure the installation and use of best available technology. (3) the focus on overall efficiency as the primary performance benchmark for CHP: in reality CHP units have a very similar overall efficiency but it is the balance between electrical and thermal efficiency within this which is the differentiator, with higher electrical efficiency being a significant driver for both increased financial savings and greater CO2 emissions reductions.

David: I would agree that to an extent technologies such as Heat Pumps (both Air Source and Ground Source) should be utilised in increasing quantities in the future as a very sensible and energy efficient means to satisfying our energy demands overall. However, I would not see this being a panacea which would be considered across the board as a strict alternative to CHP. Firstly, whilst 67 % CCGT electrical efficiency is technically feasible if you look at the latest data from DUKES 2009 (DUKES 2010 to be published very shortly I believe) CCGT installed in the UK at present actually achieved only 51.9% electrical efficiency on Higher Heating Value basis in 2008. This is 57.5 % on Lower Heating Value (LHV) basis. Furthermore DUKES 2009 indicates that in 2008 distribution losses in the grid overall ran at 6.9%, and if this is applied to the CCGT efficiency would result in effficiency at point of use of the electricity of 53.5 % (LHV basis). I assume that in aiming for a significant decarbonisation of the ‘grid’ you are not proposing wholesale construction of more and more new CCGT facilities to achieve the 67% efficiency to which you refer? Furthermore, if we take a slightly extreme scenario of all of the electricity produced at the above 53.5 % ‘delivered’ efficiency being converted into thermal output using the 3.5 COP for ASHP we result in 1.87 kWh of thermal output per kWh (LHV) of natural gas used. Taking a high efficiency natural gas CHP with gross electrical output of 42.9% (LHV basis), 2.5 % parasitic loads, and thermal efficiency of 43.8 % and similarly assuming all electrical output is used in ASHP of COP 3.5 the gas engine achieves 1.90kWh of thermal output per kWh (LHV). Of course, you are correct that a CCGT will have further thermal energy available for a district heating application, the difficulty typically being the location of power stations with respect to suitable heat sinks and the resulting fesibility and cost of delivering the thermal energy over distances. I think care should also be taken over the performance of Heat Pumps, in particular Air Source units. Whilst COPs of between 3 and 4 are indeed typical these are very dependent upon ambient temperature, and at low ambient temperature the COP falls away quite drastically (typical COP of around 2.0 at 0 deg.C outside ambient when used to produce DHW of around 65 deg.C), which works converse to typical requirements for thermal output - i.e. the system performs less well when demands for heat are the greatest. Phil: Interesting question but there is no simple answer to this - it is a complex subject currently being debated in the industry. However, I do know there is likely to be an article on this in the CIBSE Journal quite soon from Huw Blackwell (CHP Group). His theme is that it's all very well looking at efficiencies but temperature is key! Air source heat pumps are unlikely to produce the temperatures we require for DHW and the jury is still out on their seasonal efficiencies so are they the whole future? I believe we will still have a mixed generation capacity in 2025 and local CHP will still play a role albeit with renewable fuels. Paul Woods (CHP Group) also made a very relevant point at a recent ISES conference - that local CHP provides a highly flexible and responsive part to the generation system, particularly a future decarbonised one. Put it another way - what else will provide the load following capacity on a decarbonised grid? By the way, aren't air source heat pumps just air conditioning?

I don’t know of any life cycle models for the middle east - Carbon Descent (Chris Dunham) have developed a model that could be modified to suite but I suspect it would take quite a bit of work. The CHP suppliers may have a model that is suitable?

Phil: Engines require gases or oils as fuels and the biofuels available are starting to be installed in significant numbers. However, I would say solid biomass CHP (e.g. wood chip) is still in the development stage in the UK, particularly at the small end (> 1 MW). The idea is to gasify the solids rather like making charcoal and capturing the gases. The few smaller installations that have been tried haven't been successful. This hasn’t been the fault of the CHP, it seems to have been in the gasifier not producing the right quality of gas for the CHP. There are a few larger installations around that have achieved it - notably one in Austria but these are around the 5MW size making it more economic to ensure good operation of the gasifier. One manufacturer did have a non gasifier solution but I think that has had some difficulties too. My recommendation - biogas and bio-oils YES, biomass - be VERY careful! The one really interesting building application of biomass CHP is at University of East Anglia. This is still under construction but has the prospect of being a first for the UK. It is a fairly large installation but seems like it has a good problem-solving engineering team to make it happen. The CIBSE CHP Group had an excellent presentation on this at our conference on 28th June this year and the slides will be on the Group web site (www.cibse.org/chp) very soon. David: With respect to the first issue that you raise, it is correct that CHP based around the gasification or pyrolysis of biomass has a number of technical challenges which have led to some unsuccessful schemes. These technical challenges are by no means insurmountable as has been proven through successful schemes of the kind in particular in continental Europe. It is of course possible to establish a biomass CHP scheme using more ‘conventional” technology, such as a biomass boiler with a steam or Organic Rankine Cycle (ORC) turbine. These are without question more established biomass CHP technologies, but the downside is the significantly lower electrical efficiencies of these turbine systems compared to the use of reciprocating engines and the consequentially very high heat to power ratio. Care should be taken, however, when considering that liquid fueled engines are the better solution. Certainly the storage and fuel delivery to the CHP of liquid fuel is more simple and less space consuming and operation on these fuels is more established. Equally the electrical efficiency of a liquid fuelled engine is comparable to that of a gas fueled unit and there are fewer technical challenges to these applications than to biomass gasification with gas engine solutions. However, if the intention to such a scheme is to establish a renewable CHP system and to access support mechanisms for renewable energy such as Renewable Obligation Certificates, it should be recognised that (1) the vast majority of sources of biodiesel (even B100 spec) are not accredited under the ROC scheme as too much natural gas (i.e. fossil fuel) is used in the production of these fuels, which means that NO ROCs could be gained from such a CHP scheme, (2) running on B100 biodiesel invariably impacts adversely upon maintenance schedules compared to fossil fuel diesel, adding cost and downtime to operation. If a ‘raw’ plant oil is used instead of biodiesel to overcome the ROC accreditation issue this impact is all the greater. The key point is that it is important to recognise the pros and cons of all potential solutions when developing a CHP scheme, in particular renewable CHP. It would be fair to say that none of the available solutions are all ‘pro’ and no ‘con’.

David: I favour parallel connection because I believe it allows better sequence control with existing boilers based on an overall flow temperature sensor. However, many like series connection because it is easier/cheaper to install pipework and allows CHP to be remote from boilers but this can lead to missing control links. Ensuring CHP acts as the lead boiler is essential for good economics and carbon savings.

We are grateful to Christine Pout of BRE for providing the following response. The Part L factor is low because it only includes CO2 emissions (rather than CO2, methane and nitrous oxides as CO2 equivalent) and the scope of upstream emissions that are included is limited. A more comprehensive emission factor for rape seed oil used in the UK which included other greenhouse gases and a fuller (although not complete) consideration of upstream emissions was provided as part of the Part L consultation in 2009. This factor was derived from data used in Renewable Fuels Agency’s emission calculator for the Road Transport Fuel Obligation. There are other studies which use a more complete life-cycle assessment methodology which give an even higher emission factors for rape seed oil.

CHP Sizer is a pretty good piece of CHP software – much more than just a simplistic model and can provide a good start to any feasibility study. You can load your own profiles into this as well as using the built-in ones for certain building types. Downloadable from CHPFOCUS web site under TOOLS for those that haven’t got it. The Canadian model RETSCREEN has a CHP module available free from www.retscreen.net. I have heard of Dutch and Danish models but I don’t have any experience of them. The American simulation models DOE-2 and Energy Plus also have CHP elements. However, many of the best models have been developed by consultancies for their own use and are not publicly available. At London South Bank University we have worked with a company called Carbon Descent to develop one of the best models around but that doesn’t come free either.

I would still see a positive future for CHP under these circumstances. Smart meters and smart grid will no doubt drive a change in energy usage and an increase in energy efficiency which might reduce energy demands to an extent and make some ‘borderline’ CHP plants unfeasible. However, the sensible advice around CHP should always be to carry out energy efficiency improvements first before sizing CHP so that the demands on which the system is based are appropriate over the medium to long term. Smart meters and smart grid certainly does not run counter to this way of thinking. Additionally, smart meters could actually assist in driving forward new CHP and district heating installations. One of the factors which often holds back investment in new CHP is the risk and uncertainty which comes from having insufficiently detailed demand data for the application. Smart meters should go a long way to plugging this information gap and removing a proportion of the risk holding back new CHP installations. Furthermore, a smart grid could assist in facilitating the use of CHP along a more ‘Scandinavian’ model of running larger engines, oversized in relation to their own sites' loads, with thermal storage, and designed to operate only for a few hours a day at peak electricity demand periods where electricity exported to the grid is in demand and secures a higher tariff for the CHP owner/operator.

David: Firstly, it is always best to hydraulically separate the engine water circuit from the district heating water circuit. This ensures that there is a minimal run of pipework for the engine water circuit and a small volume of water in the circuit, which makes it easier to maintain the water quality as required by the CHP system. In order to achieve this an interface plate heat exchanger would typically be used with the engine water circuit on one side of the plate and the district heating water on the other. Typically such a heat exchanger would be designed with a minimum 5 deg.C delta T across the plate to ensure that the heat exchanger does not become too physically large and expensive, although water to water heat exchangers can be selected with as little as a 1 deg.C delta T. In this scenario the engine water circuit could be selected with a 90/70 deg.C flow and return creating a 10 deg.C delta T across the heat exchanger. I would also suggest that the engine water circuit, and the district heating circuit water flow through the interface heat exchanger, should be designed as a variable flow rate circuit in order that the flow temperature of the engine circuit and of the district heating water circuit, can be maintained at 90 deg.C and 80 deg.C respectively even at part load operation for the engine. In terms of where to locate the interface plate heat exchanger for the CHP in relation to the district heating circuit’s boilers this could either be a parallel connection or a series connection, neither of which would be ‘wrong’. The advantage of connecting the CHP in series with the boilers on the return header is that the CHP sees the full thermal load of the system and it ensures that thermal demand is not ‘stolen’ from the CHP by the boilers firing excessively. In order to ensure that the district heating circuit side of the heat exchanger does not need to be sized to accommodate the full flow rate of the entire circuit a bypass should be included across this heat exchanger - the CHP heats a proportion of the water appropriate to the thermal output of the unit which then recombines with the return water from the district heating circuit and flows to the boilers which fire as required to raise the overall temperature up to the design flow temperature of the system. Phil: Some DH systems take the water from the CHP directly into the dwelling/building heating and hot water system. However, the more common and preferred approach is to have a domestic consumer unit in each dwelling/building i.e. a heat exchanger, small circulating pump, meter and controls. This does isolate the two systems and provides better monitoring and control facilities. Guide to community heating and CHP - Good Practice Guide GPG 234 gives more detail and so will the forthcoming revision to CIBSE AM12 later this year. In a parallel connection arrangement the system does not automatically regulate itself to ensure that the CHP operates as the primary heat source and therefore additional controls will need to be put in place, but this is CIBSE’s preferred connection arrangement for CHP into a new system rather than a retrofit (although even on a CIBSE forum I have to confess that as a CHP specialist company we prefer the series connection arrangement!). For a simple visualisation of these two connection methods it might be worth seeking out the CIBSE CHP Group’s Datasheet 2 on Spark Ignition Gas-Engine CHP which illustrates both of these connection variants.

David: Ultimately all that can be done is to carry out as detailed a feasibility study as is possible, investigating all potential optimisation options such as absorption chilling, thermal storage, etc. and considering the results. Unfortunately on this basis sometimes these studies do not result in a positive conclusion. However, as you say, Leisure Centres with pools would normally represent quite a strong potential application for CHP. Given that the utilities pricing and resultant spark spread will always be a major factor in the feasibility of CHP there are a few considerations which will help in achieving the best possible results for feasibility and in operation. (1) whilst overall efficiencies are typically very similar from one unit to the next selecting a CHP with the highest possible electrical efficiency results in enhanced financial and CO2 savings as electricity is the more valuable commodity in both respects, (2) in evaluation of units look at through-life constings. Over the lifetime of a CHP the costs of fuel (driven by efficiencies of the system, especially electrical efficiency as above) and of maintenance of the CHP far outweigh the initial capital investment. Select the ‘best case’ system on this criteria. (2) obtain a long term maintenance pricing on the basis of a fully comprehensive contract so that there are no 'surprises' for the client in operation. If such an analysis does not produce the financial returns necessary to justify the project then unfortunately it is most likely one to walk away from. Phil: You need to do a detailed feasibility study to size the CHP correctly and this should be based on hourly heat and power profiles. The feasibility should take a whole life costing approach over the life of the plant including things like maintenance costs. Select the machine with the best Net Present Value (NPV), Internal Rate of Return (IRR) and carbon savings (£ invested per Tonne saved). Then you can presents a full business case to the finance director. If you haven't got the capital then get an ESCo to do the feasibility study and they may then finance as well.

David: there will always be some applications of course which are not suited to CHP and there is no sense in trying to ‘force’ a system into these scenarios. All CHP applications should, in our view, go through as detailed a feasibility study as is possible prior to any commitments being made, with the ideal being an assessment on the basis of half-hourly electricity and thermal demands from the consumer (half-hourly electrical info is often easy to obtain, thermal data with such resolution is typically not so easy to come by). In order to enhance the performance or feasibility of a CHP scheme there are a number of aspects which could be considered. (1) is there potential for the scheme to be modified to be a trigeneration installation? This makes sense primarily where there is a seasonal ‘shift’ from direct thermal demand to chilling/cooling demand and the installation of an absorption chiller enables the use of thermal output that would otherwise have been wasted. (2) can thermal storage be utilised to level out a fluctuating demand for heat and enhance the overall efficiency of the CHP by reducing heat rejection? (3) is there scope for incorporating additional heat consumers into a scheme to provide diversity of loads, add economies of scale, and access higher efficiencies and lower per kW costs for larger CHP units? (4) - can the CHP be configured to export electricity to the ‘grid’ at periods of high power demand and as a result access peak period tariffs for this power from electricity distribution companies? In this scenario peak periods would typically be for only a few hours per day and as a result the CHP scheme would need to be designed with this in mind, through over-sizing the CHP in relation to site demands and incorporating thermal storage to capture the 'excess' heat produced while the unit is running to be released gradually to satisfy the site demand when the CHP is switched off. This approach is one which is in use in Scandinavia in order to enable CHP to be applied to what would traditionally have been considered to be marginal cases. Phil: If a CHP is constantly shedding heat then it is oversized relative the building heat demand or it is being badly controlled. You should size CHP to meet a bit more than the base load heat demand and in Summer it will either modulate or dump small amounts of heat. Size it too large and the economics become poor because you dump too much heat (or modulate/shut down too much). One good way to develop a good base heat load is to add lots of different buildings together on to district heating - increasing potential for CHP.

David: This will all come down to the gas network delivering the fuel to the specific site. If the pipework in the distribution system to the site is not sufficiently sized it will simply not be possible to deliver the volume of gas required to the CHP. Your gas supplier should be able to advise what the capabilities are of the existing gas supply and indicate whether an upgrade would be required to deliver the quantity of gas that such a system would require. One thing to note is that all CHPs will have a requirement for the delivery pressure of the gas at entry to the engine's gas train. For the GE Jenbacher gas engines for example this is typically gas in the pressure range of 80-200mbar. If gas is not available at this pressure a gas booster will be required to attain it. Phil: Clearly, a larger CHP engine will draw much more gas. Will the existing gas main support the larger CHP and any other on-site uses for gas? If not then the cost of a new main has to be factored into the feasibility study economics and this could be a show stopper! Equally, you need to consider gas pressure required by the larger CHP machine - do you need additional gas boosters to increase pressure with resulting additional capital and running cost implications? Some recent Trigeneration modelling at London South Bank University (see ISES conference slides at www.cereb.org in a few days time) has shown that large developments with a summer cooling load might be a better bet for trigen than steady cooling loads like data centres. The steady cooling load might be achieved better with a very high efficiency vapour compression chiller at COP of 6 and above whereas Trigen will be better for the Winter heat and Summer cooling loads.

Yes, there are CHP sets available that can be run on bio-diesel. However, typically these units will have increased requirements for planned maintenance than would a standard diesel set. Additionally, if such an avenue is being pursued in order to access support mechanisms such as Renewable Obligation Certificates great care must be taken in the sourcing of the fuel for the CHP. This is because the majority of commercially available bio-diesels do not meet the criteria required to be classified as a renewable fuel under the ROCs scheme as natural gas is typically used in the production of the bio-diesel, and thus Ofgem categorise these fuels as fossil fuel and not eligible for ROCs. For more information and guidance please see the document “Biodiesel, glycerol and the Renewable Obligation” published 10 March 2009 and available for download on the Ofgem website.

There are a number of reasons for this, including (1) historically low utilities prices in the UK which have not ‘driven’ people to explore alternative solutions, (2) typically small ‘spark spread’ resulting in marginal returns and payback scenarios for commercial installations (3) difficulty and complexity of grid access for synchronisation and/or export (4) minimal incentives to encourage CHP installation: feed-in tariffs or similar used in a number of European countries, and in many cases not only for renewable energy schemes but also for highly efficient technologies such as fossil-fuel CHP (5) scarcity of district heating networks in the UK: reluctance of consumers to enter into such a scheme and lose their ‘freedom’

Under a fully comprehensive maintenance contract the usual availability guarantee in the industry is around 90% for a natural gas-fuelled system. Some suppliers will provide higher availability guarantees as their norm (Clarke Energy's standard is 92%) or sometimes on a case by case basis. With respect to actual utilisation rather than availability guaranteed it would be expected that a natural gas fuelled system would achieve availabilities upwards of 95%, where planned and unplanned outages and maintenance are factored into the <5% ‘downtime’.

Natural gas is in fact the most commonly used fuel in engines used in CHP plant in the UK. In section 6.3 of the Digest of UK Energy Statistics (DUKES) 2009 the table shows that in 2008 or 8,467GWh of fuel used in reciprocating engine CHP systems 6,715GWh of this fuel was natural gas - representing over 79% of the total fuel into CHP engines.

There are a number of points to raise in response to this question. (1) there is naturally a time-lag in information appearing in DUKES: by way of note, Clarke Energy has installed natural gas CHP schemes numbering in the double figures in the 300kWe to 3.3MWe range in London since the beginning of 2009, including some in commercial office applications. There is certainly an increase in interest in and demand for natural gas CHP in the capital in particular, largely in the new build sector and driven primarily by energy efficiency and CO2 emission reduction requirements within the planning regulations. (2) small-scale CHP is most likely to be fossil-fuelled, typically with natural gas. As such it does of course have its own carbon footprint. However, it should be noted that an ‘industry standard’ natural gas engine achieving an electrical efficiency of c. 36% on Higher Heating Value basis and used ONLY for electricity generation with all heat rejected still generates its electricity at a lower emission factor than the 0.54118 kg.CO2/kWh level currently issued by DEFRA/DECC for UK grid electricity. Economics would drive the unsuitability of power only applications for gas engines and would drive the CHP route, which saves further CO2 emissions through the displacement of fuel which would otherwise be consumed for heating. (3) studies have been carried out into the generation types which are displaced through increasing contributions from renewable technologies and distributed generation such as CHP: typically it is fossil fuel power stations which reduce in output (this effect can be seen in simple terms within DUKES, in particular with respect to electricity produced from coal falling as other generation sources contribute more). Therefore it can be considered that even as the carbon intensity of UK ‘grid’ electricity falls over the coming years the electricity displaced by installing CHP is not actually displaced at the prevailing emission factor, but at a higher level. (4) with reducing grid electricity carbon intensity ultimately a point would be reached where the carbon emission of the natural gas fuelled engine would be higher than the emission saved. However, assuming sufficient thermal load to take the full output of a CHP, a CHP with electrical efficiency of 36% and overall efficiency of 77% (both with reference to the Higher Heating Value of the gas) and boiler efficiency of 85% the point at which such a CHP would not deliver any CO2 emission savings would be a grid electricity emission factor as low as 0.266 kg.CO2/kWh. (5) alongside the decarbonisation of the electricity grid there is a likelihood of the decarbonisation of gas grid through the injection of upgraded biogas into the network. If the potential for this technology is realised through Feed-in Tariffs for grid injection any CHP assets installed now will over time become partially renewably-fuelled, thereby further extending the useful CO2 reducing ‘life’ of the technology.

CHP is indeed sometimes referred to as “cogeneration”. Combined Cooling, Heating and Power (CCHP) is often referred to in the UK as trigeneration. The use of absorption chillers driven by the thermal output of the system (typically hot water, steam or direct exhaust gases) is intrinsically less efficient than providing chilled output from electrically driven chillers. A low temperature hot water driven chiller typically achieves Coefficients of Performance of around 0.70-0.75 whereas a double effect chiller driven by steam or hot exhaust gases is likely to achieve a CoP of around 1.2-1.5. Compare this to typical CoPs for modern electrically powered chillers of upwards of 4.0 and you will see the contrast. This of course means that by employing an absorption chiller to displace usage of a ‘conventional’ chiller these respective performances impact on the quantity of electricity consumption displaced. However, this does not mean that CCHP is not worth doing, it just needs care in its application and implementation. There are two prime types of application where CCHP makes sense. Firstly, where there is a seasonal shift from heating to chilling demand - in this kind of scenario a CHP system optimally sized for heat and electricity demands, typically in the winter months, could be rejecting significant quantities of ‘waste’ heat in the low demand summer months hence adversely affecting the economic and emissions reduction case...or the CHP could even be switched off and lie idle for extended periods of time. If a chilling demand exists during these periods of low direct thermal demand a CCHP solution could well be optimal, allowing the installation to continue to operate at best possible efficiencies, rejecting the minimum amount of waste heat, and can also provide a more attractive overall solution that ‘artificially’ downsizing a CHP system to match summer thermal baseloads. Secondly, where there is a very stable, continuous chilling load on an application which would not otherwise suit CHP - a traditional example of this kind of scenario would be a conmputer datacentre. Whilst overall ‘efficiency’ of the system would be lower than for an electricity and heat only system, in this kind of application no direct thermal demand exists as such to employ CHP. In this case it is highly possible that the benefit of displaced electricity consumption from the power generation of the CHP and from the chilled output from the absorption machine will provide sufficient financial and emissions savings to make for a viable scheme. Of course all of the above must be met with the proviso that any and all applications for CHP or CCHP should be carefully evaluated in as much detail as is possible on a case by case basis - there is no susbtitute for a comprehensive feasibility study to determine whether such a scheme makes sense and to select the most appropriate technology and output size.

Personally, I'm not a great believer in single dwelling CHP because there isn't generally a year round steady heat demand. When you run the numbers, CHP viability mainly comes back to a good year round heat demand. I don't see it as excess heat, better to view it as - where is the useful heat load? If no steady heat load then don't put CHP in! So micro single building CHP is not something I would generally recommend except a large house in the country or one with a swimming pool. Better to tag onto a district heating system where possible. However, MINI CHP is being installed in significant numbers into elderly people's homes and sheltered housing (mini district heating) and this can be a good approach as there is a useful year round DHW heat demand. Show me the heat load!!! Off-grid applications - well maybe but when there is no heat demand the machine switches off or has to dump heat and you reduce viability. Sounds like a very big thermal store to me! Swimming pool - ideal!

I am the person responsible for both the creation and operation of the University of Dundee’s 3.1 MWe gas fired CHP plant. This installation has operated continuously since 1996 and the engines have amassed 300,000 running hours between the three sets. The installation which features Jenbacher 3020 engines was the first of its kind in the UK and was the first CHP installation undertaken by the then fledgling company ‘Machine Manpower Management’, now known as Clarke Energy Ltd. The plant can rightly claim to be a success story and during the years new ways of utilising the available heat have been developed. We now have absorption chilling providing year round comfort and process cooling to a major life sciences development, whilst the lowest grade heat from the lube oil coolers and 2nd stage turbo intercoolers is used to heat the two newest teaching buildings on the Campus. This novel use of 45 deg.C heat earned the University a 'Green' award. Times change and the energy needs change with them so with an eye to the future we are now contemplating increasing the electrical capacity by adding a 4th engine but of also enhancing the thermal fit by including a 100 tonne thermal store as part of the heat recovery system.

I’d make the general comment that you should take all reasonable steps to minimise energy use through conservation/efficiency measures before seeking to meet the remaining demand by CHP. This will reduce the energy content of the building and the final decision whether or not to proceed with CHP will then be determined by economics, which vary significantly with changes in gas and electricity prices. A sensitivity analysis should be done to assess the risks of future changes in fuel prices.