Industrial-scale CHP delivers many significant benefits derived from its inherently high energy efficiency and operational flexibility, but installation costs can be high. James Hunt takes a look at how industry around the world uses cogeneration systems, and how environmental and energy cost pressures seem likely to increase its take-up.

The arrangements and benefits of industrial-scale cogeneration are well known. Plants typically comprise gas turbine(s) with a heat recovery boiler (for hot water or low temperature steam) or a heat recovery steam generator (HRSG) using the gas turbine exhaust to generate high pressure, high temperature steam, which can then drive a back pressure steam turbine and/or provide steam/heat for various processes. Another arrangement is the steam–electric power plant with steam extraction from a condensing turbine. For smaller plant, typically 2–20 MW, diesel or (cleaner) lean burn gas reciprocating engines can be used.

The benefits are significant and include far better use of the fuel energy to 80%–85% (or better) thermal efficiency and greatly reduced exhaust emissions – carbon dioxide (CO2) emissions can be more than halved, but nitrogen oxide (NOx) and sulphur dioxide (SO2) emissions are also significantly lower. Moreover, because cogeneration lends itself to distributed generation (DG) (being situated near the user), loads on existing power transmission systems can be reduced, negating the need for expensive upgrades or new transmission lines.

This Siemens steam turbine is typical of machines using steam generated by gas turbine exhaust heat in cogeneration plant
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In addition, there is a need for improved security of power supply. Cogeneration can help, as plants are often installed and operated by the electricity user and can be maintained to provide more dependable power.

For various industrial power applications, cogeneration has been providing a more thermally efficient way of converting increasingly scarce fossil fuels (mainly natural gas) into electrical energy, with excess heat fully utilized for processes. Such plant can also work well using waste gases/biomass as fuel.

Cogeneration is ideal where existing industrial facilities are being expanded, older steam-generating equipment is being replaced or for new facilities. It may also be the best option when there are unstable energy prices.

Most cogeneration plants are relatively small, being operated by smaller independent companies. Such plants, rated to suit particular thermal and/or electricity demands, could provide increased competition in the production and sale of electricity.

Cogeneration in industry

According to Nick Burchett, marketing manager of Dalkia plc, the number of industrial cogeneration units as a proportion of the total number of industrial energy plants in Europe currently represents only around 10%–15%. This is mainly because organizations are unwilling to invest in new cogeneration plant due to the fluctuating price of gas and electricity, and poor industry conditions. However, Nick reports a ‘big upsurge’ in cogeneration interest over the past two years because of corporate responsibility awareness, the increasing need to reduce carbon footprints and rapidly escalating fossil fuel costs.

Inside the control room at AstraZeneca’s Dalkia cogeneration plant at Macclesfield, UK
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There is also growing interest in using on-site fuels derived from waste products (e.g. wood chips) and biogas produced from the anaerobic digestion of sludge waste. This is generally true of the global situation though with variations. Germany, for example, is well ahead of the UK and most other countries in adopting cogeneration.

In terms of load arrangements, the biggest industrial share goes to gas turbines supplying exhaust heat to steam turbines as back-up, using HRSGs, or providing heat to package boilers to provide steam for processes and/or heating and drying operations. Dalkia, for example, undertakes considerable work matching electrical/heat loads to variable demands, with supplemental boilers managing peak heating loads. The company currently manages around 850 cogeneration plants (gas/steam turbines, and reciprocating engines) with a total generating capacity of 4255 MWe.

Modern cogeneration plant is clean in every sense of the word
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Industrial cogeneration plants range from <1 MWe (sometimes just a few hundred kW for gas reciprocating engines used in water/sewage treatment plant) up to a maximum of 250 MWe for very large petrochemical plant (one or two are even bigger); the average is 12–20 MWe.

Tables 1 and 2 – from Digest of UK Energy Statistics 2007 (DUKES 2007) published by the Department for Business, Enterprise and Regulatory Reform (BERR) – show total UK cogeneration usage and capacity in 2006. It is likely that the mixes shown are broadly similar globally. There is increasing demand for cogeneration plant in the UK to meet QA rules1 so as to gain exemption from the Climate Change Levy (CCL).

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Disincentives to cogeneration

Despite its many advantages, industry has been slow to take up cogeneration. One reason is that cogeneration often has a higher capital cost than equivalent simple cycle plant. Payback periods may be 12 years for large cogeneration plants or four years for small plants. So despite the higher fuel efficiency, conventional plant is often preferred. However, the greater numbers of cogeneration plant installed, modularization (where possible) and technological developments will reduce the price differentials.

Another disincentive concerns the artificially low electricity price that many large centralized conventional power plants benefit from through government subsidies. This can be significant, especially as high environmental costs of conventional plant are not included in the electricity price. Cogeneration is at a disadvantage because deregulation aims to reduce electricity prices, so selling excess energy to the grid can become uneconomic.

Furthermore, if the plan is to sell excess cogeneration energy to the grid, regulations tend to favour large centralized power plants. This has been a major disincentive to using CHP in the USA. Even when allowed to, it can also be expensive to connect to national grids. Regulatory frameworks need to be addressed to improve large-scale cogeneration take-up. Even so, fast-increasing fuel costs are helping and Perkins Engines Company in the UK, for example, has seen a doubling of its reciprocating engine sales for cogeneration over the past year for this reason alone.


Small-scale tailor-made cogeneration plants have high capital costs, but serial standardized production can reduce this. For example, Finnish company Wärtsilä Biopower has focused on sawmills and district heating because of the suitable heat demand characteristics. It selected two nominal sizes for standardization of cogeneration production – the BioPower 2 and BioPower 5 plants. The boiler is the same for each, but varying process needs are met using different turbines.

Such modular design requires a standardized process and layout. For example, the feed water pump module, containing two pumps and around 50 valves, is pre-assembled in the factory together with instrumentation, cable preparation and flange connections.

Biomass-fuelled cogeneration power plants designed for independent power producers (IPPs) can, says Wärtsilä, be standardized ‘only up to a point’ because fuel treatment and storage systems, as well as emissions limits, vary from project to project. Wärtsilä’s target is for 50%–70% of plant construction to be standardized, the rest being to customer requirements. Benefits include lower equipment and installation costs, shortened delivery times and 50% shorter installation time.


Industry needs long-term certainty to make long-term investments. COGEN Europe ( sees a ‘double benchmarking’ approach as ideal for the next phase of the EU Emissions Trading Scheme (EU ETS). Double benchmarking would reward companies that invest in energy-efficient low carbon technologies. Directive 2004/8/EC requires the definition of benchmarks for heat and electricity production. These, published in Commission Decision 2007/74/EC, represent best practice and could be used in the benchmark setting for the EU ETS.

COGEN Europe says that EU ETS should rely on hot water, steam, heat and electricity production benchmarking instead of using historical emission figures to determine allocation. It could also take into account the fuel type and type of heat generated (warm water/process steam etc). Heat and electricity benchmarks should be expressed in terms of kg CO2 per unit of heat and electricity (typically MWh).

Benchmarks would need to be reassessed regularly to account for technological advances. COGEN Europe also sees advantages in having standard load factors determined by industrial sectors for new entrants for a couple of years from start of operation. Many countries (Germany and Italy in particular) have already successfully implemented such an approach, but the UK has used a standard load factor for new entrant cogeneration plant based on existing installations.

Unfortunately, this has resulted in severe under-allocation for cogeneration new entrants in various sectors, but a large over-allocation for plant running for a fraction of the year.

Cogeneration choices

Many aspects require careful examination by owners/operators when choosing what type of power plant to use. When planning a cogeneration plant, it may be necessary to examine performance parameters of competing plants to assess the efficiency of cogeneration systems. Too often, a cogeneration plant may be chosen solely on the basis of the expected peak or average annual load as the base condition. Even if utility factors are included, such an analysis may not be fully representative because successful cogeneration depends on correct estimation of load variation and accurate prediction of demand.

Proper economic evaluation requires a much greater understanding of load variability, as well as how the planned system will meet this load efficiently. Therefore, accurate information is needed about application type, annual energy demand, heat/electricity ratio, daily load factor and aggregated annual heat/electricity demands – plus monthly (and even weekly or hourly) patterns – so as to perform successful computer simulations.

Operators of cogeneration plant now have prime power options. Until recently, gas turbines fuelled by natural gas were the obvious choice (they still are for large plant), but advances in reciprocating gas engines have made them alternatives. For base load operation, gas engines are now more efficient than gas turbines; they also provide better flexibility for frequent starting, stopping and load changes. Moreover, the electrical efficiencies of gas engines in this mode are clearly higher says engine manufacturer Wärtsilä.

The largest gas engines are typically around 6 MW output (60 MW multi-engined). At 60 MW, turbines and gas engines are probably economically equivalent. For smaller plants, the power/heating need is typically 10 MW. Gas engine investment costs are lower than for gas turbines, so they compete directly.

If high pressure steam is needed, gas turbines are probably more economical; for hot water, gas engines may be more so. Gas engines also have lower CO2 emissions per unit of electricity generated.

Cogeneration operation in practice

The following examples provide a snapshot of current cogeneration applications in industrial applications.

Thermal efficiency is not the only criterion

In a cogeneration application powered by a gas turbine at Blackburn Star Paper Mill in the UK, the prerequisites were operational flexibility and very high availability. An Alstom GTX100 gas turbine, with steam turbine in combined cycle mode, supplies up to 59 MWe, plus 28 tonnes/hour of steam to the paper mill.

The CHPQA score2 is checked daily, helping to optimize plant operation. An availability of 99.2% has been achieved (the target is 95%), but it is the plant’s flexibility (load shifting, reduced load and shutdown) that is crucial for commercial success.

Cogeneration brings cost savings and ‘green’ benefits

Avecia’s Grangemouth site in the UK manufactures many different chemicals. Cost savings and environmental improvements were required without using company capital. Dalkia Utilities Services was awarded a 15-year contract energy management (CEM) agreement, including £6.5 million capital investment for a new 7.5 MW cogeneration plant. Steam/electricity is metered through an Energy Supply Agreement (ESA).

This computer-controlled plant consists of a 4.5 MW gas turbine genset whose exhaust gases pass into a supplementary/auxiliary fired waste heat boiler raising 30 tonnes/hour steam. This steam passes through a 4 MW backpressure steam turbine and is delivered to the process at reduced pressure. The waste heat boiler provides optimum availability and flexibility; three other boilers provide top-up/stand-by steam. Benefits of the CEM agreement include:

  • reductions in CO2, SO2, NOx and particulate emissions of 51%, 66%, 63% and 99% respectively
  • energy savings
  • better supply quality
  • access to major capital investment.

Biomass-fuelled modular cogeneration

A standardized cogeneration plant supplied by Wärtsilä Biopower to a sawmill in Vilppula, Finland, produces over 800,000 m3 of timber/year, with residual bark fuel providing 300 GWh of energy.

The plant contained a BioPower 5 HW unit (2.9 MWe + 9 MWth using a natural circulation water tube superheated steam boiler with an axial impulse backpressure steam turbine) and a BioEnergy 9 unit (9 MWth, thermal energy only from a hot water boiler). It covers all the heat demand of the drying kilns, plus providing local municipal heat, as well as 70% of the sawmill’s electricity demand. Around 60% of the sawmill’s wood bark is converted to 23 GWhe and 132 GWhth energy.

The BioGrate combustion technology obviates the need to pre-dry the fuel. Similar plants in Finland, Ireland, Sweden and Germany have shown significant savings in the delivery chain.

Large biomass-fuelled cogeneration

The Europac Portucel Viana paper mill and recycling factory in Portugal produces materials for the manufacture of corrugated cardboard on a huge scale by transforming 720,000 tonnes of wood and 109,000 of recycled products each year. Pine wood and eucalyptus branches are fired in a new biomass boiler for steam and electricity generation, though most is used for product.

Ensuring that the plant meets stringent environmental guidelines is crucial. A Rolls-Royce industrial RB211-GT61 gas turbine-powered genset, along with a steam turbine, produces around 27 MW. This provides all the plant’s electricity needs and the excess is sold to the grid. The gas turbine has achieved over 99% availability – vital in avoiding serious paper quality issues.

Cogeneration helps plants grow

Gas reciprocating engines in cogeneration mode are ideal for certain large commercial greenhouse applications. For example, Rolls-Royce’s G4.2 engine is helping large-scale vegetable growers to increase their yields by feeding carefully controlled and cleaned quantities of exhaust CO2 into the greenhouses. Cogeneration electricity provides lighting for the crops, while system heat keeps them warm. Excess electricity is sold to the grid.

The future

Greater adoption of cogeneration will need reduced maintenance requirements and running costs, longer lifetimes and lower capital costs. But as long as demand continues for emission reductions and fuel efficiency improvements, there should be a greater need for cogeneration plant in industry and elsewhere – despite the inhibitors mentioned above. There will be more trigeneration and increasing use of biomass/biogas, especially using any combustible waste by-products from production processes.

Even so, John Charlton Rolls-Royce’s Marketing Solutions Engineer (Industrial Power) says that, in order for the sale of electricity from cogeneration to be successful, it must be more operationally flexible to the grid (during the night, for example, when prices are low). This means using aeroderivative gas turbines (gas engines for smaller plant) rather than industrial gas turbines, which are inherently inflexible.

The future will also see greater take-up of alternative power sources such as CFC Solution’s (MTU) HotModule fuel cell (to 500 kW/unit), already in use in small industrial and other applications. These units are efficient and extremely clean.

The spread of cogeneration fuels is increasing (Table 3). Now predominantly fuelled by natural gas (around 70%), today’s operators are looking hard at alternatives including fuel oil (2.9%), coal (3.5%), renewables (2.5%, including waste fuels and biofuels). This is growing fast. ‘Other’ fuels represent 13% of the total.

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Cogeneration could help the EU meet its long-term CO2 reduction targets. The EU ETS should be an increasing driver for cogeneration take-up, though fuel price rises may have a bigger effect. The EU ETS encourages greenhouse gas reductions in the most cost-effective way, and cogeneration allows for potential economic expansion while cutting carbon emissions. COGEN Europe is keen on the EU ETS in terms of cogeneration and the framework set by the Cogeneration Directive (2004/8/EC) – harmonization, effectiveness, fairness and transparency.

Compared with conventional transmission grids, distributed generation can dramatically increase the overall efficiency of energy use – transmission losses can be 6% of the electricity used. Full DG benefits may be achieved using cogeneration – more potential business a decade or so ahead.

Integrated gasification combined cycle (IGCC) technology may improve electricity generation efficiency using coal or other hydrocarbon fuels, yet with far lower emissions than existing coal-fired power plant. IGCC is suitable for very large cogeneration applications, especially as fuel flexibility is good and there is CO2 recovery.

James Hunt is a UK-based writer on energy and electrotechnical issues


1. Quality Assurance (QA) certification for UK cogeneration schemes brings exemption from the Climate Change Levy and business rating, and access to Enhanced Capital Allowances (ECAs).

2. Installations must meet criteria set for good quality for the purposes of the UK ECA scheme as set out in the Combined Heat and Power Quality Assurance Programme (CHPQA).

Back to basics – advantages of CHP

Large centralized power plants have been the mainstay of electricity production across the world but, while reliable and quite cost-effective, their efficiency is low. For a steam cycle plant, the overall thermal efficiency is only 30%–35%. For a simple cycle gas turbine plant it is around 30% and, even for a combined gas turbine-steam cycle plant, it is only 50%. The rest of the fuel energy goes to waste. This is expensive and leads to an increase in carbon dioxide emissions, the main greenhouse gas causing global warming.

Cogeneration – or combined heat and power (CHP) – raises the overall thermal efficiency significantly to around 80%–85%. Although less of the available fuel energy may be converted into electricity, the production of both electrical and thermal energy results in the higher overall efficiency. Typically, cogeneration will convert up to 35% of the fuel energy to electricity, with another 50%–55% being produced as steam/hot water, though this can be varied. A third stage, absorption refrigeration (trigeneration), produces still greater fuel efficiency.