|Siemens planned combined-cycle gas-fired power plant in Gorzow, Poland Credit: Siemens|
Due to fundamental laws of physics, the energy conversion processes needed to supply useful forms of energy to modern economies inevitably cause losses of energy. For a number of reasons, including economy, environment protection and sustainability, all developed countries undertake considerable effort to reduce such losses. Combining generation of electrical power and heat in a common technical process provides one of the most important opportunities for reducing such losses, because it enables using inevitable heat losses from heat engines in a useful manner. The great potential of combined heat and power (CHP) technologies has been acknowledged in many pro-efficiency initiatives on a national and international level. In particular, it is extensively discussed in the EU’s newest Energy Efficiency Directive (EED).
While cogeneration is by no means a new concept, its market penetration is still not very high. The EED declares that ‘High-efficiency cogeneration and district heating and cooling has significant potential for saving primary energy, which is largely untapped in the Union’. In fact, as of 2011 (the newest data published by Eurostat), only 11.2% of electricity generated in the EU-27 came from CHP plants. More importantly, this value had not changed for the previous five years. CHP’s share in heat supply is not very high, ranging from 0% in Malta to more than 35% in Finland, with the average at just above 15%. This clearly shows that there is still huge potential for combining generation of both energy forms and thus improving the overall energy efficiency of European economies. At the same time, this situation proves that there are certain obstacles preventing easy development of combined heat and power.
One of the essential challenges in developing combined heat and power generation is the heat demand pattern. Let’s consider a typical case from Poland, a central European country where district heating (DH) is popular. Figure 1 shows a typical heat demand curve from a Polish city. It can be easily seen that, during a considerable part of the year, demand stabilises at a very low level, typically below 10% of the maximum demand observed during a year. This is a period when room heating is not needed due to high ambient temperatures, and when district heating systems only operate to provide domestic hot water. But this means that the absolute base load of district heating systems is below 10% of their maximum load, and only covers 30% of the total heat supply (value obtained by integration of the load-duration curve shown in Figure 2). This is therefore a natural limit on heat supplies from strictly baseload heat sources, CHP or otherwise.
|Figure 1.Typical annual heat demand pattern of a Polish district heating system. Zero demand around 5700 h is caused by maintenance and is not a feature of a typical load curve|
|Figure 2. Same data as in Figure 1 converted to the heat load duration curve|
It is important to mention here that the EU legislation calls for promoting only cogeneration characterised by high annual efficiency. There are specific minimum thresholds introduced: 75% of annual average efficiency for simple cycle CHP plants and 80% for combined-cycle plants. These threshold levels are not much lower than practically achievable nominal values. This in turn means that CHP is only to be encouraged (i.e., supported) if no major amounts of heat are wasted. This effectively prohibits any operation of a CHP system in a way which would result in generation of heat which cannot be consumed.
All this means that strictly baseload CHP plants may only cover 30% of the total heat demand from municipal DH systems. If a larger portion of the heat demand is to be covered, then the CHP source will not be able to operate on a baseload regime. In other words, if more than 30% of the total heat demand in a certain DH system is to be covered by CHP, then the capacity utilisation factor (both for electrical and heating capacity) will have to be reduced from maximal technically possible values (which today easily exceed 90%). The only solution to this problem could be provided by implementation of long-term energy storage systems, able to store extra heat generated during summers to be used in the coldest seasons when the heat load exceeds the capacity of the CHP system – but such systems are not commercially available today.
Covering more than 30% of the total annual heat load with CHP may be therefore accomplished in one of three ways:
- 1. Constructing separate plants for covering base heat load and intermediate load, the latter with an annual equivalent operating time of some 4500–5000 hours. Both plants would be operated almost exclusively at full load;
- 2. Constructing one CHP system, able to operate at partial loads during summer;
- 3. Constructing one CHP system, able to operate in daily cycles during summer, coupled with short-term heat storage.
Generally speaking, the first approach could lead to increased investment cost, and the profitability of the intermediate part would be affected by low capacity factors. The second solution requires appropriate design (allowing for low load operation), and also might affect maintenance costs (as part-load operation tends to wear the equipment faster). Solution number three is potentially best, as it is the only one which enables compensating for the lowered capacity utilisation factor with sales of one of the products (electricity) at higher prices, using intra-day market price fluctuations (if such fluctuations are actually observed on the market in question). But it should be noted that, at the same time, this solution may only be effectively implemented using a very flexible CHP technology, capable of rapid starts and stops and invulnerable to them in the longer term. It may also be noted here that a solution featuring multiple parallel CHP units within a single plant may combine all three philosophies, providing the operator with additional flexibility in adapting to changing market conditions. But, in any case, if CHP plants are to supply a high share of heat and electricity in a certain national system, they will not be able to utilise their capacity to its full technical capabilities (except for cases with industrial heat consumers).
A separate challenge is of a purely economic nature. CHP plants are typically more expensive than ‘pure’ power plants with the same output, as they require extra equipment for heat recovery. Of course, in return they generate an additional flow of revenue from heat sales. Unfortunately this additional flow does not necessarily compensate for the extra cost involved, especially in that CHP plants tend to have poorer electrical efficiencies than their electricity-only counterparts. This results, firstly, from their distributed character (smaller plants do not achieve the high efficiencies of large state-of-the-art power stations), and secondly from the technical conditions of the process (lowered electrical output when heat recovery is used – although this only applies to technologies using a steam cycle, and does not affect the internal combustion engines popularly used in gas-fired CHP plants).
Case study: Poland
Poland is an EU Member State with a better-than-average share of combined heat and power generation: CHP plants are responsible for some 17% of power generation and 18% of heat generation. These values indicate that there should still be ‘free space’ for combined heat and power, even in the strictly baseload category. This is confirmed by recent studies. It has been calculated that the current market potential for CHP systems in municipalities which do have district heating systems but have not yet installed any CHP is around 1.5 GW of strictly baseload systems. Nevertheless, this potential is not being converted into actual projects.
The reason is simple: new CHP plants are not feasible due to a combination of economic and political factors. The two most essential factors are low wholesale electricity prices and the expected transition from coal to natural gas in the local district heating sector.
Poland’s current wholesale electricity prices are very low. The price of power actually sold by Polish CHP plants has stayed below PLN200 (US$60)/MWh during the last few years. Over this period the electricity price has been dropping due to the Polish power system’s domination by old coal-fired power stations, built before the introduction of a market economy. This means that they only reflect the current operating costs of producing electricity from coal and lignite, which are very low.
Of course this creates serious obstacles for funding any new power projects, which has been demonstrated by a long struggle between state-owned utility PGE and the Ministry of Economy over new coal-fired units in Opole. The government insisted that these plants will be necessary to ensure security of supply following phase-out of some of the oldest generation units, while PGE argued that new plants’ feasibility cannot be successfully demonstrated. This case ended with the use of extraordinary state aid for the project, subject to European Commission approval.
This case indirectly indicates that CHP plants running on coal would also not be feasible. The plant mentioned above is an ultra-modern supercritical 2 × 900 MW project with efficiency levels around 45% and a total cost of PLN11.6 billion (which means that the cost of 1 MW of installed capacity was PLN6.44 million). If this plant was not feasible without extraordinary support measures, it is difficult to expect that a CHP unit with an electrical efficiency of some 30%, total efficiency of 80% and a similar investment cost could possibly be. And using coal blocks many potential opportunities for obtaining additional funding.
Gas-fired CHP projects are considered worth subsidising, as has been demonstrated by several projects. They are seen as a way to improve energy efficiency while reducing industry’s carbon footprint at the same time due to the much lower emissivity of gas. Unfortunately the economics of such projects are much less favourable.
At present, Polish gas prices for industrial customers are around PLN37/GJ, i.e., some PLN135/MWh. Even if we consider a relatively large CHP plant (at a scale of 100 MW or more), we can reasonably expect electrical efficiencies not exceeding 50% and total efficiencies of some 85%. This means that each MWh of gas may be used to generate 0.5 MW of electricity (worth PLN100) and 0.35 MWh of heat. The value of heat is not so easy to determine as it varies considerably between local systems, but it can be assumed at PLN30/GJ = PLN108/MWh. This means that, ultimately, gas worth PLN135 may be converted to final energy forms with a total sales price of slightly below PLN140. And we haven’t yet considered any plant maintenance costs, not to mention paying for construction in the first place! No detailed feasibility study is needed to prove that there is absolutely no way to generate profit in this way.
Of course it can be argued that these circumstances will not remain so unfavourable forever. In fact, we can be certain that they will improve sooner or later. After all, if today’s power-to-fuel price ratio is insufficient for any kind of power plant investment, it will have to grow to ensure construction of new capacity at some point in time.
In 2013 a renowned Polish engineering and technical advisory company, Energoprojekt-Katowice (EPK), carried out a detailed forecast of Polish electricity prices using the Plexos advanced modelling software suite. Three different price projections were created, depending on assumed prices of CO2 emission allowances within the EU Emission Trading Scheme (ETS) (see Figure 3). Then three more variations were made, assuming that the shutdown of the oldest Polish coal-fired units, currently scheduled to occur by 2017, could be postponed. The resulting electricity price curves were later used to investigate the feasibility of gas-fired CHP plants based on different technologies (internal combustion engines and combined-cycle gas turbines).
|Figure 3. Annual average electricity prices on the Polish wholesale electricity market, obtained by a Plexos simulation carried out by Energoprojekt-Katowice. The peak in 2017 is caused by scheduled decommissioning of numerous power units due to their excessive emissions.|
In all cases, regardless of the power system development scenario or operating profile of the CHP plant (two different options were investigated, maximising either overall annual efficiency or electricity sales), the results of the analysis are clearly negative (see Table 1). The financial performance of plants without any incentive system is so poor that it is safe to declare that, without some incentive mechanism, a gas-fired CHP station which sells electricity to the market may not be feasible.
|Table 1. Results of a comparative feasibility analysis for three different solutions of municipal CHP plants without any CHP support mechanism carried out by Energoprojekt-Katowice. All plants are assumed to operate in heat-load following regime (i.e., maximisation of annual average efficiency)|
Adam Rajewski is Sales Manager at Wärtsilä Polska. Maciej Skwara is a student in the Faculty of Power and Aeronautical Engineering at Warsaw University of Technology.