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Research Papers: Energy Systems Analysis

Increasing the Flexibility of Combined Heat and Power Plants With Heat Pumps and Thermal Energy Storage OPEN ACCESS

[+] Author and Article Information
Eike Mollenhauer

Institute for Energy Engineering,
Technische Universität,
Berlin 10587, Germany
e-mail: eike.mollenhauer@iet.tu-berlin.de

Andreas Christidis

Institute for Energy Engineering,
Technische Universität,
Berlin 10587, Germany
e-mail: christidis@iet.tu-berlin.de

George Tsatsaronis

Institute for Energy Engineering,
Technische Universität,
Berlin 10587, Germany
e-mail: tsatsaronis@iet.tu-berlin.de

Contributed by the Advanced Energy Systems Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received January 9, 2017; final manuscript received October 10, 2017; published online November 30, 2017. Assoc. Editor: Tatiana Morosuk.

J. Energy Resour. Technol 140(2), 020907 (Nov 30, 2017) (8 pages) Paper No: JERT-17-1012; doi: 10.1115/1.4038461 History: Received January 09, 2017; Revised October 10, 2017

Combined heat and power (CHP) plants are efficient regarding fuel, costs, and emissions compared to the separate generation of heat and electricity. Sinking revenues from sales of electricity due to sinking market prices endanger the economically viable operation of the plants. The integration of heat pumps (HP) and thermal energy storages (TESs) represents an option to increase the flexibility of CHP plants so that electricity can be produced only when the market conditions are favorable. The investigated district heating system is located in Germany, where the electricity market is influenced by a high share of renewable energies. The price-based unit-commitment and dispatch problem is modeled as a mixed integer linear program (MILP) with a temporal resolution of 1 h and a planning horizon of 1 yr. This paper presents the optimal operation of a TES unit and a HP in combination with CHP plants as well as synergies or competitions between them. Coal and gas-fired CHP plants with back pressure or extraction condensing steam turbines (STs) are considered, and their results are compared to each other.

FIGURES IN THIS ARTICLE
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The increase of renewable energy supply reduces the average spot market price of electricity and highly influences the price trend over the day, week, and year [13]. When wind is abundant or a clear sky is present on a summer day, the electricity prices are at a very low level, especially during periods of low demand. This reduces the business motivation to run a combined heat and power (CHP) plant, although the district heat has to be supplied at all times. Thermal energy storages (TESs) and heat pumps (HP) increase the flexibility of an energy system and enable an adaption of the heat and electricity production to the market conditions [46].

In Germany, the energy policy stipulates for the energy transition that, “the electricity generation from CHP is to become more responsive to the price signal, and thus more flexible. To make this possible, larger heat storage units are needed so that the unchanged level of demand for heat can be met despite the flexibilization of electricity generation.” [7]. Therefore, the investment in thermal energy storages for district heating is subsidized by the government in Germany since 2012 [8], and several projects were realized in recent years, see Table 2.

Heat pumps represent a thermodynamically efficient option to couple the electricity sector with the heat sector. If these are powered by electricity generated from renewable energies, fossil fuels are replaced in the heating sector, and carbon emissions are reduced. Especially in times of high renewable electricity generation and local surplus when wind farms or photovoltaics have to be switched off, it is beneficial to use the excess electricity for heating. Although direct electrical heaters have lower capital costs compared to heat pumps, they are only a temporary option for German politicians, due to climate-related and efficiency reasons [7].

Methodologically, mixed integer linear programs (MILPs) are often used to determine the optimal unit commitment of power and cogeneration plants, thermal energy storages and heat pumps. The benefits of thermal energy storages in district heating systems are investigated for example in Refs. [913]. Large-scale heat pumps are one possibility to electrify the heat supply and are already installed in some district heating systems, especially in Northern Europe. Nevertheless, heat pumps in district heating networks are a current field of research [1417], together with the integration of the increasing volatile electricity generation from renewable energies.

The aim of the paper is to analyze the dependence of the operation strategy and the possible benefits of TES and heat pumps for different CHP plant types with the current market conditions in Germany. After a short description of the analyzed energy systems and the main parameters of the mathematical optimization model, we present the operation and benefits of a thermal energy storage (Sec. 3) and a heat pump (Sec. 4) based on the German electricity prices of 2015. Installing both in one district heating supply system, could increase or decrease the advantage of each unit, as shown in Sec. 5.

The analyzed system consists of two or three identical CHP units, a gas-fired boiler for peak loads, and, optionally, a thermal energy storage unit or a heat pump as shown in a simplified flow chart in Fig. 1. The CHP plants can deliver up to 50% of the maximal heat demand of the system, and the thermal energy storage unit is sized to buffer 2 h of maximum heat supply from the CHP units.

The cost-optimal operation of the different units in the energy supply system within 1 yr is determined with a MILP. The model is solved with the commercially available solver “IBM ILOG CPLEX Optimizer,” and considers the hourly electricity prices and the heat demand in the district heating system. The heat demand, which has to be fulfilled in each hour, is derived from the load curve of an existing district heating net in Germany and scaled to 1200 MW peak load. The optimization maximizes the profit contribution, which consists of the electricity revenues minus the variable costs within 1 yr. The considered costs are the fuel, emission, and start-up costs of the different units, taxes and surcharges, and expenditures for electrical power consumption from the net. As the effects of the thermal energy storage and the heat pump are analyzed, the differences between the results with and without these additional components are evaluated. The heat supply to the district heating network is the same in both cases, so that the associated revenues are identical and do not influence the difference that defines the effect of the storage or the heat pump. Therefore, the revenues from heat supply do not have to be included as input data.

A short overview of the model is given in Fig. 2, which lists the main properties. Technical restrictions like the feasible operating area and efficiencies of CHP plants (see Fig. 3) or limitations of the heat pump are described in Secs. 2.12.3. A comparable model is used and described in Refs. [1820]. An illustration of the results from the optimization can be found in Fig. 4, which shows the different unit commitment and operation as well as the main parameters: heat demand, price of electricity, and district heating supply temperature.

CHP Plants.

Combined heat and power plants (PPs) can be categorized according to different criteria. This work differentiates between gas-fired and coal-fired plants, and the type of heat extraction from the steam turbine (ST): (extraction) back pressure ST or extraction condensing ST. The characteristics of the CHP plants are based on detailed thermodynamic simulations executed with the software ebsilon professional. The simulations are presented in Refs. [20] and [21]. The results are shown in Fig. 3 where the feasible operating regions of the plants are indicated in a power-to-heat diagram (PQ˙ diagram). The left diagram (a) shows the possible operational area for the gas-fired combined cycle power plant (CCPP) and the coal-fired steam PP, both with an extraction condensing steam turbine. These plants have a conventional condenser and a steam turbine with extractions so that it is possible to feed a variable amount of steam to the heating condensers connected to the district heating system. For constant fuel consumption, the steam extraction reduces the power production of the turbine which results in the slope of the maximum and minimum load boundary in the PQ˙ diagram for increasing heat extraction. The power reduction induced by the heat extraction defines the power-loss-coefficient and depends on the required supply temperature of the district heating system. High supply temperatures lead to an increased power loss because more steam has to be extracted on a higher pressure level from the steam turbine. The influence of the temperature is indicated in Fig. 3 by the dotted lines, which show the feasible operating area for a an increased and decreased supply temperature. Both units can extract up to 300 MWth for the district heating system. The power to heat ratio and, therefore, the produced electricity of the CCPP is higher than the one of the steam power plant, due to the higher electrical efficiency and since the heat is only extracted from the steam cycle.

The right diagram (b) in Fig. 3 shows the relation between electrical power and heat extraction for the CCPP and steam power plant with a back pressure steam turbine. All the generated steam has to be condensed in the heating condensers and the corresponding heat transferred to the district heating system so that the heat extraction defines the electrical production and vice versa. The influence of the district heating supply temperature on the plant characteristics is indicated by the dotted lines in the figure. In contrast to extraction condensing turbine plants, these units have a minimum heat supply. Therefore, three back pressure units with 200 MWth each are implemented (instead of two units with 300 MWth each, as for extraction condensing) so that during periods with low heat demand, e.g., in summer, the CHP plant can supply the heat in minimum load.

The feasible operating range of the CCPP depends additionally on the ambient temperature (influence shown in Tables 4 and 5).

Heat Pump.

The heat pump is sized to supply in total up to 100 MWth, which represents approximately the minimum heat demand of the district-heating network in summer. Hence, the heat pump operation is not limited by the demand. A river with an average temperature of 12 °C is considered as the ambient heat source to heat the district heating return flow from 60 °C up to 90 °C. For these operating conditions, a typical coefficient of performance is 2.8 [22,23], which is considered to model the heat pump. If the supply temperature is above 90 °C, a gas-fired supplementary boiler has to provide the residual temperature difference.

In Germany, the taxes and other surcharges on the power consumption of the heat pump depend on whether self-produced electricity or power received from the electricity grid is used. For electricity produced from the CHP plant a tax of 20.5 €/MWhel is considered, and additional 100 €/MWhel [24] of surcharges for external purchase (besides electricity market price). Depending on the considered systems, changes might occur due to the amendment of the Renewable Energy Sources Act and of the law referring to CHP (KWK-G).

Thermal Energy Storage.

The thermal energy storage is designed as an atmospheric tank with a net capacity to store 2 h of maximum heat supply from the CHP plants (1200 MWh). To avoid boiling conditions in the tank, the temperature of the hot zone is limited to 98 °C, whereas the cold zone has the same temperature as the return flow of the district heating system (60 °C). In the stratified tank, a mixing layer between the hot and cold zone of 10% of the height [25,26] is considered, which is formed during the first charging process after a complete discharge. The further temporal increase of the initial mixing layer is insignificant and thus neglected in the model. To guarantee a stable mixing zone, a maximal charging and discharging rate has to be respected, which is dependent on the storage capacity and geometry. A gas-fired supplementary boiler is installed downstream to reach higher temperatures when required. Heat losses to the environment are considered, but are very small for large and insulated tanks [27].

A thermal energy storage unit has two main effects on the operation of a district heating supply system. It enables an operation of the CHP plant based on electricity prices and increases its heat supply due to displacement of the heating boiler. Both effects can be seen in Fig. 4, which exemplarily visualizes the results of the unit commitment and dispatch problem.

The upper part indicates the electricity price, the district heating supply temperature, and the state of charge of the TES. The lower part shows the power generation of the CHP units as well as the heat demand. Furthermore, the filled areas indicate the heat generation or extraction of the different units distinguished by the color. The lowest filled area represents the heat supply from the CHP units, above that the heat supply from the thermal energy storage, and, if applicable, the supplementary boiler and the heat pump are indicated. These areas reach at least the heat demand, because it has to be fulfilled at all times. In case the filled areas exceed the demand, the surplus of heat production is fed into the storage unit.

Figure 5 shows, whether more thermal energy is charged or discharged for a given combination of heat demand and electricity price within the year. Combinations that did not occur in 2015 or at which the storage is not used, are kept in white.

For heat demands higher than the maximal heat supply from the CHP units (>50%), the storage is only discharged since there is no free charging capacity from the CHP plant. These load cases represent a substitution of the gas-fired heating boiler with heat from the CHP units enabled by the storage. For the electricity-price-based operation of the CHP plant and the thermal storage (< 50% heat demand), one has to distinguish between the different plant types.

Back Pressure Turbine CHP Plant.

In combination with plants with a back pressure steam turbine (Figs. 5(b) and 5(d), see also Fig. 3(b)), the thermal energy storage is charged during periods with high electricity prices so that an increased power production is achieved and for low prices vice versa. It can be seen in Figs. 5(b) and 5(d) that for the CCPP and the steam power plant, the storage unit is mainly charged if the electricity price is above the average electricity price of 32 €/MWh and discharged below. To enable the beneficial replacement of the heating boiler at times when the heat demand is above 50%, the storage is also charged at lower electricity prices and heat demands slightly below 50%. Both are also visible in the trends demonstrated in Fig. 4. The peaks, when the heat demand exceeds the maximal CHP production, indicate a replacement of the otherwise required heating plant by discharging the storage. The areas when the CHP units supply less than their maximum capacity and less than the demand indicate a storage discharge to reduce their power generation at times of low electricity prices.

Extraction Condensing Turbine CHP Plant.

Compared to a CHP plant with a back pressure steam turbine, a plant with an extraction condensing steam turbine is more flexible, because the heat supply is not directly coupled to the power production. This influences the operation of the energy storage, and the two main effects are illustrated below in reference to the PQ˙ diagram in Fig. 3.

In case of electricity prices higher than the marginal costs, the plant is operated in full load to sell as much electricity as possible and therefore is limited by the upper boundary of the feasible operating range in the PQ˙ diagram. By discharging the thermal energy storage, it offers the opportunity to increase the electricity production, as the heat extraction of the CHP plant can be reduced, and the load case is shifted to lower heat and higher electricity generation. This operational behavior is recognizable in Fig. 4 (left) at, for example, the 21st and 22nd when the storage is discharged to increase the electricity generation.

During periods with high heat demands and low revenues from the electricity, the CHP plant, only produces as much electricity as required for the heat extraction. The operating point is on the right restriction in Fig. 3(a). Here, the storage is discharged to reduce the power production of the plant so that the load case is moved to lower heat extraction and electricity production.

The storage is charged when electricity prices are near the marginal costs of power production, which comprise the fuel cost and the cost for CO2 emission certificates, see Figs. 5(a) and 5(c). With the assumptions listed in Table 3, the marginal costs of electricity are 21.3 €/MWhel for the steam power plant and 41.6 €/MWhel for the CCPP, when the plant is running without heat extraction and in full load.

The high gas prices lead to high marginal costs of CCPPs so that these will often generate only as much power as required to sustain the heat production. Figure 5(c) illustrates that the storage is regularly discharged during low electricity tariffs. For high electricity tariffs starting at 45 €/MWhel, the other effect occurs sporadically as well (see the discharging especially at low heat demands).

The results for the steam power plant with low marginal costs show (Fig. 5(a)) that the energy storage is mainly discharged above 30 €/MWhel to increase the generated power in times of high prices and rarely at prices below 15 €/MWhel.

In summary, the thermal energy storage together with a back pressure steam turbine CHP plant is charged in times of high electricity prices and discharged at low prices. Together with an extraction condensing steam turbine, discharging of the storage can offer a reduction or an increase of the electricity production of the CHP plant, depending on the operational point of the plant. If the spot market price is so low that heat production with the gas-fired boiler is cheaper than in the CHP plant, the CHP plant is switched off, if not limited by other restrictions like start up costs or minimum shut down times.

An installed heat pump in a district heating supply system replaces some of the heat supply from the gas-fired heating boiler. Due to the taxes and surcharges applying to power consumption from the grid, the considered heat pump is nearly exclusively driven by power from the CHP plants. Figure 6 shows the commitment of the heat pump depending on the heat demand and the price of electricity for the four considered CHP plants. It reveals that the heat pump is commonly used during heat demands above the maximum heat supply from the CHP plant (50%) and up to an electricity price of 68.7 €/MWhel, at which it becomes beneficial to use the gas boiler instead.

The diagrams of the steam power plant (a) and (b) show that the heat pump is additionally used during times of very low electricity prices. In combination with the back pressure steam turbine (b), it indicates occasional operation of the heat pump for a heat demand of 17% and 33% which is induced by the fact that one CHP unit can supply a maximum of 16.3% of the peak heat demand (200 MWth) and has a minimum heat load of 70 MWth. Therefore, during some hours, it is profitable to use the heat pump instead of starting a second or third CHP unit with start up costs and a reduced part load efficiency. As the heat pump operates at times of high heat demand, it mainly runs from November until March. More than 94% of the yearly heat production from the heat pump is supplied in that time, as shown in Table 1 for the steam power plants.

The operation of the heat pump together with the gas-fired CCPP is plotted in Figs. 6(c) and 6(d), which illustrates that the heat pump is not only used during times of high heat demand, but also regularly at demands below 50% peak load. The heat pump is used below electricity prices of 29.8 €/MWh when it is favorable to further reduce the fuel consumption of the CHP plant by replacing some of the heat with the heat pump. The difference to the steam power plant is caused by the higher fuel costs and power-to-heat ratio and results in some operation from spring to summer, see Table 1. As for the steam power plant, the heat pump is also used at higher electricity prices to avoid start-ups and part load operation of the CHP units, but to a larger extent.

The economic operational benefit (without considering the capital expenditures) of the additional installation of a heat pump and a thermal storage compared to the operation with only the CHP plant and the peak load boiler is presented in Fig. 7. It shows the results for the four considered CHP plants, whereby the left stapled bar represents the benefits when only the heat pump or only the storage is installed, and the right bar is the benefit, if both are installed in combination. The deviation between the two bars is shown in percentage above each pair.

It can be seen that both, the heat pump and the thermal storage, are most beneficial for the CCPP with an inflexible back pressure steam turbine, high operational cost, and a high power-to-heat ratio and less beneficial for the steam power plant with a flexible extraction condensing turbine with the exact opposite characteristics. The operational benefits for the heat pump with 100 MWth are in the same range as for the heat storage unit with a capacity of 1200 MWh, whereas the capital expenditures of the heat pump are estimated to be twice as much as for the thermal storage.

On the one hand, the possibility to also charge the storage with a heat pump leads to synergies, if both are installed together. On the other hand, both compete with each other to replace the peak load boiler. Comparing the sum of benefits for a separate installation with installing both within one system, the results show only minor synergies or competition effects of less than 6%.

The main function of the heat pump is to substitute the peak load boiler at heat demands higher than the maximum thermal capacity of the CHP plants (see Fig. 6), especially for the steam power plants it is almost the only operation case. In winter, with high heat demands, it is regularly in operation.

On the contrary, the main operating case of the heat storage is to enable an electricity-price-based operation of the CHP plant (see Fig. 5) and only a few operating hours arise from displacing the peak boiler. In winter, when the heat demand is constantly higher than the maximum supply of the CHP plant (and, if applicable, the heat pump), the storage cannot be charged and therefore is rarely used. Figure 7 shows that the highest synergy arises for the steam power plant with extraction condensing turbine where the heat pump is almost not in operation for heat demands below 50%, as Fig. 6(a) shows, and the highest competition occurs for the CCPP with back pressure turbine, where Fig. 6(d) indicates increased operation for the heat pump below a heat demand of 50%.

In the investigated district heating system, the capacities for the heat storage as well as for the heat pump were carefully selected in the most probable range of economic feasibility. Thus, the heat pump capacity is undercut by the district heating demand only during few hours in summer, and the thermal storage with 1200 MWhth is a short-term storage with sufficient full load cycles. For significantly larger heat storage units, where the capacity can hardly be fully utilized by the CHP plant and higher installed heat pump capacities often exceed the heat demand, higher synergies are expected to occur, but at a much lower economic feasibility of the entire system.

Heat pumps and thermal energy storage units expand the operation capabilities of a district heating supply system and offer new opportunities to take advantage of fluctuating electricity prices.

Thermal energy storages decouple the power generation of CHP plants from the heat demand in the district heating system and enable the operator to shift partially the power generation from hours with low electricity prices to hours with high prices. Hereby, the optimal operation depends on the characteristics of the CHP plant (type of steam turbine) and its marginal cost in correlation with the electricity price. In addition, the storage reduces the heat supply from the peak load boiler, but only to a minor extent.

Heat pumps mainly replace the peak load boiler in times when the heat demand exceeds the maximum supply from the CHP units. Furthermore, they are used to reduce part load operation and start up cost of CHP units when the heat demand is slightly above the maximum supply of one or two units. If the CHP plant has high marginal costs of electricity generation, like the CCPP in the analyzed systems, it is often beneficial for low electricity prices to produce the heat in the heat pump instead of the CHP plant.

If heat pumps and thermal energy storages are combined in an energy supply system, effects of synergies and cannibalization occur. On one hand, the storage can increase the full load operating hours of the heat pump by storing some of its heat production. On the other hand, both technologies substitute the heat supply from the peak load boiler to some extend. However, the results of the examined systems show that the synergies or the competition are rather insignificant.

For inflexible CHP plants with a high power-to-heat ratio, like CCPP with a back pressure steam turbine, the advantage of installing a thermal energy storage unit and a heat pump is higher, compared to already flexible CHP plants with a low power-to-heat ratio. The number of realized and scheduled projects in Germany shown in Table 2 indicates that large thermal energy storage units can be a beneficial extension of an energy supply system (incl. subsidies). Under the current market conditions, the heat pump is only operated when electricity from the CHP site is used. A change of taxes and surcharges for power consumption from the electricity grid would support future heat pump projects and is one possibility to use the surplus of electricity from excess wind or solar power systems, which would otherwise be switched off to guarantee the stability of the grid.

The increased flexibility of the CHP plant improves the integration of renewable energy sources, so thermal energy storages and heat pumps contribute to the German energy transition (“Energiewende”).

  • German Federal Ministry for Economic Affairs and Energy, Bundesministerium fur Wirtschaft und Energie (Project No. 03ET1188A).

  • CCPP =

    combined cycle power plant

  • CHP =

    combined heat and power

  • DH =

    district heating

  • HC =

    heating condenser

  • MILP =

    mixed integer linear program

  • P =

    power, electricity

  • Q˙ =

    heat rate

  • ST =

    steam turbine

  • steam PP =

    steam power plant

  • TA =

    ambient air temperature

  • TDH =

    district heating system supply temperature

  • TES =

    thermal energy storage

  • ηel =

    electrical efficiency

  • ηth =

    thermal efficiency

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References

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Figures

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Fig. 1

Overview of the analyzed energy system

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Fig. 2

Overview of the unit commitment and dispatch model

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Fig. 3

Feasible operating area of CHP plants with (a) extraction condensing ST and (b) back pressure ST

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Fig. 4

Operation of the TES for the steam PP with extraction condensing ST (left) and the CCPP with back pressure ST (right)

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Fig. 5

Operation of the TES depending on the electricity price and heat demand: (a) steam PP extr. cond. ST, (b) steam PP back pressure ST, (c) CCPP extr. cond. ST, and (d) CCPP back pressure ST

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Fig. 6

Operation of the heat pump depending on the electricity price and heat demand: (a) steam PP extr. cond. ST, (b) steam PP back pressure ST, (c) CCPP extr. cond. ST, and (d) CCPP back pressure ST

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Fig. 7

Effects of a separate and combined installation of TES and HP

Tables

Table Grahic Jump Location
Table 1 Annual operating data for the heat pump in 2015
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Table 2 Several TESs in district heating systems in Germany
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Table 3 Economic parameters
Table Footer NoteaBased on futures from European Energy Exchange from November 2014.
Table Grahic Jump Location
Table 4 CCPP with back pressure ST: characteristics as a function of the ambient temperature (TA), TDH = 110 °C
Table Grahic Jump Location
Table 5 CCPP with extraction condensing ST: characteristics as a function of the ambient temperature (TA), TDH = 110 °C, Q˙=0MW

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