**5. Results**

For the dynamic simulations of one year, the results show that maximal reduction of *CO*2,*<sup>e</sup>* emissions is limited to 63.75%. This maximal reduction is reached by using a BMB for base load and a BGB for peak load. Figure 5 shows the increase of the total energy costs for the steam supply and electricity supply in comparison to the reference case for one year. In addition, the *CO*2,*<sup>e</sup>* emission reduction is visualised. The installation of PTC results in the lowest cost increase by 6.6%. Since only the depreciation and maintenance costs are determining the energy costs, the increase is very small compared to other technologies.

**Figure 5.** Comparison of energy costs increase and *CO*2,*<sup>e</sup>* emission reduction.

However, the limited availability during a day and a year leads to high running hours of the conventional backup boiler. This is the reason why the *CO*2,*<sup>e</sup>* emission reduction is only 17.51%.

Both, BMB with a natural gas fired or biogas fired backup boiler take advantage of the low fixed price for biomass of 0.028 e/kWh. This results in an energy costs increase of 23.61% for the combination biomass system/conventional boiler and 27.81% for the combination with a BGB backup. Also, the emission reductions of 62.12% and 63.75% are the highest of all concepts. The low carbon footprint of biomass and the high steam supply share of the BMB explain the high *CO*2,*<sup>e</sup>* emission reduction.

The use of an HP results in a similar cost increase of 23.53%. The share of the conventional backup boiler of more than 25% leads to emissions of 2612 t *CO*2,*<sup>e</sup>* which results in a reduction of 49.80%.

Because of the fuel price ratio between natural gas and biogas, the retrofit to a biogas burner increases the energy costs by 68.96%. The *CO*2,*<sup>e</sup>* emissions are reduced by 43.97%.

The MGT needs to be fired with biogas to reduce *CO*2,*<sup>e</sup>* emissions. A reduction of 43.97% is possible with an energy cost increase of 71.9%. When operated with natural gas, the simulation shows an annual savings potential of about 33,000 e. These savings can be explained by the cheaper supply of electrical energy. However, *CO*2,*<sup>e</sup>* emissions increase due to production of electricity and the low average electricity grid emissions of 267 g/kWh in Spain.

The EB has 7.71% lower *CO*2,*<sup>e</sup>* emissions than the natural gas-fired boilers of the existing system, although the assumed average emissions of electrical energy per kilowatt hour are greater than those of natural gas. The savings can be explained by the higher efficiency, the elimination of switching losses and heat losses of the second boiler. These low emission savings are offset by significantly higher costs of 90.66%.

In the simulation study, the implementation of a FC has the highest increase in costs and only a emission reduction by 34.65%. High investment costs of over 6.8 million e and low thermal efficiency compared to other technologies result in very high steam production costs. Because of the limited flexibility, a secondary peak load boiler needs to provide a significant share of the overall steam demand. Therefore, the emissions reduction is limited.

The results for the forms of energy conversion show that higher energy costs do not automatically lead to the highest *CO*2,*<sup>e</sup>* emission savings. To evaluate the best technology for the presented case study the ratio of additional costs to emission savings is essential. In Figure 6, the costs are offset against the corresponding *CO*2,*<sup>e</sup>* emission reduction to obtain the costs per tons of *CO*2,*<sup>e</sup>* saved for one year.

The costs per saved ton of *CO*2,*<sup>e</sup>* per year are between 89 e and 2753 e. According to this, the use of a BMB and PTC are the most efficient ways of providing steam in terms of economic efficiency and *CO*2,*e*-emissions avoided. The installation of a EB results in the highest costs per ton *CO*2,*e*-emissions avoided under the assumed circumstances of relative high electricity costs and *CO*2,*e*-emissions of the electricity mix.

**Figure 6.** Ratio of *CO*2,*<sup>e</sup>* emission saving and energy costs per year.

Table 5 summarises the costs and *CO*2,*<sup>e</sup>* emissions for all technologies and the corresponding used types of fuel.



## **6. Discussion**

The results indicate that the BMB with natural gas or BGB have the highest emission reduction and the lowest increase in cost. Although the steam production costs of around 30 e/t are higher than those presented by Pérez-Uresti et al. [13], the statement that biomass is the most economical alternative in 2019 is consistent. The comparison between the steam production costs of the BGB and the BMB shows that the investment costs with an assumed depreciation between 10 to 15 years have a very small impact on the steam production costs. For production plants with a high thermal energy demand the fuel prices is determining the overall steam production costs. The depreciation period should be reduced for production plants with frequently changing products and changes in thermal processes. Thus the influence of investment costs increases linearly with the reduction. However, a complete substitution of all thermal steam processes with BMB may exceed the sustainable supply. This can lead to an increase in the cost of biomass, which is not yet included in the model. For example, Börjesson et al. [62] showed that an increasing forest fuel demand by 30–40 TWh for Sweden for the upcoming decades exceeds the potential increase in sustainable supply of logging residues.

The implementation of SES and HP results in a relatively low increase in the overall energy costs. The limited flexibility impede a complete reduction of emissions Therefore, these technologies can only be auxiliary technologies for reducing the *CO*2,*<sup>e</sup>* emissions of a steam supply system. For the SES, the high space demand for the installation of the solar field reduces the potential for a decentralised solution. For a closed cycle HP, the fluctuating steam demand and steam temperature exceed current available options in the market for industrial and high temperature HP. Furthermore, in accordance with Bühler et al. [4] and Apargaus et al. [42], the potential of HP for energy-efficient electrification for steam supply is estimated to be high once temperatures above 165 °C are reached. In addition, for the food processing industry the steam temperature level is not given by the process (e.g., sterilisation), which usually need temperatures below 150 °C. The temperature restrictions are set by the required quick reaction time of the control system. A process adaption focusing on lower *CO*2,*<sup>e</sup>* emissions and resulting in lower steam supply temperatures may increase the implementation potential for HP and SES.

Regarding the still relatively high emissions of EB, an increase of renewable energies in the electricity mix leads to a further reduction of *CO*2,*<sup>e</sup>* emissions as well as probably electrical energy costs reductions. There is already the option of providing and purchasing electrical energy without emissions, at least on the balance sheet, thus the compensation of the total *CO*2,*<sup>e</sup>* emissions is possible. However, to achieve the planned reduction of *CO*2,*<sup>e</sup>* emissions through electrification in the food processing industry, a significant increase in the installed capacity of renewable energies is required. As Philipp et al. [63] showed, the timing and the share of renewable electricity in the respective country is decisive for a positive *CO*2,*<sup>e</sup>* emission reduction effect. Besides BMB, EB have the potential to reduce the emissions significantly if the electricity mix is dominated by wind power. Short start up times and a very flexible load control offer a solution in the future if electrical energy costs and electrical grid emissions are reduced.

The fuel switch to biogas or biomethane results in the lowest investment costs and implementation effort. Therefore, both concepts are very sensitive to a change in the fuel prices. For biomethane the fuel price varies between 60–95 e/MWh depending on costs for conditioning and grid. For a low fuel price level, a steam production cost reduction of 35% is possible and a boiler fired with biomethane is an easy and cost attractive option to reduce *CO*2,*<sup>e</sup>* emissions. Biogas is produced from various substrates, mainly renewable raw materials, excrements, municipal biowaste and residual materials from industry, trade and agriculture. The substrates differ in price, methane yield and the resulting related state subsidies. For this reason, producer prices and emissions of biogas can also vary strongly from plant to plant [55]. In order to assess the economic and ecological effects, special attention must be paid to local conditions. For locally produced biogas, it is possible to achieve favourable prices and low *CO*2,*<sup>e</sup>* emissions.

For the MGT, a fuel price reduction is also necessary to be competitive with the BMB. However, CHP technologies increase the overall fuel demand significantly. The amount of available biomethane or biogas might limit integration potential of MGT and FC.
