Integration of Hydrogen Production via Water Electrolysis at a CHP Plant : A feasibility study

Hydrogen gas (H2), that is not produced from fossil oil or natural gas, is expected to become a cornerstone in the energy transition strategy in Europe. The recent years, technological and economic advances in the electrolyzer area, along with political and corporate support, have put H2 at the forefront of many countries’ climate change agenda. Consequently, green H2 is poised to play a large role in the coming energy transition to combat climate change. The possible advantages of integrating H2 production with a combined heat and power plant, or CHP, is investigated in this study. More precisely, the water electrolysis is carried out based on the purified flue gas condensate water and excess heat is recovered as district heating. A comparison of today’s three most common electrolyzer technologies was made, where Proton Exchange Membrane, or PEM, technology was chosen for this project, mainly for its high purity of H2 gas, robust construction, and the ability to run it as a fuel cell. Based on a mass and energy balance, a model including the integration of a PEM with a generic CHP plant was developed. The model was made modifiable, making it possible to change governing parameters, to be able to investigate different possible scenarios. Production flows, losses and other relevant data was calculated from the model. Operational data for the PEM electrolyzer were collected from several manufacturers where a mean value of the data was used as a base-case for the calculations. Based on literature and consulting experts, several assumptions were made, for example the selling price of H2 and the price for electricity. From the base-case were two cases made: a linear and non-linear case. The linear case uses the same input data each year for 20 years, while the non-linear case uses a changing input data each year for 20 years. Calculations were based on an electrolyzer size of 1,4 MW, where auxiliary equipment consumed additional 0,04 MW, resulting in a total energy consumption of 1,44 MW. An operational temperature of 80°C was assumed along with an operational pressure of 5 and 30 bar for the anode and cathode respectively. This resulted in an H2 production flow of 26 kg/h, a process water requirement of 0,2 m3/h, and a possible heat recovery amount of 0,34 MWh with a relevant temperature for the use in district heating. The study shows that the condensate-water at E.ON could provide for ~4000 hours of operation in the wintertime. To enable full operation all year around, a purchase of tap water would be necessary. The economical calculations resulted in an H2 production cost of 53 SEK/kg for the linear case and 58 SEK/kg for the non-linear case. The linear case showed a positive internal rate of return, or IRR, of 1,7%, while the non-linear case resulted in IRR < -25%. A sensitive analysis was made to examine governing parameters. The results of the sensitivity analysis showed that the largest driving variables, that significantly affect the IRR, are the price for electricity and the selling price for H2. The largest OPEX cost was found to be the price of electricity. The results showed that it is feasible to produce H2 at E.ON Örebro in a resource efficient way under certain circumstances, correlated to the electricity and H2 market. With a low electricity price and a selling price of ~50 SEK/kg for H2, good profitability is expected. It is also clear that future work should focus the areas of O2 usage, infrastructure, and market investigation for a more definitive conclusion