How to integrate air-source steam-generating heat pumps with PV, battery storage

Researchers at the University of Cagliari in Italy have designed a hybrid energy system that combines a three-stage air-source heat pump for industrial steam generation with on-site PV, battery energy storage and the electricity grid.

Unlike conventional high-temperature heat pump systems that rely on industrial waste heat, the proposed system extracts heat directly from ambient air, allowing it to produce steam without an available waste-heat source. The researchers optimized the PV and battery capacities to minimize the levelized cost of heat (LCOH), with the grid providing additional electricity when required.

“The proposed system couples a three-stage steam-generating heat pump (SGHP) with on-site PV, battery storage, and the electricity grid, optimizing the PV and battery capacities to minimize the levelized cost of heat,” lead author Luca Migliari told pv magazine. “We found that the economic viability of steam-generating heat pumps depends not only on their efficiency, but also on how their electricity supply is designed.”

“Our results also showed how the cost-optimal configuration shifts from grid-dependent operation to PV-supported and higher-autonomy solutions as electricity prices increase,” he added. “They also highlight that solar availability has a much stronger influence on the economic benefits of PV and storage than ambient temperature.”

In the study “Techno-economic assessment of an air-source steam-generating heat pump with optimal PV–BESS integration,” published in Energy Conversion and Management, the research team explained that the economic viability of PV-BESS-integrated industrial heat pumps depends strongly on local solar resources and electricity prices.

System operation

The proposed system follows a fixed dispatch hierarchy that prioritizes locally generated solar power. PV electricity is first used to directly supply the SGHP, reducing electricity imports from the grid. When PV generation exceeds the SGHP demand, surplus electricity is used to charge the battery energy storage system (BESS), subject to its state-of-charge (SOC) and power constraints. Any remaining surplus is exported to the grid.

When PV generation is insufficient, the BESS is discharged to cover part of the SGHP demand, with the grid supplying any remaining load. The battery can only be charged with surplus PV electricity and not from the grid, meaning that grid-based energy arbitrage is excluded.

The researchers quantified system autonomy using a self-sufficiency (SS) indicator representing the share of SGHP electricity demand supplied by PV, either directly or through the BESS. Hourly PV generation was calculated using PVGIS and the ERA5-2023 solar radiation dataset, with module orientation optimized for each location. PV degradation over the project lifetime was also included.

The lithium-ion BESS model accounted for charging and discharging efficiencies, self-discharge, operating constraints and capacity degradation. Battery operation was limited by SOC and charging and discharging power constraints. The researchers considered both calendar and cycling degradation, with battery replacement occurring when state of health (SOH) reached 80%.

The SGHP was designed to continuously produce 2 metric tons per hour of saturated steam at 15 bar, with condensate returned at 1 bar. It consists of three cascaded stages: a low-temperature air-to-water heat pump, a medium-temperature water-to-water heat pump and a high-temperature mechanical vapor recompression stage.

The medium- and high-temperature stages were assumed to operate at their nominal coefficients of performance (COPs), while the low-temperature stage was modeled on an hourly basis to account for variations in ambient temperature and performance losses associated with defrosting.

Assessment

The economic model included capital and operating expenditures, component replacement costs, electricity purchases, revenues from PV exports and residual values. Annual cash flows were discounted over a 20-year project lifetime using a 5% discount rate.

The researchers calculated the LCOH from discounted lifetime costs and revenues relative to the total discounted useful heat supplied. Grid electricity prices ranged from €20/MWh to €200/MWh to assess their impact on the economic attractiveness of PV and battery storage. PV capacity ranged from 0 MW to 12 MW, while BESS capacity ranged from 0 MWh to 24 MWh.

The researchers assessed system deployment under the contrasting meteorological conditions of Cagliari, Italy, and Berlin, Germany. They found that increasing electricity prices progressively shifted the cost-optimal electricity supply from grid-dependent operation toward hybrid and high-autonomy PV-BESS configurations.

These transitions occurred at substantially lower electricity prices in Cagliari than in Berlin, highlighting the influence of local meteorological conditions on the economic value of PV and storage.

“For the considered case study, the minimum LCOH varied between approximately €55/MWh and €109/MWh in the Cagliari case and between €55/MWh and €149/MWh in the Berlin case,” the researchers said.

Results

At a grid electricity price of €200/MWh, the optimal Cagliari configuration achieved approximately 91% self-sufficiency, while the Berlin system remained below 60%, despite the deployment of substantial PV and battery capacities. The results indicate that Cagliari’s more favorable solar conditions enable high levels of self-sufficiency with relatively moderate cost penalties, whereas Berlin remains constrained by its lower solar yield.

The researchers also cross-combined the solar and ambient-temperature profiles of the two locations to separate their respective effects. The analysis showed that solar availability has a substantially greater impact on the minimum LCOH than ambient temperature. As grid electricity becomes more expensive, increasing self-sufficiency becomes more economically attractive, although the cost of approaching complete energy autonomy rises sharply.

The LCOH breakdown showed that, as electricity prices increase, grid electricity expenditure is progressively replaced by capital-related costs for PV and battery storage. This shift provides greater protection against electricity-price increases in Cagliari. In Berlin, persistent grid dependence leaves the system more exposed to electricity costs even after PV and battery deployment.

The sensitivity analysis showed that SGHP costs have the strongest influence at low electricity prices, while PV costs and feed-in remuneration become increasingly important as the share of locally generated renewable electricity increases. BESS costs have a comparatively smaller impact.

“Overall, the results indicate that the economic viability of air-source SGHPs is determined not only by the performance of the heat pump itself, but also by the configuration of the electricity supply system,” Migliari concluded. “Among the two cases investigated, the more favorable meteorological conditions in Cagliari result in lower heat-production costs and support the adoption of supply configurations characterized by higher levels of energy autonomy.”