Home – Energy – A farm heating experiment combines solar collectors, a heat pump, and underground storage, and the result could shake up rural energy
Winter does not wait for energy markets. When the temperature drops, livestock barns need steady heat even if the farm is miles from the nearest gas line. A research team in northern Italy has field-tested a hybrid setup that turns rooftop sunlight into both electricity and usable heat, then stores some of that warmth underground for later use.
In a full-scale installation at the Golinelli swine farm in Mirandola, the system delivered about 40,870 kWh of heat, about 139.5 MMBtu, over one year while using roughly 10,810 kWh of electricity for a seasonal performance factor of 3.78.
The setup replaced a propane boiler and heat lamps in the nursery barn, and it ran mainly from November through April. Could farm energy move from a cost center to infrastructure?
Farms have a different energy reality than most commercial buildings, and the paper is blunt about why. Rural production facilities are often not connected to the natural gas grid, which pushes operators toward delivered fuels and on-site tanks. The researchers also note that fossil fuel price swings can ripple through farms that try to keep production costs predictable.
At Mirandola, the nursery barn was previously heated by a 34 kW propane boiler, about 116,000 BTU per hour, plus five thermal lamps in each of 10 rooms. Replacing that hardware changes more than the emissions math – it also changes the day-to-day dependence on fuel delivery and storage.
The concept is basically a three-part relay race. Photovoltaic-thermal panels (PVT) make electricity and collect heat, boreholes in the ground hold some of that heat, and a dual-source heat pump (DSHP) decides whether to pull energy from the ground, the air, or both. That switching matters because it helps meet winter peaks without draining the underground store.
On the roof, the farm used 24 PVT collectors rated at about 7.68 kW electric and 25 kW thermal, roughly 85,300 BTU per hour of heat. Underground, eight boreholes about 98 feet deep sit in a courtyard footprint of roughly 194 square feet, and their connections are part of a patented configuration.
A control rule starts circulation when solar irradiance exceeds about 14 W per square foot (150 W per square meter), or when a temperature difference of more than 7 degrees Fahrenheit favors heat transfer into storage.
The heat pump is PLC-controlled with a hot-water supply setpoint of about 122 to 131 degrees Fahrenheit, and it leans on the air source as the geothermal loop cools. Local environmental rules also capped underground heat injection at 95 degrees Fahrenheit, a reminder that geothermal is regulated like water, not like wiring.
Clean-energy pilots live or die by data, and this one logged temperatures and operating variables every minute. The system worked mainly from November to April, and defrosting occurred 3.6% of the time during that operating period. The authors also emphasize temperature stability on the building side, which they link to animal welfare and avoiding thermal stress.
Over the monitoring year, the team reports about 40,870 kWh of heat delivered (147,133 MJ) and about 10,810 kWh of electricity consumed (38,917 MJ), matching the seasonal performance factor of 3.78. The annual average coefficient of performance was about 4.07, and compressor time was dominated by ground-only and hybrid operation, with air-only use reserved for peaks.
The rooftop array is also sized to matter, with estimated electricity production of about 10,000 to 11,000 kWh (36,000 to 39,600 MJ), enough to cover roughly 95% to 105% of system consumption over a year.
That last detail is where economics can get real, and Francesco Tinti told pv magazine the DSHP electricity use is “almost entirely covered” by the PVT unit. The study also notes that the PVT electricity was not yet connected to the grid due to regulatory delays, so the best-case energy balance was still partly theoretical at publication time.
Storing heat in the ground sounds simple until you remember that soil and groundwater behave differently from site to site. The researchers monitored groundwater flow direction with two piezometers and a dedicated borehole, and they report that the aquifer impact was modest. They estimate an annual net heat storage around 94 kWh (340 MJ) and a temperature difference on the order of 0.4 degrees Fahrenheit (0.22 K) between monitoring points.
Upfront cost is the bigger hurdle, and the paper calls high installation cost a main barrier for ground heat exchangers and underground storage. In the project comparison, the integrated approach used about 787 feet of total borehole length versus about 2,100 feet in a standard ground-source heat pump project, a reduction of roughly 66%.
As Tinti put it, “The capital cost of the system remains significant,” even if it can look more comparable to geothermal once drilling is reduced.
The authors argue the configuration fits farms with available land and favorable shallow geothermal conditions, which sets some clear boundaries on where it can scale. They also call the system a pathway to cut greenhouse gas emissions while improving energy resilience, a framing that mixes climate goals with risk management.
Future work will focus on improving control strategies, integrating PVT electricity into the farm energy balance, and extending monitoring to see how the subsurface behaves over multiple years.
One reason this type of pilot gets attention is that it tackles two mismatches at once, summer solar supply and winter heat demand, using something farms often have plenty of, land.
Background materials shared with Indux describe the same push toward near self-supply through coordinated PVT, borehole thermal energy storage (BTES), and dual-source heat pump operation.
The study was published on the University of Bologna’s CRIS.
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