PV with multiple storage as function of geolocation to reduce peak demand

A system, modeled in two geolocations (Oxford, England; San Diego, California), consists of a PV array and two storage solutions (defined by distinct sets of efficiencies/costs): short term (battery B) and long term (H, hydrogen reservoir with electrolyzer/fuel cell). The system meets a 1-year, real domestic demand totaling 5 MWh/year. First, it is configured as standalone (SA); then, as gridconnected (GC), receiving 50% of the yearly integrated demand. H and PV are dynamically sized as function of geolocation, B size and H efficiency. With a 10 kWh battery and a 0.4 H cycle efficiency, required H capacity for the SA case is ~1230 kWh in Oxford and ~750 kWh in San Diego (respectively, ~830 kWh and ~600 kWh in the GC case). Related array sizes are, respectively, 93% and 51% of the local reference 8 kWp system (51% and 28% in the GC case). A trade-off between PV size and battery capacity exists: the former grows significantly as B shrinks below 10 kWh. On the other hand, PV size is insensitive to rising B above ~10 kWh, a capacity large enough to cope with short timescales. With current PV and B costs, a SA system in Oxford (San Diego) can stay within 104 $ CapEx if H’s cost does not exceed 4 $/kWh (8 $/kWh); these figures increase to 7 $/kWh (10 $/kWh) with grid constantly/randomly supplying a half of yearly energy. Extending modeling over 18 years makes results varying to different extents, depending on location; in any case, less than ±10% of the reference year.