Renewable power production is becoming a necessity to improve society and overcome the challenges of climate change. In Sweden, large-scale solar PV power is growing year-on-year and today comprises 1 percent of electricity production. Solar power, however, is an intermittent form of electricity production which, whilst being renewable, contributes to increasing grid instability. For the grid to stay in balance, at grid frequency 50 Hz, electricity must be consumed at the time of production. If there is a surplus of production or a sudden decrease in consumption, the frequency will deviate from the nominal value. When introducing larger quantities of intermittent power production, the power system inertia decreases, and the frequency becomes prone to deviate. To combat this, the Swedish TSO Svenska Kraftnät procures ancillary services which aid the grid when needed. For solar PV power to be able to contribute to these marketplaces, a battery storage solution system (BESS) is utilized. This thesis aimed to investigate the economic feasibility of co-locating a solar photovoltaic (PV) park with a battery energy storage system (BESS) and to determine the optimal size of the BESS. The study utilized a linear optimization model to simulate the operation of a 14 MW solar PV park with different sizes of BESS ranging from 1 MWh to 14 MWh. The analysis considered the revenue generated by providing different services to the electricity grid, such as energy arbitrage and frequency regulation. The results indicate that co-locating a solar PV park with a BESS increases revenue, and the optimal BESS size for a 14 MW solar PV park is between 1 and 8 MWh. Above this range, the revenue recedes due to the limitations of the grid connection, which restricts the BESS from participating in the ancillary service markets. The analysis considers the running costs associated with power discharge to the grid and initial BESS investment. The study did not account for ancillary market bids that are not accepted, which could have a significant impact on the revenue generated. The ongoing trend of lowering battery prices could further boost the economic assessment and increase interest in all battery sizes, resulting in larger battery system installations in general.

With global climate change as the main driver, there is an increase towards including more variable renewable energy (VRE) sources in the electricity mix. Energy production from utilizing the photovoltaic effect, or PV power, is increasing rapidly and is visioned to cover 5 – 10 % of Sweden’s electricity demand in 2040. In addition to rooftop PV production, large- scale PV production in the form of ground-mounted PV parks is gaining ground. A higher share of VRE in the power system creates new challenges as to uphold the power system stability. For a PV park owner, achieving a preferable economic outcome is also a challenge, as the variable electricity output may not match electricity demand. Therefore, combining a PV park with an energy storage, which can store the PV production energy, is seen as a favorable solution. This way, the variability of the electricity production can be reduced and the stored energy in the battery can be used for services benefitting both the PV park owner and the power grid. This study aims to explore the economic potential of combining a PV park with an energy storage. This is achieved by simulating a lithium-ion (Li-ion) battery storage combined with PV production modeled after a 3.5 MW PV park located in Fyrislund, Uppsala. Five cases with individually differing approaches are simulated, exploring how so-called service stacking can be applied with a battery. The investigated services included in the cases are 1) lowering the cost of connecting the PV park to the power grid, 2) lowering the cost of feeding in energy to the power grid, 3) increasing the revenue of selling electricity on the Nord Pool spot market, 4) increasing the revenue by performing energy arbitrage, 5) increasing the revenue by participating in the primary frequency regulating markets to help stabilize the 50 Hz grid frequency. The cases are evaluated by calculating the net present value (NPV) of the system over 10 years with an annual discount rate of 5 %. Battery capacities ranging from 0.1 MWh/0.1 MW to 8 MWh/2 MW are tested. The system configuration achieving the highest NPV occurs when all services are performed, and a 0.13 MWh/0.1 MW battery is used. This NPV is also higher than the NPV when not including a battery in the system. Conclusions include that the spot price impacts the choice of battery capacity to a high extent and that the battery investment cost motivates using a smaller-sized battery.