The Netherlands is committed to reducing carbon emissions in all sectors. This will cause the electricity production to be dominated by wind and solar power, and sectors such as mobility and industry will be heavily electrified. This poses significant challenges for the electricity grid. In addition, the government plans to phase out the use of natural gas in buildings by 2050. Local governments are now choosing alternative heating sources for specific neighbourhoods, and heat pumps are one of the options. As these use electricity for heating, it is important to consider their impact on the grid.

Therefore, this thesis analyses the impact of different types of heat pumps on a real Dutch low-voltage grid, focussing on transformer overload and voltage limit problems. A simulation model based on Powerfactory and Python is built, where different types of heat pumps are considered, including air- and ground-source heat pumps, as well as electric-resistive and natural gas hybrid heat pumps. Different control methods are also considered. In addition to heat pumps, public and private electric vehicle chargers and photovoltaic systems are also included in the model. Additionally, the effects of dynamic energy prices and domestic hot water production are investigated. The simulation is performed on an hourly basis using real data from the two coldest weeks of the winter of 2021.

The results show that air-source heat pumps have a significantly higher impact on transformer overload and voltage limit violations than ground-source heat pumps, and modulating heat pumps have a slightly lower impact on the grid than on-off controlled heat pumps. Gas-hybrid heat pumps are found to cause almost no grid problems on the low-voltage grid studied and have a significantly lower impact than the all-electric air-source heat pump. The presence of an electric-resistive backup heater in the heat pump significantly increases transformer overload and voltage limit problems. Scenarios for 2030 and 2050 show that problems are unlikely to occur in 2030, but the current grid will not be sufficient in 2050 if air-source heat pumps dominate the grid. More research is needed to determine whether the current grid is sufficient when ground-source heat pumps are dominant.

It was also found that dynamic energy prices will not be a problem for the grid at current rates of heat pump and home charging for electric vehicles. However, if every household has a heat pump, a penetration rate of 20\% or more of dynamic energy contracts will substantially increase transformer overloads and voltage level violations. Finally, domestic hot water production does not significantly increase overloading and voltage limit problems.

In conclusion, heat pumps can cause significant problems for the low-voltage network. However, the impact can be reduced by choosing the right type of heat pump. It is recommended that future research considers cooling, heat and electricity storage, thermal ratings of transformers, and variable capacity tariffs.

This thesis work investigates and provides an analysis of the potential benefits of an electricity - gas - heat integrated energy system, putting extra focus on the waste heat potential from fuel cells and electrolysers. The main focus is given to the low-voltage distribution grid level, and a case study is presented for the Drechtsteden subnetwork operated by Stedin, which, together with the IEPG department at TU Delft, is the promoter of this study. The novelty items of this work consist in the analysis of the waste heat potential of hydrogen conversion assets connected to a district heating network along with the inclusion of electricity and hydrogen markets, all in the contest of an energy system optimization.

The integration between these three energy sectors is assumed to be chiefly driven by the operation of electrolysers and fuel cells. Two other main assumptions set the base for this work: first, the gas sector is assumed to be entirely repurposed to operate with hydrogen and, secondly, the waste heat coming from fuel cells and electrolysers is assumed to be the main thermal energy input of a district heating network. An electricity and a hydrogen market have also been modelled to simulate the interaction of this region with the external grid.
The analysis is carried out by means of a linear optimization algorithm coded using oemof, an open source python package for multi-energy system modelling and optimization. Most of the input data (i.e. energy demand and generation profiles) comes from the Integrale Ifrastructuurverkenning 2030-2050 study from TenneT, Gasunie and the Dutch DSOs, which has been regionalized for the Drechsteden region is order to optimize the investments on the main energy assets (transformers, hydrogen substations, electrolysers, fuel cells, batteries) needed to run the future energy system.

An optimal system configuration is also calculated for a "reinforcement" scenario, in which energy sectors remain independent, and a comparison with the system integration scenario is presented. The overall system costs appear to be only about 5% lower for the system integration scenario. The costs imputable to assets is higher with system integration due to the addition of expensive hydrogen conversion assets, but, in this scenario, the operation on the energy market (driven chiefly by hydrogen exports) is more advantageous.
Finally, a sensitivity analysis on the share of heat demand to be satisfied by district heating and on the price of batteries is carried out, along with an investigation on the effect of adding thermal storage to the system.

Renewable energy sources, e.g. solar energy and wind energy, have gained popularity as an alternative means of energy production as they do not reinforce global warming. In addition, more and more electrical appliances (e.g. electric vehicles, induction cookers, and heat pumps) are used as a substitute for appliances that need non-renewable energy sources. This increase in the use of renewable energy resources pushes the electricity grid to its limits due to new induced load peaks. The grid is not designed for these developments and as a result, asset deterioration, higher transport losses, and outages are expected to occur. The most straightforward solution for the distributed system operator, i.e. the operating manager of the distribution network, is to expand the grid. However, grid expansion is a costly operation and there are additional promising methods to decrease grid load peaks, e.g. by using different charging strategies for electric vehicles. The conventional charging strategy for electric vehicles is uncontrolled charging. With uncontrolled charging, the charging of the electric vehicle immediately commences once a connection with the charging pole is established. The smart charging strategy, however, is able to delay the charging moment to a more optimal time instant in view of, e.g. variable electricity prices. The vehicle-to-home (V2H) charging strategy is similar to smart charging, but in addition, the V2H strategy allows the electric vehicle to discharge electricity to power a nearby residential home. This research aims to compare smart charging and V2H charging on their economical effects for their users. The charging strategies are implemented using two control algorithms: a rule-based controller and a model predictive control (MPC) algorithm. The rule-based controller is implemented due to its simplicity and the MPC algorithm is used for its ability to take into account predictions of system related variables, e.g. household loads. The MPC algorithm is implemented with two different forecasts namely, perfect information, i.e. uncertain variables are forecasted perfectly, and certainty equivalent, i.e. uncertain variables are predicted using a persistence forecast model. The persistence forecast model assumes that the future values of an uncertain variable remain equal to the latest measurements, e.g. the solar generation of tomorrow is expected to be equal to that of today. The control problem is non-linear as an electric vehicle behaves differently depending on its status, e.g. driving or charging. The control problem is therefore reformulated into a mixed logical dynamical framework such that it can be solved efficiently using mixed integer linear programming. An extensive comparison in performance for a microgrid case study is done using real data of solar generation, electric vehicles, and household loads for simulation. The results show that the V2H charging strategy can outperform smart charging by reducing both the peak loads and the electricity costs. However, the V2H strategy only gives a minor extra decrease in costs compared to smart charging and the performance of V2H charging is highly dependent on the quality of the forecasts. Therefore, it is concluded that, in practice, smart charging is the most effective charging strategy. Further research is done to investigate whether the microgrid costs, using a smart charging strategy, can be reduced further by taking into account the uncertainty of some variables such as the electricity price and the household load. This is implemented through a scenario-based MPC algorithm due to its ability to incorporate multiple forecasts, i.e. scenarios, for each uncertain variable. Six different scenario generation methods are implemented which are distinguished by two characteristics: the period from which the historical error between the certainty equivalent case and the true realization of the uncertain variable is collected (i.e. yearly, seasonal, or daily) and the addition method of these errors to the persistence forecast model to generate new scenarios, i.e. as a variable or as a constant. An extensive comparison in performance for a microgrid case study is done. The results show that the certainty equivalent MPC case can be outperformed if a low number of scenarios is generated. This is achieved most effectively by collecting the persistence forecast model error from a rolling horizon of the past 24 hours and adding the error as a constant to the persistence forecast model.