Daniel Burmester

The transition from diesel-dependent isolated grids to hybrid renewable energy systems presents both technical opportunities and operational challenges for Pacific Small Island Developing States (SIDS). This study presents a quasi-dynamic simulation analysis of Niue's power grid under five progressive renewable energy integration scenarios, modelled using DIgSILENT PowerFactory. While the existing network infrastructure is demonstrated to be adequate for all modelled transition scenarios, the progressive introduction of variable renewable energy sources fundamentally alters grid behaviour, shifting from stable and predictable diesel dispatch to an increasingly dynamic system. The study identifies that Battery Energy Storage Systems (BESS) are critical enablers of diesel displacement, but their effectiveness is highly sensitive to PV system sizing and diesel operational practices. Prolonged low-loading of diesel generators under high renewable penetration is shown to pose risks of wet stacking with direct implications for asset management in small island utilities. The imposition of a minimum diesel loading constraint, while necessary for generator health and frequency stability, is found to saturate storage capacity and necessitate renewable curtailment, highlighting a fundamental tension in hybrid system operation. Additionally, the progressive reduction of synchronous generation raises considerations regarding grid inertia that warrant dedicated frequency stability investigation. The findings offer transferable insights for renewable transition planning across Pacific SIDS with similar isolated grid contexts.

The increasing penetration of inverter-based renewable energy resources (IBRs) presents significant challenges to power system voltage stability and reactive power management due to the declining contribution of conventional synchronous generation. This study investigates the reactive power support capability of a fixed-speed pumped hydro storage (FS-PHS). A dynamic FS-PHS model was developed in MATLAB/Simulink based on a validated Sandia National Laboratories model and adapted to Aotearoa New Zealand operating conditions. The validated model was integrated into a modified IEEE 9-bus system operating at 220 kV transmission voltage. Load flow and electromagnetic transient studies showed that the FS-PHS unit provided effective voltage support and dynamic reactive power compensation under varying reactive loading conditions. The system successfully responded to changing network requirements while maintaining stable operation and acceptable bus voltage profiles. The findings demonstrate that FS-PHS can provide valuable ancillary services beyond energy storage, including voltage regulation and reactive power support. The technology represents a promising option for strengthening weak renewable-rich regions, such as Aotearoa New Zealand, where future system strength and voltage stability are expected to become increasingly important.

The way power systems operate is being reshaped by the high penetration of distributed energy resources (DERs) such as rooftop solar, batteries and electric vehicles in low-voltage distribution networks. These technologies, although beneficial for decentralization and decarbonization, pose significant technical challenges-including voltage rise, frequency fluctuations and bidirectional power flow. Virtual Power Plants (VPPs) are emerging as a promising framework to aggregate, manage and optimize the operation of DERs through intelligent control and coordination. The objective of this research is to analyse the use of Virtual Power Plants (VPPs) to coordinate DERs and enhance voltage stability in low-voltage distribution networks. The study uses an IEEE 13-bus test feeder, modelled in DIgSILENT PowerFactory, incorporating photovoltaic generation, battery energy storage systems, and electric vehicle loads under varying penetration levels. A PowerFactory-Python co-simulation framework is developed using a supervisory iterative approach, where quasi-dynamic simulations are analysed and used to update the control setpoints across successive runs. The results demonstrate that coordinated control of DERs can significantly improve voltage profiles, with voltage levels reduced from peak values above 1.05 pu within limits of approximately 0.99–1.03 pu. Battery energy storage systems provide effective voltage support, while demand-response flexible loads and photovoltaic curtailment act as a secondary control measure. However, the approach is constrained by limited storage capacity and the lack of real-time control implementation. To address these limitations, a reinforcement learning-based control framework is proposed as a future enhancement for adaptive and scalable VPP operation in New Zealand’s evolving distribution networks.

Aotearoa New Zealand’s distribution network faces significant strain from a 250% increase in distributed solar photovoltaic installations between 2013 and 2022. These trends increase vulnerability to failure of line-frequency transformers (LFT). The objective of this paper is to investigate the technical feasibility of retrofitting existing LFT footprints with integrated solid-state transformers (SST) with battery energy storage systems (BESS). Using MATLAB/Simulink to simulate an 11 kV radial feeder, the study evaluated performance under strenuous dual-peak winter demand periods with transformers loaded to 110% of their rated capacity. The research demonstrates the potential recovery of up to 80% of the physical volume compared to LFTs allowing the footprint to be repurposed for decentralised BESS. The findings indicate that the medium density storage technologies (0.15-0.35 kWh/L) are the best option. The technology enables a load curtailment of 20% reducing the transformer loading from 110% down to the safe 90% threshold. However, the dual-peak demand profile for Aotearoa New Zealand’s often depletes storage during morning cycles, while restricted charging windows limites utilisation of higher-density storage. Furthermore, while successful at the 0.4 kV busbar level, the aggregate impact of the main 11 kV feeder remaines minimal below 7.6%. It is recommended that future research focus on predictive control methods to optimise storage state of charge across successive peaks and the integration of downstream renewables to expand charging windows.

Solid-state transformers (SSTs) are key enabling technologies for smart grids, offering enhanced controllability, fault isolation, and active power quality improvement over conventional low-frequency transformers. Their front-end AC-DC converter must rectify grid voltage while maintaining a high power factor (PF) and low total harmonic distortion (THD). This paper presents the design, simulation, and hardware validation of a two-phase interleaved boost AC-DC PFC converter for a laboratory-scale SST, operating from 24 V AC to a regulated 48 V DC bus at approximately 100 W. A digital average-current-mode controller with interleaved 180° carriers, implemented on a TI C2000 microcontroller, regulates the DC link and shapes the input current. MATLAB/Simulink results predict approximately 89% efficiency and a well-regulated DC link, while the simulated THD and true power factor fall short of the 0.95 targets, attributed primarily to input diode-bridge conduction loss and zero-crossing distortion. A DC-bench prototype campaign confirms clean 50 kHz gate drive, correct 180° interleaving with the characteristic frequency-doubled output ripple, accurate sensing, boost operation, and a measured efficiency consistent with simulation. Because the power-factor control is an AC feature, true power factor, THD, and closed-loop regulation are reported from simulation, with full AC characterisation retained as future work. Bridgeless rectification and wide-bandgap devices are recommended to close the performance gap.

The growth of electric vehicles (EVs) and photovoltaic (PV) generation introduces new operational challenges for low voltage (LV) distribution networks, including transformer overloading, voltage deviations and bidirectional power flows. Mitigation measures often include the upgrading of conventional transformers and the re-conductoring of feeders. These methods become inefficient for uncertain load-growth paths. The technical effectiveness of coordinated distributed energy resources (DERs), such as rooftop PV systems, battery energy storage systems (BESS), and EV charging as non-wires alternatives (NWAs) to reduce the operational stress on local distribution transformers (LDTs) is assessed in this study. The representative Wellington suburban LV feeder is a 656-household feeder with 500-1000 kVA transformers. The feeder is modelled in DIgSILENT PowerFactory 2024 using the quasi-dynamic simulation language (QDSL) time-series at hourly resolution for one year. Four progressive scenarios are considered: (i) baseline operation without DERs, (ii) increasing PV penetration levels (5% in 2030, 10% in 2035, 28% in 2050), (iii) increasing number of EVs as load (5% in 2030, 10% in 2035, 28% in 2050) and (iv) integration of community-scale BESS for peak shaving. The results show that coordinated operation of DERs with BESSs can reduce transformer peak loading and improve voltage compared to standalone PV. In particular, the transformer-aware BESS dispatch offers a measurable peak shaving capacity and improves the local energy balancing, enabling a higher renewable penetration with less conventional infrastructure reinforcement. The practical role of DER coordination in improving LV network are more resilience and defers investment in the distribution systems as a scalable approach.

The Wellington Electricity distribution network confronts escalating operational challenges from ageing assets, seismic vulnerabilities, and localised capacity constraints amid decarbonisation. This study proposes and validates a coordinated demand-side management and distributed storage framework to enhance distribution hosting capacity, using quasi-dynamic Power Factory simulations of the Kilbirnie network across three scenarios: baseline operations, passive PV-battery saturation, and active demand orchestration. Passive PV-battery integration across residential, retirement home, and industrial bus depot feeders yielded substantial self-consumption, notably 38% at high-occupancy sites, yet triggered critical transformer overloads reaching 90% utilisation during evening peaks. Active demand-side management, synchronising flexible loads like hot water cylinders and EV charging with solar generation, dramatically alleviated these stresses, slashing residential transformer loading to 25% and creating thermal headroom for rigid night-time industrial demands. Key findings underscore that residential load shifting not only restores daytime reverse power flows but also accommodates electric bus depots, which otherwise would risk severe peaks. High-occupancy commercial loads demonstrated inherent flexibility, further amplified by orchestration. Overall, the framework unlocks latent network capacity, defers reinforcement, and bolsters seismic resilience without physical upgrades. Recommendations advocate mandating active control for residential interconnections, prioritising PV in flexible sectors, rightsizing transport storage for arbitrage, and deploying cross-sector dynamic tariffs. This Wellington-specific approach offers a blueprint for urban distributors balancing affordability, reliability, and electrification under N-1 standards.

The next evolution in power electronics is being driven by wide-bandgap materials—particularly silicon carbide and gallium nitride power semiconductor devices—which increase efficiency and power density, thus ensuring their integration into high-performance systems. One system poised to receive benefits from this progression is microgrids. This paper reviews common microgrid architectures, components, voltage and power levels, and power electronics to establish where wide-bandgap materials, specifically silicon carbide and gallium nitride, may benefit current and future microgrids.

The implications of an evolving energy landscape are far and wide. Not only is a shift in real power consumption and production occurring, but also notable change in the flow of reactive power, leading to complexities in grid voltage management. This paper explores reactive power management strategies, to investigate their impact on the power factor at grid exit points in New Zealand's transmission system, with emphasis on scenarios exhibiting leading power factor. Analysis of absolute reactive power criteria, power factor criteria and a hybrid of the two show that a hybrid approach at 0.95 power factor, with a transition point of 30% delivers promising results for reactive power management with minimal change in reactive power participation.