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Floods can cause widespread and prolonged power outages by inundating substations. However, assessing the inundation failure of substations to improve power system resilience is challenging, as there may not be sufficient historicaldata to capture the impact of flooding on substations at a given location, due to their evident temporal and spatial variability. To tackle this gap in knowledge, this paper proposes a georeferenced statistical model that is not constrained by historical flooding data. The geo-referenced model embeds a hydrologicalmodel that uses established digital rainfall and topography data to simulate flood depths at the location of selected substations and calculate associated inundation risks. The stochastic inundation profiles are used within a Monte Carlo simulation to model substation failures and explore options to improve power system resilience (e.g., asset elevation). The proposed model isdemonstrated using a case study from Bintulu, Malaysia, where real empirical data was used to identify the breaking points of the power system and estimate probability density functions of energy not supplied caused by inundated substations. The simulation results show that substation failures can abruptlylead to significant energy not being supplied, whereas elevating the substation to withstand an additional 20 cm flood depth will significantly delay flood impacts, and effectively improve system resilience. The proposed methodology and key findings will enable system planners and operators to understand when and where the power system will experience energy losses under unpredictable extreme floods and help them to decide on the most effective resilience enhancement strategies.

In small/medium-sized isolated power networks with low rotational inertia and high penetration of renewables, generation/load contingency events may cause large frequency excursions, potentially leading to cascading failures and even blackouts. Therefore, it is crucial for system operators to be able to monitor the state of the network in real-time and predict the maximum possible frequency deviations at all times. This paper presents a real-time frequency stability (RTFS) tool developed by the Australian Energy Market Operator (AEMO) and operationalized in the control room for the South West Interconnected System (SWIS) to ensure that the available spinning reserve is sufficient and fast enough to arrest frequency excursions under any conditions, and particularly low-inertia ones. To reduce the computational burden and complexity of the different turbine-governor models, a simple first-order lag function with two adjustable variables has been used for each of the generator. These adjustable parameters, along with other key model parameters such as load damping and inertia, have been calibrated against actual frequency response using high-speed fault recorder data from historical events. As demonstrated in several case studies, the real-time tool has proven to be accurate at predicting the trajectory of system frequency after credible contingencies, thus suggesting that similar implementations could be carried out elsewhere while power systems worldwide progress towards lower inertia.

Rural electrification is critical for the social and economic development of developing countries. Off-grid energy systems are attractive solutions for rural electrification which may offer technical and economic benefits compared with network expansion. However, given the conditions in remote areas, off-grid energy systems are often exposed to high impact and low probability (HILP) events such as natural hazards. This is an issue as off-grid planning practices traditionally focus on average performance reliability indicators, and neglect studying resilience to HILP events. This paper proposes a practical off-grid assessment framework which brings together average and risk performance indices to optimally size off-grid energy systems and quantify their reliability and resilience performance. The proposed methodology, based on Sequential Monte Carlo simulations, is demonstrated with two off-grid energy systems: PV and CHP based systems. In addition, through case studies with applications on windstorms, the impacts of natural hazards are systematically quantified and explicitly considered in the sizing of the off-grid plant. Power system planners and operators can use this framework to quantify the reliability and resilience of off-grid energy systems and inform the decision-making on optimal portfolios for rural electrification.

In light of the significant uncertainty that distribution systems are facing with the uptake of distributed energy resources and ongoing technical and commercial transformations, planning emerges as a daunting task. Tools supporting decision making in uncertain environments become key to make cost-effective and risk-aware decisions. However, no clear comparison exists across methodologies whereby the relative cost and risk implications are assessed. On these premises, this paper proposes a comparative analysis of stochastic optimization, least-worst regret, and robust optimization, with specific application to distribution systems. After reviewing the features of each methodology, we introduce a planning optimization formulation, based on mixed integer linear programming, which allows a comparative assessment. We then test our modelling on a test case, demonstrating the cost and risk implications of the investment decisions selected by the different methodologies. The results provide novel insights on these methodologies, aiming to facilitate their adoption in future distribution system planning.

This paper investigates the fast frequency response (FFR) capability of large-scale hydrogen electrolyzers (HEs) and their contribution to frequency control in low-inertia conditions, with focus on understanding the impacts of stack voltage-current (V-I) nonlinearity. We propose a HE stack model which includes a variable internal resistance to capture its V-I nonlinear behaviour. We then study the negative impacts of this nonlinearity on HE FFR capability and its mitigation solutions via proposing design specifications for the HE power-electronics interface (PEI) (DC-DC-AC) control. To do so, first we highlight the need for simultaneous stack voltage-current control in HE active power (FFR) control and propose a relevant cascaded V-I controller for stack-side converter via novel HE stack equivalencing with a capacitor. Second, we modify the DC-link voltage level in the HE PEI to avoid the stack V-I nonlinear effect. Simulation results show how the stack V-I nonlinearity might limit the HE FFR potential and how the proposed PEI controller represents an effective solution.

Integrated energy networks will be key to develop low-carbon multi-energy systems. Steady-state multi-energy vector power flow (MEVPF) analysis is the cornerstone of integrated network studies. However, despite a wide range of recently developed models, there are still significant challenges that have not been fully addressed, including applicability of different MEVPF formulations to different network topologies and node types, flexibility in adapting new connections and components, and appropriate convergence behavior for different loading levels and initial conditions. This paper analyzes different formulations and their relevant applicability and convergence properties for the steady-state MEVPF problem and proposes a new unified, loop-free formulation for heat and gas hydraulic equations. Both theoretical and numerical analyses conducted on a canonical system show the superiority of the proposed approach over the other available formulations analysed in terms of flexibility of applications and convergence performance.

Green hydrogen production via electrolysis from renewables is a promising method to achieve deep integration of renewable energy sources (RES) and boost decarbonisation of the whole energy system. Current studies mainly focus on low penetration levels, where both RES and electrolysers are treated as price-taker in the market. Here we develop an integrated hydrogen-electricity market simulation and investment tool, based on a mixed integer linear programming unit commitment with flexible hydrogen demand, with the aim of studying the techno-economic performance of a system with large-scale adoption of RES and electrolysis. We show how in a RES-dominated electricity market the marginal price could be set by the willingness-to-pay (WTP) price and installed capacity of electrolysers. The payback time or RES and electrolysers varies significantly for different resource portfolios and WTP prices of electrolysers. The results demonstrate how win-win RES and electrolyser economic equilibria can be achieved to produce large volumes of green hydrogen in low-carbon power systems.

The rapid uptake of renewable energy resources and displacement of synchronous generators may pose threats to system frequency stability and resilience. Starting from the August 2018 separation event in Australia, this work models and discusses how utility-scale PV plants could contribute to frequency stability and resilience of islanded areas following separation events. In this regard, a converter-based dynamic equivalent of aggregated PV power plants is proposed which takes into account possible practical issues such as measurement and coordination delays. The unknown parameters of the proposed model are identified through a novel closed-loop identification process based on least-square minimization. Also, a simplified model is constructed to reproduce the system frequency during the event under study, thereby capturing continuous impact of PV response on the frequency. The proposed aggregated model can considerably reduce the complexity of frequency stability analysis as well as its processing time while capturing with good fidelity the frequency response from PV farms.

Demand response (DR) programs (such as peak shaving, load shifting, capacity management, etc.) are often viewed as a promising candidate to alleviate network congestion and delay assets investments. The natural thermal inertia of buildings and utilisation of energy-intensive thermostatic loads make them an ideal candidate for DR. The presented work first puts forward a bottom-up methodology to accurately model the temporal and spatial end-use energy consumption profiles (e.g. lighting, heating ventilation and air-conditioning (HVAC), and other appliances etc.) at a city level. This then serves as key information to systematically evaluate the flexibility potential from HVAC control of buildings at different aggregation levels, such as precincts, districts and city. Second, different HVAC controlled strategies are deployed to shift buildings electricity consumption from peak demand periods. The technical and financial impacts of HVAC control strategies are then demonstrated on the city of Melbourne to appraise flexibility at a city scale. Furthermore, potential peak load shifting and financial savings are quantified, while accounting for the time of the day, the influence of climate, HVAC operation and occupants’ comfort. Results indicate that the flexibility from the thermal inertia of buildings is highly dependent on the thermal characteristics and weather conditions, and has significant spatial disparities that are deeply linked to building stock distribution.

This paper is aimed to investigate the capabilities of utility-scale energy storage system (BESS) in provision of both contingency and regulation frequency control ancillary services (FCAS). In particular, the fast mode-change capability of battery and its corresponding impacts on its frequency support ability is investigated through dynamic modelling of the 100 MW Hornsdale battery during the August 2018 separation events in Australia. In this regard, a converter-based battery dynamic model is presented which includes current- bidirectional DC-DC converter, thereby being able to observe its fast mode change as a response to severe frequency excursions. Also, an active power-frequency characteristic is proposed which considers the impact of battery pre-contingency operating point on its available headroom for primary frequency response provision. Moreover, an active power reference generation strategy is suggested which takes into account regulation FCAS provision through automatic generation control (AGC) as well as contingency FCAS provision through droop controller. Finally, it will be shown how BESS installed in Victoria might have potentially prevented the severity of the August 2018 event by prevention of both under-frequency load shedding (UFLS) and secondary photovoltaic (PV) trip.

Conventional capacity credit evaluation only focuses on generation adequacy. It is assumed that as long as there is sufficient capacity in the system to cover demand, there will be enough facilities to keep real time balancing of system load and generation, namely system flexibility. However, recent studies have demonstrated that system may suffer from lack of flexibility at operational stage in the process of increasing penetration level of wind or solar. Thus, consideration of flexibility is necessary in capacity credit evaluation in high wind and solar penetrated system. In this work, the concept of capacity credit is extended with consideration of both generation adequacy and flexibility. Then, a framework to evaluate the capacity credit with the extended definition is proposed. The proposed framework is applied to evaluate the capacity credit of wind, solar and pumped hydro storage in the renewable energy zones proposed in AEMO’s Integrated System Plan. It is demonstrated that allowing wind and solar curtailment at operational stage can improve capacity credit to some extent. Also, coordination of wind, solar and pumped hydro storage can increase their capacity credits significantly.

Most research relevant to power system adequacy with large-scale penetration of variable renewable energy sources (RES), including assessment of RES capacity credit, has focused on relatively small penetration levels, up to some 30%. However, RES contribution to supply peak demand with much higher shares of renewable energy, and even close to 100%, has been less studied, and the actual feasibility of such a RES-dominated system in terms of preserving a certain level of system reliability is as yet unclear. In this work, a Monte Carlo simulation model is adopted to quantify the system adequacy level. The availability curves of conventional generation units are simulated based on the state-duration sampling method combined with a three-state transition model of generation units. Parametric studies are conducted to explore the characteristics of system adequacy levels under different RES penetration levels as well as different wind and solar installed capacity mixes. At the same time, the benefits of coordinating large-scale energy storage, modelled as pumped-hydro storage plant, with RES are assessed and demonstrated. The results from several case studies on a reduced test version of the Australian eastern interconnected power system highlight how the proposed characterization method can inform strategic, reliability-aware planning of future RES-dominated power systems.

Grid integration of renewables and replacement of conventional synchronous power plants may significantly decrease system inertia, which can potentially lead to frequency stability issues. Among alternative solutions to support system frequency in low-inertia conditions, and thanks to their unique technology features and highly controllable power electronic converters, utility-scale battery energy storage system (BESS) can be deployed to provide fast frequency response (FFR). However, possible undesired knock-on effects from such FFR operation, e.g., its negative interaction with equipment protection relays, and particularly for interconnectors, have not been adequately investigated. In this context, this paper first demonstrates with an illustrative analytical example how BESS FFR could potentially induce undesired trip in out-of-step interconnector protection schemes. Then, a case study example based on an Australian test system is presented to discuss how FFR from the 100 MW Hornsdale BESS located in South Australia might have contributed to the trip of the Heywood interconnector with Victoria during the August 2018 separation event. Finally, it is shown how FFR from BESS in Victoria could have enhanced frequency control and even prevent system separation, hence highlighting the importance of FFR location.

The paper investigates the frequency and voltage dynamics and stability in power systems with increased penetration of inverter-based renewable energy sources (RES). The case studies presented within the paper show that the frequency dynamics (frequency nadir and rate of change of frequency) is not only affected by the decrease in system inertia but also by increasing frequency/voltage interactions when the proportion of RES exceeds that of synchronous generation. Furthermore, the critical fault clearing Time (CCT) analysis for transient stability indicates that RES fault ride through (FRT) and their settings can have a significant impact on the nearby generators. The studies also demonstrate that voltage and frequency interactions can be reduced and transient stability of synchronous generators improved by applying dynamic voltage support in weak areas of the system.

The increasing penetration of non-synchronous generators, accompanied by retiring/displacement of synchronous generators has created a number of new operational issues in the Australian National Electricity Market (NEM) network, such as low-inertia conditions. Low-inertia power systems are likely to experience relatively large frequency variations following a generation/load mismatch. This is evidenced by a recently occurred event in the Australian National Electricity Market (NEM) grid, which led to cascading failures and electrical separation of the two states of Queensland and South Australia from the rest of the NEM. This paper first provides an extensive description of the event occurred on 25th August 2018, whose high-level dynamic behaviour was simulated in a NEM reduced test system. Secondly, the use of grid-scale battery energy storage system (BESS) in providing primary frequency response (PFR) is investigated as a potential countermeasure to cascading failures. Simulation results show BESS could have potentially avoided under-frequency load shedding (UFLS).

The deep penetration of distributed energy resources (DER) and renewables into electrical networks is increasing generation variability and uncertainty. One way of addressing this issue is Virtual Power Plants (VPPs), which aggregate a diverse set of DER to act in various electricity markets as a single entity. This work introduces a modelling framework which allows a VPP to operate in multiple markets, considers multiple energy vectors, and dispatches devices at 5-minute intervals, while operating within local network constraints. To ensure framework tractability, it is divided into a three-stage optimization: the high-level scheduling the devices; the mid-level dispatching them with 30-minute timesteps over a 24-hour horizon; the low-level performing the 5-minute dispatch. A real case study with electricity and hydrogen in South Australia is conducted. Results show the VPP coordinating renewable generation, dispatchable load, hydrogen storage and thermal generation to maximize earnings over multiple markets whilst adhering to local network constraints.

This paper reports on a portable C sensor of trace sensitivity and yet resilient to saturation and poisoning, suitable for field use onboard unmanned ground vehicles. The sensor is based on a FAST Gas Chromatographic module (FAST-GC) and a Quartz Enhanced Photo Acoustic Spectroscopy (QEPAS) module, and can detect and identify threats rapidly and reliably even when challenged by higher concentrations of common interferents like gasoline and paint fumes.

The dispatch of different types of hydropower plants such as storage, Run of River (RoR) and pumped affects downstream water flows and power generation. These short-term operational impacts (e.g., hourly water release) must be properly modelled and quantified to capture the flexibility of interdependent hydropower plants to provide system support (e.g., reduce energy costs). This paper presents a Linear Programming (LP) model to simulate the operation of interdependent hydropower plants where dedicated hydrologic routing constraints are used to track the flow of water, and quantify relevant impacts on generation. The contribution of this work is the explicit quantification in cost and energy terms of the value of capturing short–term interdependencies between hydropower plants associated with the use and release of water by upstream plants. The results demonstrate that, by explicitly considering interdependencies, it is possible to better coordinate their operation and optimize hydropower generation.

The rapid uptake of renewable energy sources (RES) and displacement of synchronous generators is introducing a number of security challenges, particularly in terms of frequency and voltage stability, whose interactions in RES-dominated systems are to be fully understood yet. This paper models and discusses the application of utility-connected battery energy storage system (BESS) for provision of integrated dynamic services, i.e., simultaneous provision of primary frequency/active power and voltage/reactive power control. To investigate how BESS should respond to system contingencies, a detailed BESS dynamic model is presented along with comprehensive discussions on interaction of frequency and voltage responses and proposing suitable control signal generation algorithms. Simulation results illustrate the BESS capability to provide integrated dynamic services as proposed, highlighting the significance of response prioritization.