Hybrid systems have evolved from a research concept and various pilot project. They are now the most cost-effective source of power in a wide variety of settings. There are also a huge variety of types of hybrid systems depending on the application. This presentation will provide an overview of that history, starting with small systems for energy access in remote areas of developing countries without any pre-existing power infrastructure. Another promising early application were islanded systems, both geographic islands and electrical islands, such as the 200 remote indigenous communities in Alaska.  The falling cost of solar PV and various forms of batteries, particularly lithium has dramatically changed the results of least cost design optimization.  The lessons learned over these 30 years of modeling, pilot projects, and development experience are now being applied to very large grid-connected hybrid systems as continental-scale electric grids decarbonize.  The ability of these large grids to absorb the levels of solar and wind that have become common for smaller grids depends on the hybridization of large wind farms and solar parks with utility-scale batteries. This presentation will conclude with descriptions of how the modeling requirements have evolved to respond to these new challenges.

Despite holding abundant renewable energy resources, most islands present extreme external energy dependency on fossil fuels, ultimately causing high energy costs. In order to remedy such situation, many island communities are targeting the abandoning imported fossil fuels in favour of local renewable resources. The U.S. Virgin Islands emerged in 2010 as front runners in reducing fossil fuel imports and stabilize electricity costs with energy efficiency schemes along with wind and solar power installation. They had significant progress over the years, hindered by relatively expected stability issues. Then, in 2017, Category 5 hurricanes Irma and Maria struck the islands, causing extensive damages, which, among other things, affected up to 90% of the transmission lines. After recovering the system, the focus of the local system operator is on increasing the reliability and resiliency of the grid.

In the case of Saint Croix, solar power covers around 10% of the peak demand and 2.5% of the overall energy needs in 2022, although this does not include installations at distribution level. Wind power is not yet present in the island, but its addition is already planned along with more solar PV, and battery systems. In this context, our work focused on developing optimal economic dispatch attending to the particular conditions of the island, paying special attention to positively contributing to reducing instability. While minimizing the stress on the batteries by limiting their cycling. The approach considers two different methods to provide asymmetric reserves. One simply by ensuring 25% of the present load, and the other attending to the N-1 contingency. Besides, the study will explore the effects of strengthening the renewable installed capacity.

Hybrid power plants are emerging as an adequate solution to address emerging power system needs, since they can provide a wide palette of services by leveraging the capabilities of different technologies. At the same time, storage has been recognized as a critical component for the energy transition,

in order to deal with the new characteristics of inverter-based generation. In particular, it is becoming clear how a storage system can provide certain grid services, but how to extend these ideas to hybrid storage systems is not fully understood. In this work we present an optimization-based framework that is able to deal with the typical fast time scales associated with storage, at a reasonable computational cost. The approach relies on piecewise affine linear approximations, that can be reformulated as mixed integer linear programs. An example focused on peak shaving shows the benefits of the proposed approach.

Hybrid power plants (HyPPs) combining different renewable energy sources with battery energy storage systems (BESSs) present multiple advantages and might become a key part of the energy transition, but the still high price of BESSs and varying market conditions could slow down the investment on them. In this paper, the optimal operation of a HyPP consisting of wind, solar photovoltaic and a BESS operating in the Iberian Electricity Market is analysed under the market scenarios between 2018 and 2022. The study reveals the significant effects of the market conditions regarding the revenues obtained by installing BESSs, but claims the need for new market mechanisms to ensure their feasibility. Moreover, a closer market study indicates that price difference rates between markets have not varied significantly, resulting in similar optimal operation strategies in the studied years.

Evolution of Battery Energy Storage Systems (BESS) made them a pivotal asset to successfully deal with hybrid power systems with high Renewable Energy Sources (RES) penetration.

The main objective is to achieve stable and secure operation of the electrical system. All services required to maintain system stability and security are traditionally provided by synchronous generators but can now also be provided by high power grid forming inverters (GFM), supported by batteries and the right control and automation to make them into Virtual Synchronous Machines (VSM). In addition, BESS allows to accumulate green energy excess to be released in time of need without fuel consumption or green house gas emissions.

Classic power systems unit commitment and optimal dispatch problems have to be industrialized and tailored to small/medium scale hybrid systems with large RES penetration in which leveraging forecasts and correctly capturing BESS-specific constraints, cost and efficiency items become key to improve the technical and economical performances of the whole system.

This paper provides insights on BESS value proposition in terms of both power and energy management. Real plant data as well as simulation results obtained with dedicated tools are discussed to explain and highlight how advanced BESS value can be fully exploited.

• System behavior following load and generation trip events is analyzed benchmarking scenarios with and without BESS to quantify power systems stability and security improvements.
• Longer term energy flow simulations are performed benchmarking scenarios with and without BESS to provide insight into how and to which extent advanced Energy Management Systems (EMS) can support automatic and optimal decision making to minimize electricity cost and carbon footprint while taking into account operational constraints.

The paper demonstrates and provides simulation and experimental evidence that advanced BESS bring to the system a unique combination of technical features and a pivotal additional degree of freedom key for successful operation of hybrid power systems.

These benefits come at the cost of increased complexity which can however be comfortably addressed with specialized control and management systems which are nowadays supported by viable and trustworthy technology solutions and products from industry players such as Hitachi Energy, rich with hybrid systems domain knowledge and expertise.

By using an external signal for the synchronisation, an island grid with grid-forming inverters (GFM) can be operated

with constant frequency. The global positioning system (GPS) provides a periodic pulse with suitable accuracy. It is used to

define the grid frequency and a reference for the voltage phase angle. A digital counter on the control hardware determines

the phase angle. The counter is reset with each pulse of the GPS. An active power - angle droop control leads to partial

power sharing between the GFM and reduces distortions due to non ideal synchronisation. Furthermore, the grid operator

can adjust the voltage reference phasors of the GFM to control the power flow in the grid. An island grid with two GFM

and a hydro power plant is studied in simulations. The investigated power system is an altered and simplified grid model

of Suðuroy, in the Faroe Islands. The effects of a load connection and a distorted GPS synchronisation are studied. The

stable operation of the power system with the fixed-frequency approach is demonstrated.

Abstract

After a blackout, critical infrastructure can be resupplied through a microgrid on distribution grid level. In this way, considerable damage to society can be avoided. This microgrid must be separated from the higher-level grid and interconnected by switching operations in that way that as many critical infrastructures as possible can be resupplied. In this case, a controller with automated processes is important, because fast actions are necessary during a blackout. The controller must stepwise expand the microgrid to avoid high fluctuations. Since it is not trivial to test a microgrid on distribution level during daily grid operation, extensive simulation tests are necessary to validate such a controller. PowerFactory is ideal for this purpose, as it can be used to simulate the dynamic processes in microgrids. Furthermore, an interface is needed to connect the controller with the microgrid. This interface enables the exchange of control commands and measurement values between the controller and the microgrid. It must also ensure the independence of the controller so that it can be used in simulation and in the field. This paper presents an interface concept for an automated control of a microgrid simulation. Furthermore, its practical suitability is evaluated.

Structure

The first step in this publication is a description of the conceptual design to show the two software programs, MATLAB and PowerFactory, and their communication interfaces. In addition, the advantages of a control system programmed in MATLAB are explained to demonstrate the benefits of this software. Furthermore, the software PowerFactory is presented and analyzed to highlight its reliability and accuracy in calculating a dynamic simulation. Afterward, the data exchange and the developed program are presented to describe essential processes. Subsequently, the developed concept is evaluated using an exemplary microgrid and test scenarios with different switching operations. The results of these analyses provide the basis for the practical suitability of the concept.

Key results

The developed interface transmits control commands from a controller to a microgrid. Moreover, sensor measurements from the microgrid are sent to the controller. This concept is necessary to build up a microgrid after a blackout to resupply critical infrastructures. In addition, the interface allows the controller to be tested with a simulated grid and then used in the field.

Isolated French power systems, such as the overseas departments and territories, are facing high ambitions for decarbonization of the energy mix. These systems encompass a wide variety of situations, with wide range of consumption levels and numerous decarbonization strategies, which include massive penetration of solar and wind generation. This paper provides an overview of the key technical challenges that EDF SEI (Systèmes Energétiques Insulaires) is currently solving to ensure a robust system operation with high shares of renewable electricity.

Like many nations, the Isle of Man is committed to net zero emissions by 2050.  75% of the island’s greenhouse gas footprint - 500,000 tonnes of CO2 per year - is related to energy use.  The island is almost entirely reliant on gas & oil for electricity, heating & transport and there are currently no wind farms, solar parks or energy storage facilities.

The Isle of Man lies in the Irish Sea, situated midway between the UK and Ireland.  The island has 85,000 residents, with a land area of 571 km2 and a shallow territorial sea of 4000 km2.  In total, the island uses around 1300 GWh of energy per year, of which 360 GWh is electricity, most of which is generated from a gas-fueled (CCGT) power plant with diesel engines in reserve.

There has been some hesitation on utilising the island’s enviable natural resources of wind, water & mountainous terrain.  There are worries around maintaining a stable & resilient electricity grid and the cost of upgrading & reinforcing the grid to accommodate intermittent renewables plus a 2-3 times increase in electricity demand.  The solution promoted by the state grid operator is to buy a majority of its future power from green sources in the UK via an existing and a planned interconnector.  However, the steep rise and unpredictability in prices, has changed the question to can the Isle of Man become self-sufficient in renewable energy and, if so, how?  This is the reason for the research reported here.

We have used the dual approach of energy system simulation and power-flow modelling to start building two different pathways for an economic transition from gas & oil to an island powered entirely by wind & solar energies supported by varying amounts of storage.  Other options such as biomass, nuclear, tidal, wave & geothermal energies were found to be either too expensive or not feasible based on the island’s geography & geology.

The first pathway is essentially a British Isles-style transition involving full electrification and has been completed.  The second pathway, based on Denmark-style plans involving district heating & a certain amount of green hydrogen, is now underway.  Both pathways lead to net zero emissions from power generation through broadly overlapping steps:

1) Phase in onshore renewables.

2) Develop energy storage schemes.

3) Phase out gas power from the CCGT plant, whilst keeping the diesel plants as back up.

4) Build a second interconnector & strengthen key parts of the grid.

5) Phase in electric vehicles with carbon pricing.

6) Phase in sustainable heating through incentives.

The CCGT plant could be converted to a synchronous condenser to stabilise electricity or, alternatively, a new hydrogen turbine would allow it to continue as a thermal power plant.  In the Denmark-style model, new district heating schemes use heat from seawater-sourced communal heat pumps, concentrated solar & energy from waste.

Both pathways are economic, the main difference being up-front cost versus operating cost.  The models also show that, up to a reasonable size of over-capacity in wind energy, the larger the interconnector, the greater the value from exports, particularly if stored energy can be used in arbitrage, which helps justify the cost of pumped hydro schemes.  Ultimately, the island could serve as an energy hub for offshore wind farms, linked to markets in the UK & Ireland.

Continual de-carbonization and de-centralization of electrical grids has highlighted the need for ever more advanced plant controls and design sizing. New technical requirements resulting from these market movements are developing faster than standards and grid codes can be adapted. Meanwhile, component suppliers offer various forms and implementations of grid-forming controls and customers request new applications to be delivered today as well as "tomorrow".

How can market players develop standardized plant controls and sizing methodologies in the face of an industry in flux?

Fluence Energy GmbH is in a unique position to advise and guide this discussion thanks to their breadth of project implementation (Island Microgrids, Industrial Black-start, Advanced Grid-Following, and On-Grid Grid-Forming BESS for TSOs) and depth of in-house product development (From battery pack to PCS to Hybrid Plant Controls) as well as integration utilizing various PCS suppliers.

This white-paper will address the design sizing methodologies, options, and plant controls development of BESS plants taking into consideration:

• Unique Power, Energy, SOC limitations of Batteries
• Manufacturer specific grid-forming control characteristics
• Novel customer applications and new ancillary service use cases 
• All while ensuring compliance to present and potential future regulations and reliable protection operation

Anonymized empirical results from past implemented projects and in-house testing will be presented and discussed to provide insight into the potential pitfalls of system design and to drive a broader industry discussion as to how future standards, regulations, and markets might be best structured to ensure the fullest implementation and optimization of hybrid power systems by leveraging the unique and advanced capabilities and controls of BESS plants.

The Faroe Islands are aiming for 100% renewable electricity generation. The complexity of operational power systems with a high level of renewable generation necessitates accurate dynamic models. Many power systems, including the Faroe Islands, do however consist of generation units with old governors and automatic voltage regulators, in which suitable models and parameters are unknown. Obtaining dynamic models with parameters that replicated measurements proved to be challenging using existing procedures. Therefore, this paper presents an alternative and combined procedure for identifying and validating the controllers and parameters. The procedure utilises measurement data from trip tests, standard controller models, and an optimisation algorithm. The procedure also combines hybrid simulations and system-wide simulations. A successful application of the proposed procedure on the power system of the Faroe Islands is presented. The proposed approach can be applied to other power systems and is especially suitable for other island power systems of similar size to the Faroese power system.

how to submit an abstract

While it is consensus that hydrogen will play a key role in climate neutral energy systems, the where,

when, and how of many hydrogen applications remains unclear. Techno-economic modelling of

potential hydrogen ecosystems at Fraunhofer ISE aims to addresses these questions by reproducing

realistic technical behaviour of plants and systems with nonlinear mathematical and physical

correlations. The goal is to optimise the system’s setup and operation towards economic and other

objectives.

Geographic conditions determine the use of hydrogen. Renewable energies are necessary to produce

hydrogen, transport distances influence optimal transportation technologies and costs, and different

infrastructure needs to be available respectively installed. Therefore, my dissertation analyses

possibilities to combine geo-information analyses with techno-economic modelling to create a “geo-

techno-economic analysis”. This includes the identification, creation, and transformation of necessary

geodata and the development and integration of methods for spatially resolved modelling in the

techno-economic optimisation process.

This paper gives insights in the methodology, application, and potential of the geo-techno-economic

analysis. First preliminary results are presented, including: (1) costs and important locations for the

production and distribution of hydrogen, (2) transformation pathways for potential hydrogen

applications, (3) geographic, economic, and infrastructural preconditions that enable hydrogen

ecosystems and (4) optimal transportation technologies. A special focus lies on the analysis of autarkic

energy system and the relevance of import possibilities for electricity or hydrogen.

Decarbonisation of heat is a crucial step in the process of mitigating climate change. If the electrical power system supplies mainly renewable energy, heat pumps are a viable low carbon heating system. Heat pumps can either be installed for individual properties or in central district heating (and cooling) schemes.

To proof viability and identify benefits of renewable heating solutions on a community energy approach, I analysed an area in Castlebay on the Isle of Barra. Heating of residential, public and commercial properties was assessed in two-steps: Firstly, individual heating solutions were evaluated and compared to a low-temperature district heating system. Secondly, the district heating system was designed in more technical detail.

My proposed district heating scheme includes 119 properties with a total heat demand of 2.1 GWh/y, resulting in a distribution grid length of 2.3 km. Seawater as a source for the heat pump was found as most suitable, with an average seasonal performance factor of 3.8. Equipment was sized using a 1h timestep model, resulting in: heat pump 500 kW, thermal store 70 m³, electric heater 100 kW, backup fuel oil boiler 600 kW. Investment cost of £2.7 million is higher than individual heating units. This results in moderate cost of delivered heat of 8.7 p/kWh. The district heating allowed integration of further wind power into an otherwise constrained grid. A turbine with 180 kW capacity was selected. District heating in combination with wind power can reduce emissions by 634t CO2-eq/y.

These results are based on my master thesis from 2019 (publicly available) and were indicating that district heating has high potential for decarbonisation but also high investment cost. The recent rise of fossil fuel prices changes these boundary conditions and makes heat pumps even more viable.

Case studies- IRENA grid assessment studies for

• Fiji,
• Vanuatu and
• Dominican Republic