Importance of Inertia in Island Power Systems

The accurate modelling of inertia in an islanded power system is crucial when attempting to integrate low or inertia-less generation into the network, particularly those from intermittent sources, e.g. solar PV, converter-fed wind turbines, etc.

In the context of synchronous generators, the term “inertia” generally refers to the kinetic energy in the rotating mass of a generator shaft. The inertia depends on the speed of rotation and mass of the shaft, i.e. the heavier the shaft and faster the rotational speed, the higher the inertia. Under normal operation, the instant a new load is applied to the system, rotational energy (inertia) is converted into electrical energy to supply the load. As energy is removed from the system to supply the load, the speed of rotation (or frequency) decreases. This is commonly referred to as the inertial response and occurs before primary frequency control actions (e.g. from governors) take place. As a result, inertia has a direct impact on transient frequency deviations resulting from sudden changes in generation and load.

Effects of varying inertia on system frequency

In large interconnected systems, these frequency deviations are minor since the instantaneous mismatches in generation and load are very small relative to the amount of synchronous generation dispatched. However, in small island systems, these frequency deviations are much more significant and can even lead to frequency collapse.

By virtue of their remoteness and lack of other resources, the small island power systems that are normally found in island nations and archipelagos typically have high penetration of diesel engine generation. As diesel engines generally have low inertia, the inertia constants selected during system modelling can have a large effect on frequency swings. For example, consider the load acceptance (25% load step event) of a 1.5MVA diesel generator with varying inertia constants:

The simulations show that maximum frequency swings can vary from 1.235Hz up to 3.548Hz depending on the inertia constant selected.

Small power systems are usually equipped with under-frequency load shedding (UFLS) systems to prevent network collapse during frequency swings and active power deficit events (e.g. trip of generator). Integrating inertia-less sources such as solar PV plants would displace synchronous generation and thus reduce the total inertia in the system. Grid simulation studies are performed to predict whether or not the UFLS system is at risk of operating during normal day-to-day fluctuations of the solar PV system, and this requires fairly accurate modelling of the system inertia.

Selecting appropriate inertia values

Generator inertia values are usually found in vendor / manufacturer data sheets and are often expressed as a moment of inertia quantity (e.g. in kg.m2 or slug.ft2). While some software packages can accept these quantities directly as inputs, other programs require that they are converted into per-unit inertia constants (H).

In some cases, particularly in older systems or networks with temporary generators, the inertia data is not available and must be estimated. Based on our database of actual equipment data, the following inertia values can be used as guidance:

New electricity business models: Local distribution cooperatives as market participants

Transmission and distribution networks are natural monopolies and in Australia (as in most other countries), they were once part of vertically integrated corporations comprising either the complete or significant portions of the electricity supply chain (e.g. the state electricity commissions). During the industry restructure of the mid-1990s, these corporations were broken up so that in each state, there was a single monopoly transmission company (e.g. TransGrid, Western Power, PowerLink, Electranet, etc) and one or more geographically-focused distribution companies (e.g. Ausgrid, Ergon, Citipower, etc).

Despite the unbundling process, the network businesses are still relatively large in scale, with approximately 550,000 km of poles and wires shared between just 18 network companies in the National Electricity Market (NEM). In particular, distribution companies can own assets from sub-transmission level (e.g. 132kV) all the way to the 240V meter box at a residential premises.

Thus a natural question to ask is – can present-day distribution network service providers (DNSPs) be further unbundled?

Local distribution cooperatives

One possibility is for cooperatives in a localised geographical area (e.g. a suburb or housing estate) to acquire ownership of the low voltage distribution assets in the area, connect to the distribution network at one or two points as a major customer (e.g. at kiosk substations) and participate directly in the wholesale electricity market as a single coordinated entity.

Source: Identicoin

Such a local distribution cooperative could be a microgrid with a mix of its own distributed generation and storage, or it could simply be a consumer aggregating the households in the area (e.g. Virtual Power Plant). However, to get the most out of participating in the electricity market, the cooperative needs to have some level of controllability. What this could mean in practice is an energy management system that can control discretionary household loads (such as hot water heaters, air conditioner thermostat settings, swimming pool pumps, washing machines, etc), as well as generation and storage resources, in order to optimise the kWh price on the spot market for the whole cooperative.

For example, when the spot price is high due to peak loading or a binding network constraint, the energy management system can control discretionary loads, generation and storage to either limit energy purchases or sell energy back to the market (and vice versa when spot prices are low).

The cooperative itself could be run like a body corporate or owners corporation, with a professional management company appointed to maintain and manage the local distribution assets (e.g. poles, lines, energy management system, etc) on behalf of the owners. The cooperative acts like a micro-retailer and the owners simply pay an equivalent electricity tariff to maintain the system. In some circumstances, the cooperative could even pay out a dividend from profits made trading on the wholesale electricity market.

Transferring ownership

A looming obstacle for local distribution cooperatives will be convincing (or coercing) DNSPs to sell / transfer their assets to a cooperative. Under the current regulatory scheme, networks are paid a guaranteed return on their regulated asset base (RAB), and this of course gives DNSPs very little incentive to reduce the size of their RAB.

In the United States, the recent track record for municipalising electric utilities has been mixed. In some cases, local municipalities were able to negotiate the purchase of utility assets without much pushback from the incumbent utility business, typically when the incumbent saw strategic gains from pulling out of the area. In other cases, there was significant resistance from the incumbent to municipalisation proposals and negotiations were difficult and acrimonious.

However, there is a case to be made that micro-scale municipalisation proposals like local distribution cooperatives could face less resistance since the value of the assets are relatively low.

A new role for DNSPs

If local distribution cooperatives were to emerge as viable businesses, this could signal a trend towards a widely distributed ownership of electricity network assets. Micro-scale networks owned and operated by the locals who live there would change the landscape of the electricity supply industry. Where present day DNSPs have to plan and optimise a network across large geographic areas, the local distribution cooperatives only need to worry about their own small sections of the grid. The role of DNSPs would be more akin to what transmission networks are now – a backbone for the bulk supply of power to the local networks. Two or more cooperatives could potentially build private interconnections between each other’s networks, bypassing the DNSP altogether.

Moreover, there is the possibility that local distribution cooperatives can negotiate their own terms of connection to the DNSP, for example, customising the trade-off between network reliability and use of service charges. Of course, such provisions would necessitate a fairly significant change in the rules by the AEMC, but it has the potential to give more choice and responsibility to end-users regarding their own electricity supply and how they choose to manage risks and resources.