No abstract

This paper will review the recent and on-going changes to the power system in Great Britain (GB). One of the main challenges resulting from these changes in generation mix is the assurance of frequency stability in a low inertia system, and the provision of adequate dynamic responses to frequency changes, while meeting the requirements of the energy trilemma. Specifically, the increase in penetration of non-synchronous generation increases the risk of undesired operation of protection devices and contributes to a shortage of dynamic immediate response to frequency changes.A range of potential solutions will be briefly reviewed in this paper including, demand side response (DSR), energy storage, synthetic inertia, and synchronous condensers. A case study concerned with evaluating the impact that synchronous compensation may have in a low inertia power system will be described in the paper. The paper will conclude with an outline of the avenues for further study towards addressing the challenge of frequency stability and system inertia in a future power system. Index Terms--Demand side response, energy storage, low inertia system, power system protection, RoCoF, synchronous compensation, synthetic inertia.

There is a reduction in the percentage penetration of synchronous machines within the Great Britain (GB) power system leading to a decrease in inertia, and an increase in system rate of change of frequency (RoCoF) resulting from power imbalances. This raises the challenge of containing frequency deviations to within the relevant operational limits. As a result, steps need to be taken by the system operator to manage the risk to system security. In order to better understand this risk, this paper presents the challenge in light of the changing energy landscape and the current and future frequency response services available to contain frequency deviations. Although the current GB frequency response services may be capable of containing most events within frequency limits, in low inertia scenarios these responses alone are not capable of containing excursions within practical RoCoF limits. Consequently, further action must be taken to ensure system security. The system operator currently employs an interim solution of limiting the largest loss risk, depending on system inertia and the RoCoF limit. While this is suitable in the short-term, it is unlikely that this option will be cost-effective in the future.

No abstract

The changing power landscape introduces concerns about frequency management in a power system with significant amounts of non-synchronous sources of power. In islanded power systems like Great Britain and Ireland, electricity system operators are sometimes forced to undertake very expensive redispatch actions, including curtailing large amounts of renewable generation to meet statutory frequency stability constraints. Consequently, there is an imminent need to understand and quantify the limits that these constraints pose on the power system and develop metrics that can be easily integrated into current system planning and operational paradigm. This paper proposes three such metrics for quantifying the containment limits of a power system at a given operating point. The paper further argues that while the penetration of non-synchronous dispatch can indeed be used as the basis of a metric to define the containment limits of a power system, it does not account for variations in the contributions of other containment factors such as inertia. To address the aforementioned issue two alternatives are proposed: the first defines the containment limits of a power system without direct reference to penetration of non-synchronous power, instead it determines a relationship in terms of critical inertia. The second alternative improves upon the first and it considers the components of frequency stability constraints, offering an increased degree of flexibility in quantifying containment limits, and understanding the influence that certain key factors have on frequency containment.