Grid Code Requirements 92

Parts of the following two sub-sections of the thesis, covering frequency response and synthetic inertia, have been written up for Wind Energy by Banham-Hall et. al. [87]. This article is currently being updated following review.

The GB transmission system is a comparatively islanded system with a high credible loss of generation due to large individual nuclear generators. Furthermore, with plans to meet the greater part of the UK’s 2020 targets with large offshore wind farms, it is unsurprising that the GB Transmission System Operator (TSO) has been at the forefront of investigations into the capability and impact of wind turbines on system frequency. The approach National Grid [78] has taken is in line with their general principle of treating all generators connecting to the grid equally. Hence, wind farms connecting to the transmission system must be technically capable of providing the same service as conventional generators. This technical capability is checked for compliance when the wind farm is commissioned, by a series of compliance tests.

4.3.1.1 Droop

The key frequency response related requirement currently mandated in GB Grid Code is the requirement to provide droop response and is shown in Figure 4.16. A wind farm must be capable of operating such that it can regulate up or down its output power in direct proportion to the magnitude of the deviation in system frequency from the nominal 50Hz target. This response should be directly proportional with only a limited dead-band permitted around the 50Hz nominal frequency. A droop of 3-5% should be attainable, which in turn relates back to the speed of a synchronous generator. A droop of X% implies that a hypothetical 100% load step on that generator would cause a change in

speed of X%. Hence a 3-5% droop implies a change in power of between 40-66% per Hertz deviation from the nominal frequency.

Figure 4.16: GB Requirement for Droop Control from National Grid [78]

Clearly, a wind farm cannot indefinitely increase its power output in line with a droop requirement unless it is operating at an output power lower than the available wind power. Additionally, it would be economically undesirable to operate wind farms at lower than their maximum output just to provide frequency response, when other power plants can provide this capacity. Therefore the requirement of Figure 4.16 is only relevant when a generator is selected for Frequency Sensitive Mode (FSM). When a generator, such as a wind farm, is not selected for FSM it can operate under the less stringent requirements for Limited Frequency Sensitive Mode (LFSM). Under LFSM, the wind farm is only required to regulate down its output in response to a frequency above 50.4Hz. It is thereby allowed to operate at the maximum available power unless there is a major system over-frequency event.

The split in requirements between FSM and LFSM highlights a key difference between the GB regulatory framework and the economic reality. Wind farms being built have to be technically capable of providing FSM operation and are tested for it; however, they typically price themselves out of providing this service and invariably operate under LFSM.

The technical requirement to provide droop response from a wind farm has to be enhanced to take into account the variable nature of the wind resource. In contrast to a conventional generator, which would operate at a fixed output under normal operation, a wind farm would operate according to the variable available wind power. Figure 4.17, from National Grid [78], shows the GB Grid Code requirement on wind farms providing frequency response, this requires that when they are selected for FSM, they reduce their output

below the variable available power (Pavail) to a lower fixed output, known as the Capped Committed Level (CCL), and regulate according to system frequency from that level. The generator must also then supply a discretely updated measure of the maximum available power, known as the Maximum Export Limit (MEL), which informs National Grid of the magnitude of the (varying) level of reserve held by the wind farm.

Figure 4.17 shows that with variable wind speed it is understood that the available power could drop sufficiently to compromise response. This is shown on the dark blue output between about 17 minutes and 24 minutes, where the output reverts to tracking the maximum available power. This highlights a distinct feature of the implementation of the GB droop response requirement; it is based on a variable reserve approach, but ideally targets a fixed output.

Figure 4.17: Implementation of Frequency Response with an Intermittent Resource taken from National Grid [78]

The Danish approach to providing frequency response capacity is the reverse of the GB case, the Danish system operates a fixed reserve, variable output requirement [88]. This is typically known as “Delta-control” and requires a generator to operate at a fixed margin or “Delta” below their maximum available power. The droop response then operates relative

to the varying output of the wind farm. This type of response is illustrated, compared to the GB approach, in the FSM period of Figure 4.18 (Pdelta).

4.3.1.2 Response Types

The droop requirement dictates the magnitude of the steady state change in power output that a wind farm should provide in response to a frequency deviation. However, following a major loss of generation the speed of response is also critical. As such the market, from which FSM services are procured, is divided into three different types of response. Of these three, “Primary” and “Secondary response” govern the increase in power output in response to a reduction in grid frequency and “High response” governs the reduction in power output in response to a rise in grid frequency.

Primary response is the fastest type of frequency response currently procured for the GB grid. The magnitude of response is measured 10 seconds after a frequency deviation and should be maintained for 30 seconds according to National Grid [78]. Although the measurement is made at 10 seconds it would usually be expected that a generator would start to provide additional power output within 2 seconds of the frequency deviation. The aim of primary response is to stabilise the frequency within operational limits.

Secondary response is slower response that is measured according to the minimum increase in power supplied between 30 seconds and 30 minutes after a frequency deviation. Its purpose is to start the process of restoring system frequency whilst allowing time for the TSO to modify generation profiles to make up for the generation shortfall. Both primary and secondary response would be expected to be supplied relative to a fixed output level.

High frequency response is the response to a system over-frequency event and is measured 10 seconds after the frequency event. In contrast to Primary and Secondary response, High frequency response has no time limit specified, however, it would usually only be required for a maximum of half an hour before National Grid’s Balancing Mechanism adjusted generation profiles to compensate for the imbalance. Also in contrast to the low frequency response capabilities, the High frequency response controller must be active at all times, albeit it would only respond when frequency is significantly above target when in LFSM. When operating in LFSM, the wind farm’s output would be variable, therefore, but if the frequency exceeds the limit (50.4Hz) and High response is required, the wind farm would regulate its output relative to its power output immediately prior to the frequency exceeding 50.4Hz. This control is known as Balance control and is

illustrated alongside the other types of control discussed here in Figure 4.18. It should be noted from this illustration that in the event that the available wind power falls, excess response may be provided by the wind farm, which would revert to tracking the (lower) available power.

In addition to the frequency response controllers, it is possible National Grid may constrain the output of a given wind farm to a maximum level. This is typically an expensive option for National Grid, and generates negative headlines such as The Telegraph’s [89] “Wind farm paid £1.2 million to produce no electricity”. This was due to the constraint payments made to Scottish wind farms for not producing power. Nevertheless, the control, known as “Absolute Limit” control is implemented in the frequency controller and shown in Figure 4.18.

Overall, methods of providing frequency response have been implemented by wind farm operators, which have been successfully tested against the compliance tests of GB Grid Code by Horne [90]. Different control methods that can be used to provide frequency response are discussed in section 4.3.2.

Figure 4.18: Frequency Response Types