Network integration of wind power - Wind Power Integration: Connection and System Operational Aspects - page 119

the loss of moderately sized infeeds, whereas in small island systems the frequency
spectrum is very active for such events. If large heavy steam turbine (or even gas
turbine plant) is replaced in operation by large quantities of WTGs in smaller
systems, then the frequency and rate of change of frequency become very active and
difficult to control within sensible or legislated parameters. The 'inertia constant'
( H ) of a system is the stored energy in MWs/MVA of plant, and has the dimension
of time (see Section 5.2.2.1). One useful way to picture the H constant on 50 Hz
systems is that if all sources of energy were removed and if it were possible to keep
all load connected, the system would come to rest from 50 Hz in 2H seconds. So if
the inertia constant were 5 MWs/MVA, then the system frequency would have
decreased to zero in 10 s. The introduction of HVDC links with other systems does
not add inertia, although it might add fast response. The performance of both load
and generation can be unpredictable with rates of change of frequency levels above
about 0.5 Hz/s, and it is for this reason that the System Operator in Ireland requires
that half of the instantaneous load level on the system is to be supplied by conven-
tional plant. There is still serious effort needed in understanding the management of
systems with reduced inertia.
Increasing the turbine output during times of system energy deficiency causes
the generation-load energy balance to be restored, preventing the system frequency
from falling to the point where there is automatic load disconnection. Grid codes
specify response, droop and dead-band characteristics. Typically load pick-up over
the pre-emergency condition is specified for 3 s and 10 s post-event. In some
places, e.g. those subject to the Gulf Co-operation Council rules, the specification
of primary response is the increase in output available within 5 s and sustained until
30 s. Droop is usually specified as the percentage change in frequency that will
cause a 100% change in output of a unit. The droop refers only to the control
system that issues the signal, and is no guarantee that the plant will respond
eventually. The actual response is the load lift measured in defined periods post-
event. It is usual to see a requirement that the level of droop is settable separately
above and below nominal frequency in the 'frequency governor' system. By setting
the droop to a very small percentage, the generator becomes very active for changes
in frequency, whilst by setting it to a high percentage it is very insensitive to
frequency deviation. Setting the droop as low as say 2% is inclined to promote
over-sensitivity so that plant is continually responding with large changes in output,
whereas setting it to say 8% would make it very insensitive, being slow to respond
and allowing large frequency deviation on the power system. When all generation
was of similar characteristics it was common practice to set all governing loops to
4% droop so that all frequency regulating plant responded equally in proportion to
its installed capacity. This may be less relevant in a modern setting where
embedded and renewable generating plant has very different fundamental proper-
ties to traditional generation. The dead-band is the normal operating range of
frequency movement for which no emergency response is expected. It is either
a requirement that, within the frequency governing system, this dead-band is
settable separately above and below nominal frequency, or the utility specifies the
setting. Practically speaking, manufacturers generally produce controllers which