The therefore expressed as (2) where is active

The control over frequency in an interconnected power system is usually
divided into a hierarchy of three subsequent control levels: primary control,
secondary control and tertiary control 4, 5. Primary control is taken care in
large by generator turbine governors and partly by frequency dependent loads.
The system natural frequency response 6 is the combined effect of  the above mentioned. The area frequency
response characteristic coefficient ?s
corresponding to this response is defined as

                                                                                              (1)

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where Rs is the turbine governor droop, in Hz per pu power, and Ds is the damping
characteristic of load in pu power per Hz. Following a step load change, there
will be a deviation in frequency which cannot be eliminated completely by the action of
primary control. Steady-state frequency deviation  is therefore expressed as

                                                                                                        (2)

where is active power mismatch
in pu power, and is system frequency deviation
in pu frequency. Secondary control is done by Automatic Generation
Control (AGC), which actuates the reference positions of valve in governor units
and restores the system frequency to nominal value. Tertiary control refers to
the dispatch of units subject to economical aspects, where the operating points
of selected (mostly the generators with low running cost) on-line units are
changed periodically (e.g., every 15 minutes in India) to realize the
feasibility of transactions in real-time markets. Secondary control plays an
important role in a balancing area’s active power and frequency control in real
time.

The measure of mismatch between generation
and demand within a balancing area is termed as Area Control Error (ACE), in MW. AGC follows necessary
action according to ACE. The standard
AGC control strategy in an interconnected system is originally developed by
Nathan Cohn known as tie-line bias control (TBC) 7, 8, which is based on
principle that all operating pool members must contribute their share to
frequency in addition to taking care of their own net interchange. In TBC, the
control error for each area is a linear combination of frequency and tie-line
error. So, ACE is given by :

                                                                                         (3)

where Ta is the tie-line’s actual power exchange , Ts is the tie-line’s scheduled power exchange,  f is
the actual system frequency, f0
is the nominal system frequency, and B is the frequency bias of a particular balancing
area in MW/0.1Hz, which is a negative value. The value of B is chosen to be 10B=?A
so as to match the balancing area’s frequency response coefficient ?A,
where ?A is Balancing Area
A’s frequency response coefficient. Also
as shown in 9 value of B should not
be less than 1% of the balancing area’s estimated yearly peak demand per 0.1Hz
change .

According to 7 TBC has three functions:
absorbing the changes in load locally, sharing frequency control along with
others, and coordinating with natural frequency response of each plant to
remote load changes. We illustrate these functions for a two-area system, i.e.,
areas A and B, in what follows. ACE
in each area are expressed