In the previous paragraphs, we obtained the solution of an optimal power flow which is the initial steady state that we disturb with an abrupt power loss. Here, we briefly describe the equations that govern the power system dynamics.
Synchronous generators
In Section 1.3, we showed that the power flow equations in lossless approximation and only taking into account active power flows read
Pie=X
j ∈V
bi jViVjsin¡θi− θj¢ , (4.2)
where we labelV is the set buses in the system and Piethe electric power injected in the grid at the generator #i to differentiate it from the mechanical power Pimtransmitted to the turbine. Here, bi j gives the imaginary part of the admittance of the power line connecting bus #i at
4.1. A dynamical model of the continental European transmission grid
voltage Vito bus #j at voltage VjandV is the set of the N buses in the system. Voltages are
assumed constant, Vi= Vi(0)and are equal to either 220 or 380 kV.
The kinetic energy of a generator depends on its moment of inertia Jiand its angular speed ωi, it is given by Ekin= 1 2Jiω 2 i. (4.3)
Conventional generators are designed to operate in a narrow range of frequencies around the nominal system frequency f0= 50 Hz, typically between 47.5 and 51.5 Hz in Europe. On the assumption thatωiremains close to its nominal valueω0= 2π f0, then its kinetic energy varies as
dEkin i
dt ≈ ω0Jiω = P˙ m
− Pe, (4.4)
By defining H as the time during which the rated power S of the generator provides a work equivalent to its kinetic energy, we get
Hi= Ekin i Pmax i ≈ Jiω20 2Pmax i . (4.5)
For a given technology #s, Hsis more or less independent of the size of the generator and is
known as the inertia constant. Table 4.2 summarizes the values of inertia constants we use in our grid model. From Eqs. (4.3) and (5.38), The inertia coefficient miof the generator depends
on its nominal power Pmax i and its inertia constant Hs(i )and is given by mi= 2Hs(i )Pmax i
±
ω0. (4.6)
Fig. 4.4 shows the inertia distribution over the continental European grid. We observe that the vast majority of the system inertia comes from thermal generators which are substituted by new RES as the energy transition unfolds. The distribution of inertia over the grid is not uniform, there is more inertia in the center of the grid.
When a generator is not rotating at its nominal frequency an asynchronous torque, mainly due to Eddy currents in the damper windings, appears which tend to restore its frequency. The corresponding “damping” power Pidis generally difficult to calculate, nevertheless it can be obtained under some assumptions, in particular that the damping power is solely produced by the damper windings [78]. Conventional generators have damper windings which have different tasks as: providing starting torque, suppressing hunting phenomenon, preventing distortion of the voltage wave shape and damping the oscillations [79]. Damping coefficients
diof conventational generators are obtained for each generator type from Eq. (5.24) and Table
4.3 in Ref. [78] and the damping power reads
Figure 4.4 –Inertia parameters of generators in our model of the syn- chronous grid of continental Europe. The disk size is proportional to miand the colors label hydro (blue), nuclear (orange), gas (magenta), coal (black) and other (green) power plants.
Hs[s] hydro 4 nuclear 6 lignite 6 hard coal 6 gas 6 other 3
Table 4.2 –Inertia constants for dif- ferent technologies of conventional gen- erators, they correspond to the maximal values found in Ref. [80].
Frequency dependent loads
In dynamical analyses, the assumption that the consumer buses consist of frequency depen- dent loads is frequently made [81, 82]. This means that the load Liat consumer bus #i differs
from its nominal value L(0)i when this bus is subject to a frequency deviationωigiven by Li= L(0)i + diωi≡ L(0)i + ∆Li, (4.8)
where di > 0 is the load frequency coefficient. The frequency dependence of loads was
experimentally investigated [83, 84]. The results are given in the form ∆Li
L(0)i = α ωi ω0
, (4.9)
with the frequency sensibilityα ∈ 0.8 − 2 [83, 84]. From Eqs.(4.8) and (4.9) the load frequency coefficient direads di= αL(0) i ω0 . (4.10)
4.2. Disturbance following an abrupt power loss
Structure preserving model
A dynamical power system model with frequency dependent loads is often called a structure
preserving model [81]. We briefly resume the characteristics of our structure preserving model.
We denoteVgen⊂ V the subset of buses corresponding to generator buses. Their dynamics is described by the swing equations [78, 81]
miω˙i+ diωi= Pi(0)− Pie, if i ∈ Vgen, (4.11) where Pi(0)≡ Pimis the power input, miis the inertia and dithe damping coefficients of the
generator at the bus #i . The complement subsetVload= V \ Vgencontains inertialess generator or consumer buses with frequency dependent loads [81] and their dynamics determined by
diωi= Pi(0)− Pie, if i ∈ Vload, (4.12) where Pi(0)≡ −L(0)i is the load prior to the disturbance. We consider that Eqs. (4.11) and (4.12) are written in a rotating frame with the rated frequency ofω0= 2π f0with f0= 50 or 60 Hz, in which caseP
i ∈V Pi(0)= 0.
In this work, the primary control of frequency is modeled by a damping term in the swing equations describing the dynamics of generators. This is a relatively strong approximation, it corresponds to assuming an instantaneous response of the control. In reality, generators have deadbands in which the no frequency regulation is performed and governors regulate the response of the generators as a negative feedback loop [85]. This leads to a time delay and a ramping of the response. This means that our model probably overestimates the effects of primary control.