RTE System Operation Fundamentals

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A.1.1 Flow control
A.1.2 Frequency control
A.1.2.1 Maintaining the generation-load balance
A.1.2.2 Real-time automatic controls
A.1.2.3 Real-time manual adjustments
A.1.3 Voltage control
A.1.3.1 Why control the voltage?
A.1.3.2 Voltage and reactive power: an inseparable tandem
A.1.3.3 Reactive power compensation
A.1.3.4 EHV network voltage control
A.1.3.5 The problem of voltage collapse
A.1.4 N-k rule
A.1.5 Operating margins and balancing mechanism
A.1.5.1 Reserves and operating margins
A.1.5.2 Balancing mechanism
A.1.6 Protection plans
A.1.6.1 Necessity of protection plans
A.1.6.2 Protection of transmission system links
against insulation faults
A.1.6.3 Protection of transformation banks
A.1.6.4 Protection of transmission system substation busbars
A1 Annex 1
The basic notions about
System operation
A1 Annex 1
The basic notions about
System operation
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When a line sustains an outage,
the flow conveyed through it is transferred
to the neighbouring facilities still in service.
RTE - Fallen 225 kV line at the Lautaret pass

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Annex 1 -The basic notions
about System operation
A A.1.1 Flow control
In an interconnected, essentially meshed network, the distribution of energy
flows mainly depends on:
- the location of loads,
- the location of generation sets in operation,
- the cross-border exchanges,
- the location of means of reactive energy compensation,
- the impedances of transmission facilities.
These energy transits constitute a flow going from the substations where the
power plants are connected to the substations where customers are connected;
it is conveyed through the transmission lines and cables and divided up
proportionally to the admittance, i.e. the impedance reciprocal (which is in
some way a marked preference for the "shortest route"). This energy flow is
materialised by the current conveyed through the facilities. The higher the
energy flow is, the greater the current intensities will be.These intensities may
increase, in particular when a facility has tripped following a fault occurrence.
The flow initially borne by this facility will be transferred to the neighbouring
facilities: this is the load transfer phenomenon.
At all times, the System operator must ensure that the flow current in the
transmission facilities (overhead and underground connections, transformers
and autotransformers) stays within a set threshold: maximum admissible
intensity under steady-state operating conditions for lines and cables, rated
current for transforming equipment.
If the limits are exceeded, overload protective devices alert the dispatcher who
then has a limited time, which varies according to the extent of the overrun (20
min, 10 min or 1 min for 400 kV links), to bring the flow back to an acceptable
value. Otherwise, the overload protection causes the facility to trip at the end of
the time delay.
Flows are controlled by mainly acting on two parameters:
- network topology: by adapting the operating schemes, the dispatcher
modifies the impedances of the different network meshes (creating long lines
to increase the network impedance or, on the contrary, placing facilities in
parallel to lower it) and acts on the distribution of loads depending on the
generation sources;

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The control tools of dispatching centres
are used to monitor the flows in situation N …
… and detect the occurrence
of any constraints in N-k.

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A A.1.1 Flow control
- generation programmes: by adapting generation unit production schedules,
the dispatcher acts on the output of the generation sources depending on the
load requirements.
The last resort in an ultimate situation is to act on the loads by proceeding with
customer load shedding.
For a given topology and thanks to control and simulation tools, the flows in
each of the facilities can be evaluated according to the generation plan adopted
and the load location. It is possible, in the same way, to calculate the impact of
the outage of a transmission and generation facility on the value of the flows in
the remaining facilities.
Determining the impact of the tripping of a facility on the remaining facilities
calls upon the notion of transfer coefficient:
• for lines and cables, the transfer coefficient of a facility A to a facility B gives
the proportion of the flow of facility A to be transferred to facility B, in the
event of the outage of A;
• for generation facilities, the transfer coefficient of a generation set to a
transmission facility gives the proportion of the generation set power
variation that will be transferred, if need be, to the transmission facility.
These calculations are used on a permanent basis, both at the forecast level
and real-time level, to check the viability and soundness of the operating
schemes, notably as regards compliance with the N-k rule.
In real time, they are performed on a cyclical basis by the control tool or at the
request of the dispatcher to detect the appearance of any constraints in N-1 or
N-2 with the secondary analytical function available in control tools.

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A A.1.2 Frequency control
A.1.2.1 MAINTAINING THE GENERATION-LOAD BALANCE
Frequency: a common magnitude
The European power network is an interconnected system consisting of
generating facilities (power plants), transmission facilities (lines, substations)
and loads. Under normal operating conditions, one can consider that the
frequency is uniform at a given time on the overall grid (generators, being
interconnected by the play of electromagnetic force, all rotate at the same
electric speed).
Frequency: a magnitude to be monitored
Maintaining a frequency close to its rated value is necessary for the proper
operation of electrical equipment optimised for this value; the frequency must
remain within the range 50 Hz ± 0.5 Hz.
In addition, overly large frequency deviations are unacceptable for some
equipment, including generation units, which trip due to frequency deviations
from 2 to 4 Hz.
Small frequency deviations around the reference value, representative of the
normal operation of a system, are offset by the inertia of the rotating masses of
generation sets connected to the grid.
Frequency control: action on generation
In the face of normal load trends and the various contingencies encountered in
operation (generation set outages or load losses, etc.), maintaining the supply-
demand balance and a satisfactory frequency value means having to constantly
adapt the level of generation to that of demand. Three action levels co-exist:
primary control, secondary load-frequency control, tertiary control.
A.1.2.2 REAL-TIME AUTOMATIC CONTROLS
A.1.2.2.1 Primary frequency control
Primary control is carried out by control loops ("speed controllers") situated on
the generation sets.
Rapid (in a matter of seconds) and decentralised adjustment makes it possible
to restore the generation-load balance after a disturbance, provided that the
available primary frequency reserve is sufficient.

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For Europe, UCTE recommends Kj ~ 20,000 MW/Hz, more than a quarter
of which for France and the Iberian Peninsula.
The result of the outage of a 1,300 MW generation set in France (size of
the largest units):
• if France were alone in a separate network (disconnected from the
rest of Europe) with K = 5,000 MW/Hz, the frequency drop would be
260 mHz and the contribution of each set to primary control should
be 13% of its rated power output (i.e. beyond the design capacities of
the primary frequency control of most generating facilities);
• if France is interconnected with the rest of Europe (normal situation)
with K = 20,000 MW/Hz, the frequency drop is 65 mHz and each
regulating set takes part to the extent of 3.2% of its rated power
output.
The interconnection enables all the partners to pool their
contribution to the primary frequency control and each one to
reduce the sizing of his primary reserve both at the level of design
measures of new generation sets and in operation.
Some figures
Pn : Generation set rated power output (MW)
K : Generation set primary power frequency characteristic (MW/Hz)
Pn 1
= . : regulation droop
f0 K
1
k = : static gain
For a 900 MW unit:
K = 450 MW/Hz
= 0,04
k = 25
Some definitions

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For a given generation unit
The speed controller acts on the turbine motor fluid inlet valve and seeks to
impose at equilibrium a linear relation between the speed (direct frequency
image) and power.While taking into account the equipment-related limitations,
the static characteristic of this adjustment is shown in the figure below.
This linear relationship is expressed in the following form:
For all the network generation sets
Compensating for a sudden variation of balance Pbil requires an action divided
up among all the sets so as to obtain the following at the end of the control
action:
Kj : Primary power frequency characteristic of the synchronous interconnected
network.
f1 : Frequency reached at the end of the control action. Primary control restores
the supply-demand balance if the primary reserve is sufficient, but the final
frequency differs from the reference frequency.
Pbil = Kj (f1 - f0)
P - P0 = K (f - f0)
Pmax : Maximum design power
Pᐉ : Power displayed at limiter
(maximum power allowed
at the time considered)
Pc : Displayed power set point
f0 : Reference frequency
(50 Hz)
Limiter
Primary
reserve
Set point

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Pmax
available
P limiter
P effective
P set point
P limiter
P effective
P set point
Pmax
available
Example : two limiter settings
Generation set with primary reserve
Generation set without primary reserve
Example: two limiter settings

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Pbil = Σ Pj of the generation sets.The available primary reserve is the sum of
the primary reserves of the contributing sets. At the European level, the rule is
that this reserve must represent at least 3,000 MW corresponding to the
simultaneous outage of the two largest existing generation sets (French N4
units). Each contributing unit will have performed a power variation:
Pj = - Kj Pnj (f1 - f0) / f0
Kj = 0 for a generation set beyond set point value or reaching the limiter. It is
therefore important that a set in primary control does not have its contribution
reduced by an inappropriate use of the limiter which would drastically reduce
the reserve expected by the System operator. It will be noted that the higher the
network primary power frequency characteristic ( Kj) is, the lower the
frequency deviations are.
A.1.2.2.2 Secondary load-frequency control
The quick adaptation of generation to load carried out by primary control leaves
a frequency deviation at the end of the action. It also brings about flow
variations between the countries: all the generation sets of the various countries
react to the variation of the common frequency, even if the disturbance has
occurred in another country of the synchronous interconnected system.
• Aim of secondary control
Let f be the residual frequency deviation and Pi the deviation between the
balance of power observed on the transmission tie-lines of a given country
(France, for example) and balance Pi0 of the scheduled exchanges to be
respected ( Pi > 0: export too high).
For an incident located in France, representing a loss of output Pi, the reaction
of all the interconnected generation sets is expressed by:
Pi + K f = P
Pi = exchange deviation (represents the help provided by foreign partners)
K f = action of French primary control
Dividing by K produces a homogeneous deviation at a frequency:
E = f + Pi / K
PRIMARY CONTROL RESTORESTHE SUPPLY-DEMAND BALANCE,
BUT THE FINAL FREQUENCY DIFFERS FROMTHE REFERENCE FREQUENCY.

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The aim of secondary load-frequency control:
- bring the frequency back to its reference value,
- bring the exchanges between partners back
to their scheduled values.

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The load-frequency controller of the secondary control area uses a parameter l,
so that:
(without going into details, the French secondary control includes the Iberian
Peninsula, which leads to choosing λ = KFrance + Iberian Peninsula, if one complies
with Darrieus’ Law explained further on).
Secondary control principle
A centralised mechanism, located at the National Dispatching Centre, has the
task of automatically modifying the generation programme of the generation
sets in order to cancel the power deviation Pi + λ f.
To do so, it uses the remote measurements of frequency and flows on the
interconnection lines as a basis to elaborate a signal N(t) called secondary load-
frequency control level, comprised between -1 and +1, and send it to the
generation sets contributing to the secondary control in order to change their
power set point values.
Expression of level N(t):
Some parameters are available to the national dispatcher:
α : integral gain (or slope) of control (MW/r),
Pr : control half-range (MW),
λ : constant (MW/Hz) set on the controller of the secondary control area,
β : proportional gain.
The secondary control will then take place with a double objective:
• bring the frequency back to its reference value f = f0
and
• bring the exchanges between partners back to their scheduled values.
E = f + Pi / λ

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FRANCE (+ IBERIAN PENINSULA)
Primary control: P 325 MW
Secondary control:
E = Pi + (KFrance + Iberian Peninsula) x f
= - 975 + 5,000 x (- 0.065)
= - 1,300 MW
REST OF EUROPE
Primary control: P 975 MW
Secondary control:
E = Pi + KEurope* x f
= + 975 + 15,000 x (- 0.065)
= 0 MW
A generation set has tripped in France.
Only French secondary control must compensate.
(KEurope* = KEurope - KFrance + Iberian Peninsula)
N = constantN
Secondary control action in Europe
when a 1,300 MW generation set
trips in France

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Choice of secondary control parameters
• Choice of parameters α and λ
Let us take the simple example of two interconnected countries, A and B. PA
and PB designate their generation, CA and CB their internal load, KA and KB their
primary power frequency characteristics, λA and λB their constants (MW/Hz) set
on the controllers of the secondary control areas, Pi0 the power flowing from A
to B (programme).
Subsequent to a disturbance in A (for example, a load variation CA), while
assuming that the secondary control action is slow compared with that of
primary control, which can be checked by selecting a sufficiently high integrator
time constant (about 100 s), it can be considered that primary control
establishes a first balance.
Hence the following may be set out:
PA = CA + Pi = KA f and PB = Pi = - KB f.
The terms to be integrated are as follows:
and
If one chooses λA = KA and λB = KB, one obtains EB = 0. Only the level of
country A will therefore vary to restore f = f0 and Pi = 0.
DARRIEUS’ LAW
If, for each of the partners, the parameter λ is chosen equal to the primary
power frequency characteristic K, then only the secondary control of the
network creating the disturbance remedies the disturbance.
f)
K
(1)
P
fE
A
A
A
A
i
λ
+=
λ
+= (
f)
K
(1)
P
fE
B
B
B
B
i
λ
−=
λ
−= (

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Level
Secondary reserve
exhausted
N
t
t
+1
-1
0
0
Pr
Pc0
Pc
Pc0
: power set point for N = 0
Pr : contribution
Pr
Pc0
+ Pr
Pc0
- Pr
When each generation set fulfils
the contribution required by secondary control,
this helps ensure the quality of frequency
and compliance with the exchange programme.
Trend of the power set point
of a generation set in secondary control

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• Contribution of generation sets to secondary load-frequency control
RTE informs each of the producers of its contribution in MW to secondary load-
frequency control.
The producers select the generation sets taking part in the secondary control
according to their dynamic capacities to adjust their output and according to their
cost. Setting up a control range may mean having to start up additional sets.
For each generation set taking part in secondary control, the power set point
Pc = Pc0 + N pr varies between Pc0 - pr and Pc0 + pr (Pc0 set point at 50 Hz and pr
contribution of the generation set).
The relation pr = Pr helps ensure that the whole control range is used for N = ± 1.
• Possible contribution values
- Nuclear units: pr = 5% Pn, i.e. 50 MW for a 900 MW PWR
- Conventional thermal units at rated power: pr = 10% Pn
- Hydro generation sets: variable, pr may reach or even exceed 25% Pn
However, these contributions can be reduced for some sets, either temporarily or
permanently.
• Power variation slope
All generation sets are not capable of frequently bearing fast variations of their
generation. In normal operating conditions, the slope of the level is limited to
about 0.15/min (7 MW/min for a 900 MW PWR), i.e. crossing the secondary
control range takes 13 minutes. Upon an incident ( E > predefined threshold),
the central regulator switches over to fast slope: 0.9/min, i.e. crossing of the
secondary control range in 2 minutes.

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P effective
Instantaneous
primary reserve
Primary control
characteristic
(slope: -k)
P set
F
P
P = Pc + k f
Pc = Pco + pr
Pco
Pco - pr
f
f 50 Hz
N
= 0
N
= +1
N
= -1
P effective
Instantaneous
primary reserve
F
P
Pco + pr
P = Pc - Pco + Npr
Pco - pr
Pco
50 Hz
N
= +1
N
= -1
P set
Two situations possible …
at the end of a primary and secondary control action,
upon a disturbance
Utilisation of the whole secondary control reserve: Pc = Pc0 + pr; N = 1
(limit stop level).The deviations are not completely corrected.
Utilisation of only a part of the secondary control reserve: Pc = Pc0 + N pr
The deviations are corrected: f = 50 Hz, Pi = Pi0
The straight line (N = 1, N = 0, etc.) characterises the generation set
controller.The secondary control level shifts the line in parallel to
itself.
Legend:
Pᐉ : power output at limiter
Pc0 : set point at 50 Hz and N = 0
Pc : set point at 50 Hz
pr : secondary control half range for a generation set
Pn : rated power output
N : level
P : effective active power output
f : frequency deviation
Pi : power exchanged with neighbouring countries

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A.1.2.3 REAL-TIME MANUAL ADJUSTMENTS
Tertiary control
The previous example shows the action of secondary control, following a
disturbance, may not fully absorb the deviations on frequency and power flow on
the interconnections, the level reaching its limit stop (N = ± 1).The primary reserve
then starts and the secondary control reserve is used up.The arrival at the high or
low level limit stop can also be the result of a slow drift between load and the
generation set accepted schedules (image of load forecast).The depleted reserves
have to be reconstituted to provide protection against any new contingency.
In anticipation of circumstances of this type, daily contracting a day ahead (D-1)
provides for a power reservation which consists of several products according to
its mobilisation time and possible utilisation duration: rapid tertiary reserve
15 minutes, additional tertiary reserve 30 minutes, due reserve at term, etc.This
power is brought on line, according to real-time requirements and the deadlines,
by calling upon the balancing mechanism (cf. § 1.5 of this annex), in order to
readjust the generation schedules to the actual supply situation and reconstitute
the primary and secondary reserves (f = 50 Hz, N = 0).The rapidly mobilised power
reserve is set up with generation sets which are not at maximum power or which
can start up quickly (hydro generation sets, combustion turbines). It should be
noted that a downward reserve is also provided for, always on a contracting basis.
The aim of tertiary control, co-ordinated by the national dispatching centre, is to
mobilise the tertiary reserve throughout the day, as much as needed, while
endeavouring to reconstitute or adjust it according to System trends. Using the
balancing mechanism as a basis, it calls upon upward offers by ascending price
order in case of insufficient output. Otherwise (surplus generation), downward
offers by descending price order are called upon.

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Voltage control
is necessary in order to …
→→ Operate the network while ensuring reliability
→→ Maintain the supply voltage of customers
within the contractual ranges
→→ Comply with the operating constraints
of the equipment
→→ Minimise losses
→→ Use the capacity of transmission
facilities in the best way possible

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A A.1.3Voltage control
A.1.3.1 WHY CONTROL THE VOLTAGE?
Satisfy the customers, distributors and producers
Voltage is, along with frequency, one of the main parameters of System
reliability. This parameter is common to all the users: customers, distributors
and producers, connected to the same electric node.
For customers and distributors, each supply contract defines the declared
supply voltage and the accepted variation range around this value.These two
terms, which condition the sizing of customers’ receiving equipment, must be
respected at all times.
For the producer, the voltage must also be kept within an agreed range that can
be supported by the generation facilities, otherwise the generation sets may
have to be disconnected, which weakens the reliability of the power System.
Satisfy the needs of the System
Controlling the voltage is also necessary to ensure proper, overall System
operation, both from the economic and reliability standpoints. At the same time,
appropriate control helps reduce network losses, use available transmission
capacities in the best way possible and avoid the risk of voltage collapse, such as
those experienced by Belgium in 1982, and theWest of France and Japan in 1987.
Respect equipment operating constraints
Finally, the voltage must be maintained throughout the HV grid, in a narrow
range compatible with the sizing of the equipment:
- voltages that are too high lead to the ageing or destruction of connected
equipment;
- voltages that are too low lead to overloads on the lines, disturb the smooth
operation of some protections and transformer on-load tap changers, affect
the behaviour of the auxiliaries of generation units and, more generally
speaking, of the processes of public transmission system users.

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Some magnitude examples
An EHV line can be shown by the following
equivalent diagram:
R: resistance of conductors
X: line inductance
C: line homopolar capacity
For a 400 kV line:
R 3 / 100 km
X 30 / 100 km
C 1,2 ␮F / 100 km
i.e. about 60 MVAR effective
per 100 km of no-load line
(Cω/2 . UA
2
+ Cω/2 . UB
2
)

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Voltage: a fluctuating magnitude
However, voltage fluctuates by nature. It is first affected by slow and general
variations brought about by seasonal, weekly and daily load trend cycles (without
RTE preventive action, the voltage would be rather low at peak load periods and
high at off-peak load periods); it is also subject to rapid variations due to multiple
contingencies: random load fluctuations, network topology changes, tripping of
transmission facilities or generation sets.
To keep the voltage within the desired range throughout the (E)HV network, it is
therefore necessary to have adapted and perfectly coordinated means of control.
A.1.3.2 VOLTAGE AND REACTIVE POWER: AN INSEPARABLE TANDEM
The voltage at a network point depends on the electromotive force of the
generators connected to it, as well as on the voltage drops in the various
components of the grid: rotating machines, transformers, lines, etc.
Voltage drops
If the very simple case of a load supplied by a constant voltage source through a
line (cf. diagram below) is examined,
one can roughly write that the voltage drop in the line ( V = V1 - V2), caused by
the active and reactive power flows (P and Q) induced by the load, is equal to:
V= (R P + X Q) / V2

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RTE - 400 kV lines
Beyond a certain distance,
the reactive power supplied by the generators
cannot reach the place where it is needed.
Reactive power does not travel very well.

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For an EHV line, X 10 R:
It is the reactive power circulation which generally creates preponderant
voltage drops. Voltage and reactive power are therefore strongly linked
magnitudes.
So reactive power does not travel very well because it creates voltage drops.
This means that beyond a certain distance, the reactive power supplied by the
generators or capacitors cannot reach the place where it is needed.
Maximum transmissible power
Furthermore, if a purely active variable load (Zch = Rch) is considered and one
examines the trend of the voltage at its terminals depending on the active
power transmitted to it through the line, it can be seen that, when the load
increases (i.e. when Rch decreases), the power transmitted to the load begins
by increasing, then goes to a maximum, before decreasing (cf. curve below):
There is a critical point (corresponding to the critical voltage Uc and the
maximum transmissible power Pmax), beyond which it becomes impossible to
have more power transmitted to the load.
Here we find a well-known property:
There is a maximum value of active power transmissible to a load through a
line, from a constant voltage source.
V X Q / V2

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Maximum power
transmissible to a load
The maximum power transmissible to a load from a maintained
voltage source is equal to:
It reaches its maximum value for ϕ = 0 and ß = 90° (Z = X)
and is then expressed as:
The transmissible power between two points with "maintained
voltage" connected by a reactor is equal to:
Its maximum value is reached for θ = 90° and is expressed as:
One sees that, if one can manage to keep the voltage constant at
the load terminals, the maximum transmissible power is twice as
high when the voltage is kept constant solely at the generator
terminals. Hence the interest of having many voltage-maintained
points.
=
X2
UU
P 21
max
))+
.=
-(ﬂcos(12
cos
Z
U
P
2
1
max
X2
U
P
2
1max =
θ.= sin
X2
UU
P 21
max
θ = transmission angle
U1 sin (ωt + θ) U2 sin ωt

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For any load Zch, this maximum power corresponds to a load impedance value
such that: Zch / Z = 1 and is expressed as follows:
where:
U1 is the maintained voltage at a network point,
Z is the line impedance between the maintained voltage point and the load,
ϕ is the phase shift initiated by the load
(tg ϕ = 0 when the load is compensated exactly),
ß is the phase shift initiated by the line.
This expression of Pmax shows, among others, that:
- the higher the operating voltage (U1), the higher the maximum transmissible
power. Hence the interest of operating with the highest possible voltage
map;
- the lower the network impedance (Z), the higher the maximum transmissible
power. Hence the interest of having a network that is sufficiently sized and of
operating the maximum number of lines available;
- the more ϕ decreases, i.e. the more the reactive compensation of the load
increases (thanks to the adding of capacitors), the more the transmissible
power grows. Hence the interest of compensating at a maximum (or even
overcompensating) as near as possible to the loads the reactive power they
consume.
A.1.3.3 REACTIVE POWER COMPENSATION
Controlling the voltage therefore assumes, first of all, controlling the reactive
power flows which are due to two causes:
- load consumption: it is characterised by the tangent ϕ of receptors, highly
variable according to the type of load, which itself differs depending on the
type of day (working or not) and the time (tangent ϕ lower in off-peak periods
than in peak load periods);
- network components (transformers, lines and cables): the lines can supply or
absorb reactive power, depending on whether the conveyed power is lower
or higher than its characteristic value.
))+
.=
-(ßcos(12
cos
Z
U
P
2
1
max

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Voltage stability is degraded
when the operating voltage decreases
or when the loads are insufficiently compensated.
For a given tg ϕ,
the maximum transmissible power rises with the source voltage.
For a given source voltage level,
the maximum transmissible power increases with the load compensation.

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How to carry out efficient compensation of reactive power to control these flows?
On distribution networks
As reactive power does not travel well, reactive problems must be dealt with
locally as much as possible if they are to be settled. The interfaces between
transmission and distribution therefore cannot be disregarded with respect to
this issue.
The best compensation is obviously that which is performed at the level of the
utilisation equipment itself by encouraging the customer to install capacitors
and doing so by offering an appropriate tariff. However, it is not always
sufficient and must consequently be supplemented by compensation carried
out directly on the distribution networks. It is performed by means of capacitors
installed on the MV networks and controlled, for the most part, automatically
by varmeter relays.To obtain "proper compensation", it is absolutely necessary
to have a sufficient number of capacitors, installed where needed and efficiently
controlled by varmeter relays that are available and appropriately adjusted.
Otherwise, this will result in voltage withstand problems on the distribution
network which will have detrimental effects on transmission network reliability.
On transmission networks
Reactive power compensation is also necessary at this level. Its purpose is to
supplement (if necessary) that of the distribution networks and carry out the
compensation of the transmission grid.
The generators connected to the transmission grid can supply or absorb
reactive power in a very simple way, by getting their excitation current to vary.
This is, of course, only possible within the reactive power reserve limits allowed
by their "operating diagram".
That is why generation facilities must be built so as to be able to have sufficient
reactive power reserves. These possibilities must also be effectively available
and the System operators must be aware of the actual reserves; otherwise,
network reliability is jeopardised, since the operators may rely on reserves that
actually do not exist.

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Controlling the voltage supposes the control
of the reactive power flows.
HV1 or MV capacitors provide
the reactive power.
Automatic on-load tap
changers seek to
maintain a constant
downstream voltage.
The nature of the loads plays
a role in this voltage situation.
The customer has obligations.
The subtransmission and
distribution networks and
transformers are rather
reactive power consumers.
- The reactors absorb reactive power.
- The capacitors supply reactive power.
- The synchronous condensers
make it possible to do both.
The generation sets supply or absorb
reactive power.The sets with the highest
capacity are connected to the 400 kV grid
and fix the global voltage framework.
The EHV network must
be sufficiently “strong”
to be able to convey
the reactive power.
The transmission networks,
depending on whether they are
loaded to a little or large extent,
are sometimes reactive power
consumers and sometimes
reactive power producers.
400 kV grid
225 kV
225 kV
HV
(63 kV
or 90 kV)
MV
LV
C

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197
The action of the generation sets may prove to be insufficient due to their
location on the network (reactive power does not travel very well!), their
unavailability or limited possibilities. Other means of compensation must
therefore be used: capacitors, reactors, or even synchronous condensers. Here,
too, it is primordial for reliability that these facilities be installed where they are
needed and that they be effectively available.
The pertinent use of these different means is necessary in view of the extremely
different characteristics of the generators and capacitors, as regards the
contribution to voltage and reactive power compensation control. The
generators provide a reactive power that can be brought on line
instantaneously and adjusted in an extremely fine way. As for the switching of
capacitor steps, this action requires a certain time and obeys the all or nothing
logic; in addition, the reactive power provided by a capacitor decreases when
its voltage drops. Capacitors are a useful means, but their reactive power is not
at all comparable to the "dynamic" reactive power of generation sets.
In practice, the mobilisation of static compensation equipment (capacitors,
reactors) is used first so as to preserve part of the reactive power of the
generators for fine and fast adjustments and in response to incidents.
A.1.3.4 EHV NETWORK VOLTAGE CONTROL
On the EHV network, voltage control under normal operating conditions is
obtained by a succession of three control levels with staggered time constants
making it possible to mobilise reactive power reserves in increasingly extended
areas.
On grids with a lower voltage level (90, 63 kV and MV), voltage control is
ensured by the automatic on-load tap changers installed on (E)HV/HV and
HV/MV transformers.

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Generator design limits:
the P-Q diagram at the stator terminals
The possible scope of generator operation has the following curve
for a given voltage at the stator terminals, expressed in the active
power/reactive power axes.
The limits of the domain correspond to various physical constraints:
limit of heating of stator end zones
(combination of stator and rotor flows),
stator intensity limit
(problem of heating of stator systems),
rotor current limit (problem of heating of magnetic systems
due to iron losses) (case of turbogenerators),
induction limit in the air gap (heating of magnetic system
metal plates due to iron losses) (case of turbogenerators).
Each stator voltage value corresponds to a different diagram.
1
2
4
3
P
Q
Prated
Qrated0
1
2
3
4
U stator = Us0

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Automatic primary voltage control
Generators are the only sources which make it possible to have constant
voltage points on the transmission system; to do so, they must be equipped
with a primary voltage controller. This automatic device controls local
magnitudes at set points (more often voltage, more exceptionally reactive
power), by acting on the generator excitation voltage.
This action is practically instantaneous and serves to cope with random load
fluctuations, topology changes and incidents, at least as long as the generator
has not reached its reactive power limits. It is thus the most valuable means of
voltage control.
Everything must be done so that the generation sets are equipped with well-
adjusted primary controllers and so that the reactive power possibilities of the
sets are effectively available and known to the System control operators.
Automatic secondary voltage control
When called upon, the primary controllers act instantaneously and
automatically find a new working point of the generator. If no action is carried
out on the set points of the controllers, some generators may needlessly
produce reactive power that will be consumed by others.
Furthermore, over and above the local action of the primary controllers and of
that of on-load tap changers, control of the voltage map requires more global
actions, at the regional level, to cope with variations in load and topology.
This coordination of actions is ensured automatically on the French EHV grid by
"Secondary voltage control"(1)
.
Its principle consists in organising the network in "control areas" and in
monitoring the voltage map separately within each area by acting in an
automatic and coordinated way on the reactive power of certain generators in
the area.
RST action consists in controlling the voltage of a particular point in the area,
the "pilot point", which is chosen so that its voltage is indeed representative of
that of the whole area.
So that this system is efficient, generation sets contributing to secondary
control capable of providing sufficient reactive power will be needed in the
area.
(1): French acronym "RST" for "Réglage Secondaire de Tension".

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Secondary voltage control setting mode
In each area, RST simultaneously ensures control of the voltage
map and distribution of reactive power between the generation
units contributing to secondary control.
The control scheme consists of a control loop situated at the
regional dispatching centre (zone controller) which makes it
possible to automatically change the set point of the primary
voltage controller of the generators contributing to control.
X
Transmission of pilot point voltage Vp
Vc : RST voltage set point (for pilot point)
Uex : generator excitation voltage
Vp : voltage measured at the pilot point
Us0
: primary voltage controller set point
Reactive power generated by set
Uex
Stator voltage Us
Set point Us0
Generation set i
Network
Set i + 1
Set i + 2
Pilot busbar
Set point
Vc
Area
controller
Regional
dispatching
centre
Level
N
Contribution
Qr
Reactive
loop
Primary
voltage
controller

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It must also be possible to find control areas that are sufficiently independent.
As the development of the power system has increased interactions between
areas, this has led to developing a new system, called "Coordinated secondary
voltage control"(1)
, used in theWest region, capable of taking into account these
interactions.
The proper contribution of RST and RSCT to System operating reliability of
course requires appropriate operator actions: maintaining the availability and
performance of controllers, making available reliable and effective
transmission links, complying with operating instructions. A sufficient number
of generation sets must also contribute to the primary and secondary control.
Tertiary voltage control
Tertiary voltage control is manual. It concerns all of the actions controlled by
the dispatching centre operators to co-ordinate the voltage map between the
different secondary control areas.
Transformer on-load tap changers
In order to maintain the voltage map on the 90 kV and 63 kV networks (and at
MV), the EHV/90-63 kV transformers and (E)HV/MV transformers are equipped
with automatic on-load tap changers. By modifying the transformation ratio
according to the voltage variations in primary control, the on-load tap changers
make it possible to maintain the voltage around the set point value in secondary
control.The tap-changes are carried out with an initial specified time (change of
first tap) of 30 seconds for transmission network transformers (1 minute for
(E)HV/MV transformers), then 10 seconds for the change of the following taps.
These devices are extremely useful in a normal situation, but may contribute to
voltage collapses in an incident situation (cf. next §).
(1): French acronym "RSCT" for "Réglage Secondaire Coordonné de Tension".

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Illustration of RST action
Let us consider in the simplified network that generation unit G2, in
the process of supplying its maximum reactive power, trips at t = t0.
Evolution of the voltage trend if RST is not operational:
Evolution of the voltage trend if RST is operational:
EHV network (400 kV, 225 kV)
HV network
Loads depending on voltage
of the type pure resistor
(heating) and pure inductance
p = p0 . (V/V0)2
q = q0 . (V/V0)2
RST pilot point
Transformer with
automatic on-load
tap changer
G1
G2
VG VP
VC

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A.1.3.5 THE PROBLEM OF VOLTAGE COLLAPSE
The margin which, at all times, separates System operation from voltage
collapse depends to a great extent on the network operating conditions: voltage
value, selection of the taps of 400/225 kV auto-transformers and generation set
main transformers, load trend, topology, points where the voltage can be
maintained by generators, line tripping, etc. It can be reduced suddenly when
contingencies occur, such as generation set outages or when the sets reach
their reactive power limits.
The automatic on-load tap changers of transformers may favour voltage
collapses if care is not taken. Indeed, when they detect a low voltage on the
loads side, they cause tap changes until the desired voltage set point is
obtained. This leads to raising the current in EHV lines and increasing the
voltage drops, while getting the System operation point increasingly closer to
the critical point characterising voltage collapse. In this case, in France,
automatic devices are used to block the on-load tap changers on the current
tap, or even return to a higher tap. The blocking criterion is overstepping a
minimum voltage threshold on an electric node representative of each network
area.

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The N-k rule defines
the maximum accepted risk level.
Zone1
Zoneofout-of-normevents
TheN-kruledefinesthemaximumacceptedrisklevel
Extentof
potential
powercut
(MW)
Unacceptable
consequences
limit
(600MW
fora“single”
eventatEHV)
Non-dimensioningevents
(outageofanuclearsite,
outageofa400kVsubstation)
Lowprobability
Dimensioningevents
Auto-transformer
outage
Line
outage
Generationset
outage
Probability
400kVbusbar
outage
Zone3
Unacceptableriskszone:
tokeepoutofthisarea,preventivemeasuresaretaken,
ifnecessary,eveniftheyarecostly.
Isoriskcurve
(correspondingtothemaximumacceptedrisk)
Zone4
Acceptableriskszone:
theimplementationofpreventivemeasures
mustbetheresultofatechnicalandeconomicanalysis.
Zone2
Unacceptableconsequenceszone:
tokeepoutofthisarea,preventivemeasuresaretaken,
ifnecessary,eveniftheyarecostly.

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A A.1.4 N-k rule
At all times, the System operator must do what is necessary to ensure that the
System remains viable following a hypothetical contingency on the nominal
situation leading to the outage(1)
of k facilities (cf. § 2.3). As concerns this type of
contingency, he can nevertheless tolerate some risk according to a cost-
reliability choice.
This reference value divides the "consequences - probability" plan into four
distinct domains:
- the acceptable risks zone (zone 4),
- the unacceptable risks zone (zone 3),
- the unacceptable consequences zone (zone 2),
- the risks zone for which the System operator accepts to call upon the defence
plan (zone 1).
If the potential consequences of a contingency are unacceptable (zone 2) or the
risk run is greater than the maximum tolerated risk (zone 3), the System
operator must bring the forecast power cut back to the tolerated levels or, if this
is not possible, minimise it, in operational planning and in real-time operation.
To do so, he may implement means inducing additional operating costs. When
several solutions are possible, he must endeavour to minimise the
consequences of the feared events.
The N-k rule defines the maximum tolerated risk level, assessed by a
reference value of the product "Event probability x Extent of power cut":
the greater the probability of an event occurrence, the lower the accepted
power cut (in MW).
(1):This concerns the outage of facilities; the facilities shut down for maintenance
or repair purposes are already declared to be out of order in the nominal state of
the network.

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SNET - Provence power plant
The outage of a generation unit must not have
an impact on customer power supply.

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A A.1.4 N-k rule
The table below shows the typical events to be taken into account and, for each
one of them, specifies the tolerated consequences and risks.
Events to be taken Acceptable Customer Maximum extent
into account power cut load shedding of power cut
or load shedding
Outage of a generation set NO NO 0
Outage of a 400 kV line
or 400/225 kV auto-transformer
NO NO 0
Outage of a
225 to 45 kV line
NO (1)
/ YES YES 100 MW
Outage of a 400 or 225 kV
primary transformer NO (1)
/ YES YES 100 MW
supplying a 225 to 45 kV grid
Outage of a busbar section YES YES
600 MW at 400 and 225 kV
200 MW at 150 to 45 kV
Simultaneous outage of two
400 or 225 kV generation sets NO YES
600 MW
due to a common mode
(load shedding)
400 or 225 kV generation sets YES YES 600 MW
with t < 8 h (2)
400 or 225 kV generation sets NO NO 0
with t > 8 h (2)
Outage of a double
NO YES
1,500 MW
400 kV line (load shedding)
(1): Unacceptable power cut when the structure is guaranteed and the network is
complete
(2): t = time separating the successive tripping of 2 generation sets

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EDF - Saint-Laurent-des-Eaux nuclear power plant
Active power reserves must be predisposed
to ensure the supply-demand balance
and settle congestions on the public
transmission system.

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209
A A.1.5 Operating margins
and balancing mechanism
A.1.5.1 RESERVES AND OPERATING MARGINS
A.1.5.1.1 Reserve requirements
In keeping with the role entrusted to it byArticle 15 ofAct n°2000-108, RTE ensures
the balance of flows between supply and demand on the overall French power
systemandsettlesanycongestionontheFrenchpublictransmissionsystem,over
a period ranging from day-ahead planning (D-1) up to real-time operation (D).
Each producer manages the mobilisation of the means needed to meet the
demand of its customers and certain contingencies. RTE draws up its global load
forecast for France and calculates the values of the reserves required to cover the
different types of contingencies.
The primary, secondary and tertiary controls in real time serve to manage the
supply-demand balance, by using reserves set aside for this purpose. RTE
evaluates the reserves that are effectively available. If they are insufficient, RTE
performs adjustments on the generation facilities.
A.1.5.1.2 Supply-demand balance contingencies
• Load contingencies
The meteorological contingency (temperature, cloudiness) has a great
influence on load: thus, in autumn, winter and spring, a temperature deviation
of one degree results in a load variation that may reach 1,600 MW. Likewise in
summer, when the temperature is higher than 25°C, one degree more
generates an extra load of up to 600 MW due to the operation of various
cooling equipment (this phenomenon increases every year with the level of
installation of ventilation or air conditioning systems).
Another disturbance affecting load is related to the start or disconnection of
loads at the beginning and end of tariff periods (off-peak hours, peak day
withdrawal, etc.).
• Generation contingencies
Generation facilities, like all System components, are affected, as regards
their operation, by a number of fortuitous events and/or limitations giving
rise, in real time, to the unscheduled unavailability of a certain volume of
generation.

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Since 1 June 1998,
the value recommended by UCTE
has been determined on the basis of the curve below:
This curve, with the shape:
Pr = a Lmax + b2
- b
is established empirically with:
a = 10 and b = 150
Pr = Recommended secondary control half-range in MW
Lmax = Maximum forecast load of the control area in MW
for the period considered
0
0
5000
10000
15000
20000
25000
30000
35000
40000
45000
50000
55000
60000
65000
70000
75000
80000
85000
90000
900
800
700
600
500
400
300
200
100
Lmax in MW
Recommended
secondary reserve
in MW

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• International exchange variations
The noteworthy increase of exchanges is accompanied by a concentration at
certain times of modifications in scheduled energy interchange between
control blocks, with changes that often reach several thousand MW between
France and the other countries. Secondary load-frequency control is used to a
considerable extent in these transitional phases.
A.1.5.1.3 Definition and sizing of reserves and margins
Primary reserve
In an interconnected network, the primary reserve is the sum of the primary
reserves of the generation sets in primary control. The primary reserve of a
generation set is the power margin allocated to the primary frequency control
(cf. annexA.1.2).
The UCTE rule recommends a permanent primary reserve of 700 MW for France
(+ 150 MW if reference frequency at 49.99 Hz / - 150 MW if reference frequency at
50.01 Hz).
Secondary reserve
For oneTSO or severalTSOs belonging to the same control block, the secondary
reserve is the sum of the secondary reserves of the generation sets subject to
secondary load-frequency control(1)
.
The instantaneous secondary reserve of a generation set corresponds to the
upward or downward power still available under the action of secondary load-
frequency control at a given time, considering the value of RSFP level N at this
time.ItisequaltothecontributiontoRSFPwhentheRSFPlevelNisequalto0,the
assumption used in the forecast studies.
RTE determines the secondary reserve requirement for each half-hourly point:
value recommended by UCTE for periods when the demand gradient (demand =
load France + algebraic sum of international exchanges) is low (cf. opposite page)
or increased value for periods when the demand gradient is high, with a
minimum of 500 MW regardless of the demand level.
Tertiary reserve
Theupwardordownwardtertiaryreserveisthepowerthatcanbebroughtonline
in less than half an hour. It is set up on the basis of balancing offers submitted on
thebalancingmechanism(cf.§1.5.2ofthisannex)whichhaveamobilisationtime
compatible with the utilisation envisaged within the scope of the normal
operation of this mechanism.
(1): French acronym "RSFP" for "Réglage Secondaire Fréquence Puissance".

©RTE 2004
It consists of two parts:
• rapid tertiary reserve: power reserve that can be mobilised in less than
15 minutes, for a guaranteed period of at least one hour for each activation at
least twice a day.
The purpose of the rapid tertiary reserve, which has a minimum value of 1,000
MW, is to supplement the contributions to secondary frequency control.
• additional tertiary reserve: power reserve which can be mobilised within a
period between 15 minutes and half an hour, for a guaranteed period of at least
six consecutive hours for each activation and at least once a day.
The additional tertiary reserve, which has a minimum value of 500 MW, is
intended to reconstitute the rapid tertiary reserve.
Deferred reserve
Power which can be brought on line within a time of over half an hour and the use
of which is ensured for a given consecutive duration.The deferred reserve makes it
possible, whenever necessary, to reconstitute the desired upward (or downward)
level of tertiary reserve, therefore the operating margin level.
Operating margin (or Margin)
At instant t0, the operating margin for a given time t0 + d corresponds to the
difference between:
- on the one hand, the supply(1)
known at instant t0 as normally being available at
t0 + d (except for exceptional or safeguard actions),
- on the other hand, the demand estimated at instant t0 as likely at t0 + d.
For an upward (or downward) margin, the maximum (or minimum) generation
offered will be taken into account.
Reserve availabilities agreed upon between TSOs in the time range t0 + d
("common" reserves) can also be included, if necessary, in the operating margin.
Links between reserves and operating margin: expressed in another way, the
margin is the algebraic sum of secondary, tertiary, deferred and common reserves,
which each correspond to special characteristics, and of the "balance"(2)
.
212
(1): By "supply" is meant for the most part the generation available or declared as such
by those in charge of scheduling for the call programmes and the generation offered
as part of the normal operation of the balancing mechanism.
(2):The “balance” is an indicator characterising the difference at a given time (real-time
or future) between generation provided by RTE (in fact the sum of the active power
set points transmitted to the producers by RTE for this time) and demand (load +
exchanges) at the same time.

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The current operating margin corresponds to the margin observed at current
instant t0. It is established on the basis of the current values of the reserves and
of the "balance" known at instant t0 and expresses the extent of the severity of
the situation experienced at t0.
15-minute margin
In this case, power can be brought on line in less than 15 minutes. It is made up
of rapid tertiary reserve and secondary reserve and must make it possible to
compensate for the outage of the largest connected generation set (which may
be about 1,500 MW).
What margins are to be kept?
The requisite margin is the margin deemed necessary to respect a risk level
predefined to make use of generation facilities so as to avoid a power system
failure linked to a generation-demand balance. It is a function of the
generation/demand level, the estimated reliability of the generation facilities,
as well as the analysis of load contingencies, etc.
Each day, on D-1, RTE defines this volume for various representative time spans
and makes sure, one day ahead and then in real time, that the margin available
at these time spans remain higher than the required value. It checks more
particularly that the offers present on the balancing mechanism help reach this
objective.
Accepted risk
The operating margins help cope with contingencies. Suppliers have the
responsibility of setting up margins enabling them to protect themselves
against the risks related to their contractual commitments. As the regulatory
texts do not stipulate the minimum risk level for which the players must make
appropriate provisions, the latter determine this level themselves.
RTE, considering its experience in this domain, defines the risk level that it feels
should be covered for the French power system as a whole.This level is defined
and valid for the various time spans. Current rules are such that the likelihood
of calling upon exceptional means and safeguard actions (contract interruption,
customer load shedding, escalation to Pmax for generation sets, etc.), i.e. less
than:
- 1% at the morning peak load,
- 4% at the evening peak load.

Some figures
At constant risk, the necessary margin evolves according to the time period
considered: at close time spans, the required margin decreases in volume since
the contingency risks decrease and the future is increasingly deterministic;
conversely, at farther time spans, the volume increases because the uncertainty
about the contingencies increases.The increase of volume is nonetheless not a
linear function since the facilities which can be made available by the real-time
period must be taken into account.
The objective, such as is the practice in System operating rules, is to have in
real time a margin of 2,300 MW within 2 hours and about 1,500 MW within
15 minutes.
Operating margin under degraded operating conditions
By definition, the constituted operating margin does not make it possible to
cope with just any contingency. If it proves to be insufficient when the deadline
approaches without it being possible to reconstitute it by the usual actions, one
therefore has to use the means provided for operation under degraded
operating conditions.
In particular, when the 2-hour margin or 15-minute margin cannot be met, a
"Critical alert situation for insufficient margin" message is actuated by CNES
and sent to the producers (cf. see also the § "Insufficiency of balancing offers"
in annex A.1.5.2).
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215
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A.1.5.2 BALANCING MECHANISM
Why a balancing mechanism?
As indicated previously, RTE must have margins, for daily preparation and in
real time, enabling it to ensure the overall supply-demand balance for France
and the solving of congestion on the French public transmission system.
RTE encourages the electrical market actors to make generation facilities
available to set up these margins.To this end, after extensive consultation with
the various players concerned, RTE set in place a balancing mechanism on
31 March 2003 making it possible to pool the available means of generation.
This mechanism features the submission of offers from the balancing
participants.Any player who so desires can take part in the mechanism provided
that he complies with the rules validated by the French Energy Regulation
Commission.
The participants submit their balancing offers. RTE calls upon these offers
depending on the balancing requirements, according to the related conditions
(price, conditions for utilisation of the offers and technical constraints) and
while taking into account the System operating conditions.The activated offers
are remunerated at the offer price.
The balancing mechanism represents an annual gross physical volume (upward
and downward) of about 15 TWh, thus offering a mutual interest for each
participant:
- for the various players, making optimum use of their withdrawal capacities
or generation flexibility both in upward and downward trends, while setting
all the parameters of the offer (price, period, conditions),
- for RTE, constantly ensuring System reliability and getting a reference price
to emerge for the settlement of imbalances.
What is a balancing offer?
A day ahead of time (D-1) before 4 p.m., each participant sends RTE a generation
schedule, ie "call programmes"(1)
for its programming entities, or a load
reference and, for each of its balancing entities that he wishes to propose,
submits one or more offer(s) defined by the following parameters:
- balancing direction (upward/downward),
- period covered by the offer,
- price possibly different on previously defined flexible pricing periods,
- usage conditions.
(1): French acronym "PA" for "Programme d’Appel".

For the producers, the offer volume is implicit: it corresponds respectively to
Pmax - PA for the upward offer, PA - Pmin for the downward offer.
For the consumers, the offer corresponds to the withdrawal or extra load
volume possible compared with the forecast load.
For the other players, the volume of the upward or downward offer is expressed
explicitly.
Submission of balancing offers
The balancing mechanism operates continuously (24 hours a day) for the
transmission of offers to RTE (new offers, modification or deletion of previously
submitted offers) and in sequenced fashion to take into account the offers, on
the basis of gate closures spread out on day D. Each gate closure is followed by
a neutralisation period applying to the offers redeclarations. Over this period,
an offer cannot be:
- activated by RTE,
- withdrawn or changed by the participant.
Each player pledges not to propose the energy made available through the
various offers to another player and RTE commits itself to taking into account
and abiding by all the declared utilisation conditions of these offers.
Mobilisation of balancing offers
RTE mobilises the offers a day before or in real time, for at least one of the
following causes:
• P = C, to restore the overall supply-demand balance France;
• Network, to remedy a congestion on the national network, on the regional
network or on an international interconnection;
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t
P
Maximum
power
offered
Pmin
Call
programme
Upward offer
Downward offer

217
©RTE 2004
• System services, to reconstitute the minima required in primary and secondary
reserve;
• Margin, to restore the operating margin to the required level for the various
future time spans.
The call programme modified by RTE’s balancing requests, both on D-1 and in real
time, and possibly by redeclarations of the participants, becomes the "running
programme"(1)
.
Balancing is, quantitatively, the difference between the two powers (running
programme PM and call programme PA).
Running programmes
in real time
Call programme
redeclarations
Import & export schedule
modifications
Contingencies
Balancing
in imbalance situation
compared with the reference of D-1
- P=C balance
- Network congestion
- System services
- Margin
Running programmes D-1
Call programmes D-1
t
P Running
programme
Call
programme
Upward
balancing
Downward
balancing
Maximum
power
offered
Pmin
(1): French acronym "PM" for "Programme de Marche".

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Insufficiency of balancing offers
The availability of a sufficient volume of upward and downward offers to comply
with the requisite margin levels and the resolution of network congestion is
checked by the CNES and URSE a day ahead of time and in real time.
In case offers are insufficient, RTE warns the balancing participants according to
the conditions described in the dedicated rules (all for the margins, some for
network congestions):
- time span greater than 8 hours: alert message on the balancing mechanism, by
which RTE requests additional offers;
- time span under 8 h: message "Notification of changeover (of balancing
mechanism) to degraded operation", possibly preceded or followed up by the
sending -via the SAS (Security and Alert System) - of the safeguard order
"Critical situation due to insufficient margin" in case of non-compliance with
the upward margin level required at a given time span (8 h, 2 h, 15 min). RTE can
then mobilise exceptional offers, over and above any additional offers.

219
A A.1.6 Protection plans
©RTE 2004
A.1.6.1 NECESSITY OF PROTECTION PLANS
A.1.6.1.1 Origin and nature of faults
Electricity transmission facilities (lines, cables, substations) may be affected in
the course of their operation by a number of insulation faults. Fault causes are
usually ranked in two categories: external origin and internal origin.
The first case concerns natural or accidental causes independent of the network.
Two main types of external causes are distinguished:
• meteorological disturbances (storm, fog, frost, wind, etc.), which are the
principal cause of faults on overhead lines;
• diverse and accidental causes: electric arcs between foreign bodies
(branches, birds, etc.), electric arcs between various items of equipment
(cranes, earthwork equipment, etc.), pollution.
In the second case, the faults are due to the network itself.The internal causes
are mainly equipment damage (lines, cables, transformers, instrument
transformers, circuit-breakers, etc.) brought about by mechanical failures or the
ageing of insulants, and untimely switching which may be due to human or
equipment failure.
In most cases, a fault gives rise to the appearance of a short-circuit current
which must be cleared by de-energising the faulty facility. As a result, the faults
which affect the various system components constitute, with regard to
customers, the main cause for the interruption of the power supply.
Regardless of the cause, a fault may be of two different types: it is said to be
transient if, after a short insulation, the facility concerned can be re-energised
(flashover of an insulator string due to an atmospheric overvoltage, for
example). It is said to be permanent when it comes with damage (or presumed
damage) of equipment requiring intervention for repair or inspection before
putting the facility back into operation.
Transmission facilities sustain about 10,000 to 12,000 short-circuits per year,
the largest number of them brought about by meteorological conditions:
approximately 60% due to lightning and slightly over 20% due to frost, sticky
snow, rain, wind, salt pollution, etc. Equipment damage accounts for 2%, the
remainder being due to various causes (contacts with vegetation and animals,
incidents brought about by the users, acts of malevolence, contingencies due
to unknown causes).
Over and above meteorological causes, the number of short-circuits per 100 km
of facilities per year is closely tied in with the voltage level: about 2-3 at 400 kV,
7-8 at 225 kV, 9-12 at 90 kV and 15-20 at 63 kV.

©RTE 2004
220
RTE - Inner view of a 400 kV substation relay building
The protection systems are housed
in substation relay buildings
located near HV facilities.

©RTE 2004
221
A.1.6.1.2 Short-circuit currents
Short-circuit currents caused by faults disturb proper System operation. They
result in:
- voltage drops (voltage dips) on the network, the amplitude and duration of
which depend on the form -single phase or polyphase- of the faults, their
location, as well as the clearance time;
- heating and electrodynamic stresses in equipment which may have
damaging effects if the equipment resistance limits are exceeded;
- dynamic stresses (in particular, acceleration stresses) at the generation set
level.
As regards these different stresses, the duration of the faults is determining and
the clearance time must be perfectly controlled.
A.1.6.1.3 Fault clearance
When a fault occurs on a network facility, the facility concerned must be de-
energised by opening the one or more circuit-breakers which connect it to the
rest of the network.The functions of fault detection and control of the tripping
of HV equipment concerned are ensured by special devices: fault protections.
The protection function is one of the most critical functions when it comes to
System reliability.
As shown in the above diagram, the openings are limited
to the two circuit-breakers of the faulty line: the clearance is said to be "selective".
Protections are expected to operate reliably (no failure or unwanted
operation), selectively (tripping of only circuit-breakers necessary to clear
the fault) and fast (to minimise equipment stresses and preserve the stability
of generation sets).
Fault
SourceSource

©RTE 2004
All the protections of a network make up a "protection system". Protection
systems come in different technical levels: 75 protection plan, 83 protection
plan, 86 protection plan. Each system must be such that, in case of the failure of
a protection or circuit-breaker, back-up is always ensured; this back-up may be
provided locally (for example, by doubling the protections), or remotely by the
protections of other network facilities. Back-up will be more or less effective (in
selectivity, in rapidity, etc.) depending on the nature of the grid concerned:
interconnection networks, sub-transmission networks, etc.
Example of an emergency clearance: case of a remote back-up;
the loss of selectivity with this type of back-up is to be noted.
The protection system of meshed (or ringed) grids is more complex than the
one which protects networks in a radial arrangement, because in case of a fault
on a meshed network line, the current is divided into the different branches of
the grid.
At 400 kV, faults have to be cleared in an extremely short time so as not to
jeopardise the stability of the generation sets.The protection system makes use
of electronic or digital protective devices associated with interlocking between
substations (accelerated underreach system, for example). The limit time for
the clearance of solid three-phase short-circuits, including circuit-breakers
operation time (50 ms), is about:
- line faults: 70 to 110 ms,
- busbar faults: 140 ms for open substations, 100 ms for gas-insulated
substations,
- faults with a circuit-breaker failure: 190 to 270 ms.
222
Protection operation:
opening of circuit-breaker
Protection
failure
Emergency opening
by protection
SourceSource
Fault

©RTE 2004
223
At 225 kV, electromechanical protection equipment tends to give way to
electronic equipment within the scope of replacement programmes, whether it
be for stability requirements (substations near generation sets) or because of
obsolescence. The use of interlocking between substations (protection
signalling facilities, etc.), necessary in the case of "near substations", tends to
develop for the other facilities (taking into account of quality of supply
constraints). The maximum clearance time of solid three-phase short-circuits,
including circuit-breakers operation time (70 ms), is about:
- line faults: 120 to 150 ms for "near substations", 140 to 800 ms in general for
the other substations (< 250 ms in the case of protection signalling facilities),
- busbar faults: 95 ms for "near substations", from 600 to 800 ms for the others.
At HV1, protection systems still largely make use of electro-mechanical devices;
modernisation programmes lead to their replacement by equipment featuring
new technology for the purpose of improving quality of supply or because of
obsolescence. In sensitive areas, interlocking between substations (protection
signalling facilities) may be used. The clearance time is approximately the
same as the values adopted at 225 kV for "not near substations".
A.1.6.2 PROTECTION OF TRANSMISSION SYSTEM LINKS AGAINST INSULATION FAULTS
Considering the operating diagrams of high and extra high transmission grids,
one cannot be content with using simple intensity relays, such as those used on
radial networks.The network meshing imposes a more sophisticated protection
system to take into account the different contributions to the fault.
Schematically, the principle of this system is as follows:
ICC: short-circuit current
PX: protection on outgoing feeders
All the protections detect and locate the fault:
- the PXAs and PXCs locate the fault "outside" the facility that they protect and
do not immediately command tripping;
- the PXBs locate the fault on the facility that they protect and command the
opening of the ends of line B.
Fault
Line A Line B Line C
PXA
Source
PXA PXB PXCPXB PXC
Source
ICC1 ICC2

224
©RTE 2004
For transmission system lines, the protection system meets the three-fold
requirement of operating reliability, selectivity and rapidity. This supposes
equipment redundancy, or even functional complementarity, of equipment
used at each outgoing feeder level (operating reliability criterion) and,
depending on the need, the implementation of a system of data exchange
between the protections of the two ends of the facility (rapidity and selectivity
criteria); in this last case, we speak of remote protection.
Two main types of protection are distinguished:
• protections using local criteria worked out on the basis of the measurement
of currents and/or voltages at each outgoing feeder level: these are distance
protections which serve to indicate the fault location by impedance
measurement via outgoing feeder instrument transformers, which
determine the location of the faults and consequently issue tripping
commands and protection signalling facilities;
• protections using the criterion of comparison of electrical magnitudes at the
ends of the facility: the two main ones are line differential protections
(current difference) and phase comparison protections (voltage/current
phase deviation).
A.1.6.2.1 Distance protection principle - Advantages and drawbacks
The distance protection principle is outlined below: on the one hand, for faults
between phases and, on the other hand, for phase-to-earth faults.
Fault between
phases
Distance protection
Phase A
Phase B
Phase C
Current transformer
Voltage transformer
Impedance measurement
of faulty phase-to-phase
loop
Impedance measurement
of faulty phase-to-earth
loop
Earth fault
Distance protection
Phase A
Phase B
Phase C

225
©RTE 2004
The fault is located at the protection level by two distance measurements: the
first generally covers 80% of the length of the line, the second 120%.
-The first, taking into account the errors specific to the measurement and the
lack of precise knowledge about the characteristics of the facility, allows to
reliably identify the fault in the facility and to proceed with immediate
tripping.The fault is then said to be in "zone 1" and cleared at the "1st
stage".
- The second serves to cover the rest of the facility, but at a range going beyond
the busbars of the opposite substation and covers, to a certain extent, the
outgoing feeders connected to it. It is necessarily time-delayed so as to be
selective as regards the faults which might occur and which must be cleared
by local protections.The fault is then said to be in "zone 2" and cleared at the
"2nd
stage".
The diagram below sums up this procedure, in direction A to B (the operating
principles are the same in the other direction).
• Advantages:This protection detects the faults beyond the facility concerned
and thus offers the advantage of ensuring emergency triggering for faults
occurring at substation B or farther (busbar faults, line faults improperly
cleared following a circuit-breaker or protection failure). In this case, one
speaks of operation under "remote back-up" conditions.
• Drawbacks: On the other hand, it is relatively slow in the 2nd
stage. This
inconvenience can be reduced by resorting to information exchanges
between the ends of the facility by means of teletransmission systems
(accelerated underreach system).
Furthermore, for short links, the differentiation between zones 1 and 2
reaches its limits. However, these protections can still be used by resorting
to blocking systems.
Outgoing feeder A
Zone 1 (80 %)
Zone 2 (120 %)
Opening time
1st
stage - Outgoing feeder A (PXA)
Zone 2 (120 %)
Outgoing feeder B
Zone 1 (80 %)
2nd
stage - Outgoing feeder A (PXA)
1st
stage - Outgoing feeder B (PXB)
2nd
stage - Outgoing feeder B (PXB)

A.1.6.2.2 Principle of differential and phase comparison protections -
Advantages and drawbacks
The line differential protection calculates the deviation between the current
values measured at both ends of the line and compares it with a predefined
threshold. If this limit is exceeded, triggering occurs.
The phase comparison protection works according to the same principle, but
detection concerns the phase deviation between voltage and current at the two
ends of the line.
• Advantages: Other than their insensitivity to flow currents, these protections
offer the advantage of a better selection of the fault phase(s), in particular on
the conductors of two-circuit lines (case of faults simultaneously affecting
the two circuits). In addition, differential protection provides efficient
protection of lines with tapped connections.
• Drawbacks: As a rule, these protections are insensitive to external faults and
cannot ensure "remote back-up". They must therefore be combined with a
distance relay.
Furthermore, they require specific high-performance transmission circuits
notably in terms of availability (which may themselves constitute a common
mode between several facilities).The resulting cost limits its use to the 400
kV grid and to underground links.
A.1.6.2.3 Utilisation limits of these protections
The scope of action of distance protections, differential or phase comparison
protections is limited to the clearance of low-resistance faults (fault resistance below
30 ).To clear resistive faults, specific protections the principle of which is to measure
the homopolar power are used.These protections have the drawback of being slow,
which is acceptable because this type of fault is less constraining.
226
©RTE 2004
Transmission of values
of I1 and I2
I1
Tripping
if |I1- I2 | > Iseuil
I2
Tripping
if |I1- I2 | > Iseuil
Iseuil
= tripping tuning threshold
Differential Differential
Transmission of values
of 1 and 2
I1
I2
Tripping
if | 1 - 2 | > seuil
V1 V2
Tripping
if | 1 - 2| > seuil
: Phase angle between V and I
seuil
= tripping tuning threshold
Phase comp. Phase comp.

(1): In these situations, the interlocking system is secured.
(2):The interlocking system is implemented depending on customer constraints.
(3):This time corresponds to the clearance of faults in zone 1 and zone 2
with accelerated underreach system.
(4):This is a simplified protection for the clearance of polyphase faults.
(5): French acronyms: "CPEC" for "Changeur de Prise En Charge",
"TPN" for "Transformateur de Point Neutre". 227
©RTE 2004
A.1.6.2.4 Types of equipment and performances for the different voltage levels
The table below lists the equipment used and average performances for
common cases (including the operating time of circuit-breakers).
It shows the redundancy mode chosen to ensure operating reliability. The
protection against resistive faults is not mentioned, but is systematically
provided.
A.1.6.3 PROTECTION OF TRANSFORMATION BANKS
Schematically, an EHV/HV transformation bank consists of:
• the transformer itself and associated equipment:
- the on-load tap changer CPEC(5)
,
- the neutral point transformer TPN(5)
, making it possible to recreate an HV
neutral in case of aY-delta connection,
Protection Protection Interlocking
Standard
Network
n° 1 n° 2 system
performances Comments
(in ms)
400 kV distance distance YES (1)
70
400 kV differential distance YES (1)
70
Strategic double lines,
tapped connections
225 kV distance distance YES (2)
80 (3)
225 kV phase distance YES (1)
80 Stability constraints
HV1 distance distance YES (2)
80 (3)
EHV/HV substations
HV1 distance back-up (4)
YES (2)
80 (3)
225 kV distance nil YES (2)
210 (3)
Former layouts
of electromechanical
HV1 distance nil 210 drawings

- the earthing reactor RPN(1)
of the EHV neutral point or HV neutral point,
- the auxiliary services transformer TSA(1)
, powering the substation
auxiliaries. It is connected either to the transformer tertiary or to the TPN
(Y-delta transformer) secondary,
• the primary link, situated between the circuit-breaker on the primary side
(EHV) and the transformer,
• the secondary link, included between the transformer secondary and the
instrument transformers installed on the HV side.
The protection of the transformation bank is part of specific measures
coordinated with the protection of lines and substation busbars. It is broken
down according to the following three sub-units.
A.1.6.3.1 Protection of the transformer and associated equipment
Transformer protection is ensured according to the following principles:
- Buchholz protection, which is meant to clear faults in the transformer by
detecting oil movements or the presence of gas, subsequent to an internal
disruptive discharge,
- tank earth protection, which supplements the foregoing protection and detects
an internal or external disruptive discharge between a live element and the
transformer tank by measuring the current flowing in the tank earth connection
(which requires the tank to be insulated from the ground by insulating blocks).
The associated equipment (CPEC,TPN,TSA) is protected by separate equipment of
the same type as that protecting the transformer: Buchholz protection, tank earth
protection or neutral current relay as the case may be.
EHV busbars
HV busbarsBushing
Oil circuit
Oil conservator
EHV busbars zone
Primary link Transformer
Bushing: Core-type current transformer
Secondary link
HV busbars zone
Bushing
Tank
earth
Circuit-breakerInsulating
blocks
Buchholz
Selector switch
disconnector Selector switch
disconnector
Circuit-breaker
Instrument
combined
transformer
Transformation bank diagram
228
©RTE 2004
(1): French acronyms: "RPN" for "Réactance de Point Neutre",
"TSA" for "Transformateur de Services Auxiliaires".

229
©RTE 2004
A.1.6.3.2 Primary link protection
The primary link is generally very short; it therefore includes no particular
protection.The faults affecting this link are cleared as busbar faults.
A.1.6.3.3 Secondary link protection
Regardless of the plan, the protections associated with the secondary link carry
out several functions:
- main secondary link protection,
- back-up secondary link protection,
- back-up protection on EHV side (clearance of transformer contribution to an
EHV fault), such as, for example, the tripping of the transformer to back up
the main protection of EHV busbars or for a poorly-cleared EHV fault,
- back-up protection on HV side (for the purpose of clearing transformer
contribution to an HV fault),
- HV ring opening protection (action on HV connection circuit-breaker).
A.1.6.3.4 Transformer protection performances
The table below shows, for the various plans, the performances of the different
busbar protections used on the transformers (operating time in milliseconds,
including circuit-breaker opening):
Electro- 225 kV 400 kV - 75 400 kV - 75 400 kV - 86mechanical and HV 83 evolution 83
Circuit-breaker operation 80 70 55 55 55
Buchholz 160 110 95 95 95
Tank earth connection 160 110 95 95 95
Secondary link fault 180 90 85 85 75
EHV back-up 1,300 1,700 580 580 1,700
HV back-up: normal 2,500 to 3,500 3,200 2,200 2,200 2,200
CB(1)
open 500 - 400 400 -
Ring opening HV:bus coupler CB 1,300 400 to 600 - - -
HV transformer CB 2,500 to 3,500 2,000 to 2,500 - - -
(1): CB = circuit-breaker.

A.1.6.3.5 Service resumption
In order to facilitate analysis prior to resuming service after the tripping of a
transformer, the information relative to the causes of the outage has been
ranked in three levels:
• Certain fault: the fault is on the transformation unit and any attempt to
restore voltage is prohibited. It concerns a tripping by Buchholz (transformer,
TSA or TPN), secondary link differential (or cable earth), CPEC fault,
maximumTSA neutral intensity, maximum tertiary current intensity.
• Uncertain fault: the fault is inside or outside the transformation bank and
one may try, after analysis, to re-energise. It concerns a tripping due to a
tank earth fault (example: disruptive discharge of a terminal spark gap) or by
EHV back-up protection.
• External fault: the fault occurs outside the transformation bank and it is
normal to try to re-energise the transformer. It is a fault triggered by an EHV
or HV busbar fault or circuit-breaker failure, HV back-up protection,
maximumTPN or RPN neutral intensity.
A.1.6.4 PROTECTION OF TRANSMISSION SYSTEM SUBSTATION BUSBARS
"Busbar faults" are faults located in the substation within the area delimited by
the current measurement transformers installed on outgoing feeders.This area
is called "busbar zone".
Apart from their effect on equipment, these faults can be particularly
constraining for network stability at EHV, and for customer quality of supply on
the EHV and HV sub-transmission networks. As a result, particular protection
systems are implemented to detect and locate the faulty busbar section and de-
energise it. Their performances are adapted according to the roles of each
network: interconnection, sub-transmission, etc.
Generally speaking, the system used to clear busbar faults on EHV networks is
made up of:
• a differential busbar protection, performing fault clearance by local opening,
at the substation concerned, of the bus coupler circuit-breakers and switched
busbar circuit-breakers delimiting the faulty busbar section and of the circuit-
breakers of outgoing feeders switched onto this busbar section;
• a busbar ring opening protection, providing back-up and separating the
faulty busbar section from the rest of the substation (ring opening of
busbars), completed by the natural second-stage operation of the distance
protections of the outgoing feeders adjoining the faulty busbar section, thus
ensuring total fault clearance.
The operating principle of these systems is presented hereafter.
©RTE 2004
230

231
©RTE 2004
A.1.6.4.1 Busbar differential protection
The busbar differential protection performs the sum of the currents on the
various substation busbar sections. If it is not nil on a section, the protection
detects a busbar fault. The fault is then cleared by the local opening of the
circuit-breakers of the outgoing feeders powering the faulty busbar section, as
well as connecting or section circuit-breakers adjoining it. This function is
carried out by a single, centralised equipment item, independent of outgoing
feeder protections.
Busbar differential protection general diagram
In case of a busbar fault, the differential protection makes only the circuit-
breakers connected to the faulty busbar section trip. The busbar differential
protection must therefore know the substation electric diagram. To do so, it
uses the positions of the selector switch disconnectors of the various outgoing
feeders.
A.1.6.4.2 Busbar ring opening protection
Fault clearance is carried out in two stages:
1) opening, in the faulty substation, of the bus coupler circuit-breaker to
separate the busbar sections and thereby isolate the faulty busbar from the
rest of the substation;
2) opening, in the remote substations, of the outgoing feeders still supplying
the fault.
Fault
I4
I2
I3
Ifault
I1
Busbar differential protection
1 2
Tripping
1 No trippingBusbars 1 : I1
+ I2
+ I3
= 0
2 TrippingBusbars 2 : I1
+ I4
= Ifault
≠ 0
Current transformer → Ii

233
©RTE 2004
A.1.6.4.3 Supervision protection
Supervision protection is a particular busbar ring opening protection, making
use, to ensure the ring opening function, of a simplified differential protection
taking into account only the sum of the currents going through the outgoing
feeders independently of their switching operations.
This protection, used solely at 400 kV to protect strategic substation back-ups,
offers the advantage of being more rapid than a conventional ring opening
protection.
A.1.6.4.4 Implementation and performances
The table below lists the performances of the busbar protections used at the
different voltage levels (including circuit-breaker opening time: 50 ms at 400 kV
and 50 to 80 ms at 225 kV).The main protections are noted "Pp" and the back-up
protections "Ps".
Network Technical level Busbar protection Clearance time
400 kV 75 protection plan Pp: busbar differential 70 ms
83 evolution Ps: busbar ring opening Bus couplers: 250 to 380 ms(1)
and 86 protection plan Remote CB (3)
: 380 to 590 ms(1)
Strategic 75 protection plan Pp: busbar differential 70 ms
400 kV substations 83 evolution Ps: supervision Bus couplers: 105 ms
and 86 protection plan Remote CB: 370 to 500 ms
Interconnection 83 protection plan Pp: busbar differential 70 ms
225 kV 225 kV and HV Ps: busbar ring opening Bus couplers: 320 ms
Remote CB: 490 ms
Sub-transmission Electromechanical Pp: busbar ring opening(2)
Bus couplers: 380 to 560 ms(1)
225 kV and HV 225 kV and HV Remote CB: 600 to 800 ms(1)
protection plan
(1): Depending on the technical levels.
(2): Some 225 kV substations are equipped with more effective busbar protections, depending on their strategic
importance with regard to customers.The installation of more effective protections in HV substations is
considered on a case-by-case basis after an economic calculation according to the quality of supply needs.
(3): CB = circuit-breaker.
Worthy of note is the particular case of gas-insulated substations which, as a
rule, are equipped with a busbar differential protection regardless of their
voltage level.

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