1. No category

Tempus JPCR 530194-2012
Energy Efficiency, Renewable Energy Sources and Environmental
Impact – master study (ENERESE)
Energy Monitoring
and
System Control
P. Braciník
University of Žilina, Faculty of Electrical Engineering,
Žilina, Slovakia
Synchronous Area
●
CONTROL AREA
Is a coherent part of
the interconnected
system operated by a
single Transmission
System Operator
(TSO), with physical
loads and controllable
generation units
connected within the
control area.
Synchronous Area
●
SYNCHRONOUS AREA
Is an area covered by
interconnected system
whose control areas are
synchronously
interconnected with
control areas of members
of the association. Within
a synchronous area the
system frequency is
common on a steady
state.
Synchronous Area
●
SYSTEM FREQUENCY
Is the electric frequency of
the system that can be
measured in all network
areas of the synchronous
area under the assumption
of a coherent value for the
system in the time frame of
seconds (with minor
differences between
different measurement
locations only).
Synchronous Area
●
ENTSO-E
●
System frequency - 50 Hz
Power equilibrium
P generated =Pdemanded
P generated =Plosses + Pload
Daily Demand Diagram
www.sepsas.sk
Daily Demand Diagram
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●
●
●
Is usually defined in advance but the final
specification is done 24 hours ahead!
The source of information are distribution
utilities, elelctricity sellers and big
customers.
It is only a forecast, the real demand
always differs from it --> a task for TSO's
dispatchers to ensure system frequency
A measurement of a control/synchronous
area is needed!!!
Measurement system
●
Input data
–
Electrical parameters:
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●
●
●
–
U (phase-to-phase, phase-to-ground )
I
f
cos φ, power factor
They are used to calculate:
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S (VA)
P (W)
Q (var)
Energy (Wh)
Measurement system
●
Input data
–
Electrical parameters:
●
●
●
●
–
U (phase-to-phase, phase-to-ground)
I
f
cos φ, power factor
Other parameters:
●
●
●
temperature (e.g. transformer oil)
pressure (e.g. steam in a boilerl)
position (e.g. switching devices)
Measurement system
●
This „chain“ is always effected by error!!
http://www.informationphilosopher.com
Instrument transformers
●
●
volatage or current transformers
secondary output voltages and
currents are unified:
100 V or 100/√3 V
– 1 A or 5 A
their secondary sides are
connected to:
–
●
maesurement devices
– protection relays
–
Voltage transformers
phase-to-ground measurement
http://www.abb.com
Voltage transformers
phase-to-phase
with fuse
http://www.abb.com
Voltage transformers
outdoor versions
http://www.abb.com
Voltage transformers
●
●
●
●
Abbreviation used – VT
Often have two or more output terminals –
different for a protection purposes and for a
measurement
Main characteristics:
–
nominal input voltage UN,
–
critical operation current INk = 1,2 IN,
–
nominal output voltage,
–
accuracy class (different for different output
terminals),
–
nominal burden
They can have a fuse in the primary circuit
Voltage transformers
Voltage transformers
Two types of errors:
1. Amplitude error (%):
|pu⋅U 2−U 1|
εu =Δ u=
⋅100
U1
εu =ε without load+εwithload
2. Angle error (“)
- is given by the angle δU between U1 and U2
- is taken into account only by the
measurement of apower and an energy (U·I)
These errors are not constant, but depends on
e.g. VT load, cos φ, frequency ...
➢
Current transformers
indoor versions
http://www.abb.com
Current transformers
outdoor versions
http://www.abb.com
Current transformers
●
Abbreviation used – CT
●
They have also two or more output terminals –like VTs
●
Main characteristics:
●
–
nominal input current IN,
–
critical operation current INk = 1,2 IN,
–
nominal output current,
–
accuracy class (different for different output terminals),
–
nominal burden,
–
nominal frequency,
–
nominal dynamic current Idyn,
–
nominal thermal current IN,
Their secondary terminals needn't be disconnected!!!
Current transformers
Current transformers
Two types of errors:
1. Amplitude error (%):
p I⋅I 2 −I 1
εi =
⋅100
I1
2. Angle error (“)
- is given by the angle δI between I1 and I2
- is taken into account only by the
measurement of apower and an energy (U·I)
These errors are not constant, but depends on
e.g. CT load, harmonics, core saturation, ...
➢
Sensors - voltage
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●
●
output in volts
ratio is usually 10 000:1
or 20 000:1
direct connections to
digital relays
http://www.abb.com
Sensors - current
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●
http://www.abb.com
output is from 150 to 300 mV
current value has to be
numerically integrated
direct connections to digital
relays
Meters
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Used in low voltage
networks
For billing purposes
electromechanical
●
They are expected to
be more smart in the
future --> SMART
GRIDS
electronic
Load-Frequency Control
●
If the power equlibrium in synchronous area is lost,
it always results in frequency deviation:
system frequency f ≠ 50 Hz!!!
●
It has to be restored to 50 Hz by power sources
being involved in frequency control (I., II. and III.)
Load-Frequency Control
Exmple of a real frequency deviation
Load-Frequency Control
NETWORK POWER FREQUENCY
CHARACTERISTIC :
●
of a synchronous area/block is the quotient of
the power deviation ∆Pa responsible for the
disturbance and
the quasi-steady-state
frequency deviation ∆f c a u s e d b y t h e
disturbance (power deficits are considered as
negative values):
Δ P a Δ P gen−Δ P demand
λu =
=
(MW / Hz)
Δf
Δf
Load-Frequency Control
GENERATION POWER FREQUENCY
CHARACTERISTIC :
Δ P gen
λ gen=−
( MW / Hz)
Δf
Load-Frequency Control
LOAD POWER FREQUENCY
CHARACTERISTIC :
Pload
Δ P load
λload =
( MW / Hz)
Δf
Load-Frequency Control
Various loads have a
different levels of
frequency dependance:
●
zero,
●
linear,
●
square or cubic.
LOAD POWER FREQUENCY
CHARACTERISTIC :
Pload
This load behavior is called self-regulating effect of the load
Load-Frequency Control
Various loads have a
different levels of
frequency dependance:
●
zero,
●
linear,
●
square or cubic.
It is hard to set
(measure) a value of
control area's λload, in
interconnected
networks, so it is set
according to
experiance or is
neglected in real
operation.
LOAD POWER FREQUENCY
CHARACTERISTIC :
Pload
Load-Frequency Control
NETWORK POWER FREQUENCY
CHARACTERISTIC :
λu =λ gen +λ load ( MW / Hz)
λ gen≫λ load
For a real dispatching control is much better to evaluate
network power frequency characteristic of a i-th control
area/block of a synchronous area according to following
formula:
−Δ P i
λi =
( MW / Hz)
Δf
●
●
ΔPi – is a power deviation measured at the tie-lines of i-th
control area
Δf – is a frequency deviation in response to the disturbance
in the control area
Load-Frequency Control
General overview --> realized through dispatching actions
Primary control
Primary Control
Primary Control
The magnitude ∆fdyn.max of the dynamic frequency
deviation is governed mainly by the following:
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the amplitude and development over time of the
disturbance affecting the balance between power
output and consumption;
the kinetic energy of rotating machines in the system;
the number of generators subject to primary control,
the primary control reserve and its distribution
between these generators;
the dynamic characteristics of the machines
(including controllers);
the dynamic characteristics of loads, particularly
the self-regulating effect of loads.
Primary Control
Primary Control
Primary Control
The quasi-steady-state frequency deviation ∆f
i s g o v e rn e d b y t h e a m p l i t u d e o f t h e
disturbance and the network power frequency
characteristiic, which is influenced mainly by
the following:
●
●
the droop of all generators subject to primary
control in the synchronous area;
the sensitivity of consumption to variations in
system frequency.
Droop of a Generator
Primary Control
The primary control has a character of a joint
action --> each TSO in synchronous area
must contribute to the correction of a
disturbance in accordance with its respective
contribution coefficient Ci to primary control:
Ei
C i=
Eu
●
●
Ei being the electricity generated in control
area/block i
Eu being the total (sum of) electricity production in
all control areas/blocks of the synchronous area
It is not raleted to the installed capacity of generators!
Primary Control
●
●
●
The primary control reserve of ENTSO-E is
Ppu = 3 000 MW.
MW
This value was set according to
–
measurements,
–
experience,
–
theoretical considerations.
Primary control reserve Ppi for a i-th control
area:
P pi=C i⋅P pu
Ppi for Slovakia is about 30 MW ( ±)
Primary control
Primary Control
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Maximum Δf being solved by primary control is ± 200 mHz
If self-regulating effect of the load is taken into account ->
Δf = ± 180 mHz
Allowed frequency deviation is ± 20 mHz for long periods
under undisturbed conditions – elimination of primary control
action by unscheduled cross-boards power flows.
Insensitivity of primary controllers is set to ± 10 mHz.
mHz
Primary Control
Primary Control
Performance measurement and evaluation
Secondary Control
Secondary Control
●
●
Primary control allows a balance to be re-established at
a system other than the frequency set-point value (at a
quasi-steady-state frequeny deviation ∆f), in response
to a sudden imbalance between power generation and
consumption (incident) or random deviations from the
power equilibrium (if ΔP > ΔPpi).
Since all conrol areas/blocks contribute to the control
process in the interconnected system, with associated
changes in the balance of generation and consumption
in these control areas, an imbalance between power
generation and consumption in any control area will
cause power interchanges between individual control
areas to deviate from the agreed / scheduled values
(power interchange deviations ∆Pi).
Secondary Control
●
The function of sencondary control is to keep
or to restore the power balance in each control
area/block
and,
area
and consequently, to keep or to
restore the system frequency f to its set-point
value of 50Hz and the power interchanges with
adjecent control areas to their programmed
scheduled values,
values thus ensuring that the full
reserve of primary control activated will be
made available again.
again
Secondary Control
AREA CONTROL ERROR (ACE) - G:
G=P meas + P prog + K ri⋅(f meas −f 0 )
●
●
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Pmeas - the sum of instantenous measured reactive
power transfers on the tie-lines
Pprog - the resulting exchange program with all the
neighbouring control areas
Kri - the K-factor of the control area (a constant in
MW/Hz set on the secondary controller)
fmeas – f0 – the difference between the instantenous
measured system frequency and the set-point
frequency
Kri is usually equal to the λi
Secondary Control
AREA CONTROL ERROR (ACE) - G:
G=P meas + P prog + K ri⋅(f meas −f 0 )
●
●
●
●
Action of
primary
control
Pmeas - the sum of instantenous measured reactive
power transfers on the tie-lines
Pprog - the resulting exchange program with all the
neighbouring control areas
Kri - the K-factor of the control area (a constant in
MW/Hz set on the secondary controller)
fmeas – f0 – the difference between the instantenous
measured system frequency and the set-point
frequency
Kri is usually equal to the λi
Secondary Control
SECONDARY CONTROLLER:
1
Δ P di=−β⋅Gi− ∫ Gi⋅dt
T
●
●
●
●
∆Pdi - the correcting variable of the secondary
controller governing control generators in the control
area i
Βi - the proportional factor (gain) of the secondary
controller in control area i
Tr - the integration time constant of the secondary
controller in control area i
Gi - the area control error (ACE) in control area i.
Secondary Control
Secondary Control
Around ± 120 MW in Slovakia
Secondary Control
Quality control --> trumpet curve
Secondary Control
The trumpet curve H(t) for a given incident will be
plotted using the following values:
●
●
●
●
the set-point frequency f0 ( f0 = 50.01 Hz in our
case)
the actual frequency f1 before the incident (f1 is
different from f0 in our case)
the maximum frequency deviation ∆f2 after the
incident, with respect to the set-point f0
the loss of generating capacity ∆Pa responsible for
the incident.
Secondary Control
Secondary control is active up to 15 minutes
Tertiary Control
Tertiary Control
Is any automatic or manual change in the
working points of generators or loads
participating, in order to:
●
●
guarantee the provision of an adequate
secondary control reserve at the right time,
distribute the secondary control power to the
various generators in the best possible way, in
terms of economic considerations.
Tertiary Control
Changes may be achieved by:
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connection and tripping of power (gas turbines,
reservoir and pumped storage power stations,
increasing or reducing the output of generators in
service);
redistributing the output from generators
participating in secondary control;
changing the power interchange programme
between interconnected undertakings;
load control (e.g. centralised telecontrol or
controlled LOAD-SCHEDDING).
Tertiary Control
Time schedule of Frequency Control
Generation Costs
Generation Costs
A=a 1+b 1⋅P+(b2 −b1 )⋅(P−P ek )
Costs
without
load
Costs by
specific
load
Costs by
higher load than
specific one
Generation Costs
costs=a0 +a1⋅P+a2⋅P
2
Generation Costs
●
Costs could be expressed by the
heat (Q) that is needed to produce
electricity:
2
Q=a0 +a 1⋅P+a2⋅P [GJ /h]
●
Than it is possible to express following
characteristics:
●
Specific heat consumption:
2
Q a0 +a1⋅P+a2⋅P
q= =
[GJ / MWh]
P
P
Generation Costs
●
Minimal specific heat consumption
(operation in an economic set point Pek ):
√
a0
Pek =
[ MWh]
a2
●
Specific heat consumption increase:
dQ
b= =a1 +2⋅a2⋅P[GJ / MWh]
dP
References
 ENTSO-E
Operation Handbook, www.
https://www.entsoe.eu/Pages/default.aspx
 ABB,
www.abb.com
 www.kves.uniza.sk/docs
Tempus JPCR 530194-2012
Energy Efficiency, Renewable Energy Sources and Environmental
Impact – master study (ENERESE)
Thank you
for your attention
P. Braciník
University of Žilina, Faculty of Electrical Engineering,
Žilina, Slovakia