Principles Control & Protection of HVDC Schemes

HVDC Bridge and Station Configurations
 1. General HVDC – HVAC Comparisons
 2. Components of a Converter Bridge
 3. HVDC scheme configurations
Operation of the HVDC converter
 1. General assumptions
 2. Rectifier operation with uncontrolled valves and X = 0
 3. Rectifier operation with controlled valves and X = 0
 4. Rectifier operation with controlled valves and X  0
 5. Inverter operation with controlled valves and X  0
 6. Commutation and Commutation Failure
 7. Reactive Power Requirements
 8. Short-circuit capacity requirements for an HVDC terminal.
 9. Harmonics and filtering on the AC and DC sides

General principles of control and protection
 1. Basic co-operation of terminals
 2. Closed loop current control
 3. Control action at co-operation of terminals
 4. Practical mode of operation
 5. Operation at disturbances
 6. Current and converter unit control
 7. Abnormal and Special Purpose Controls
 8. Grid Master Power Controller
 9. Protection Schemes

Economic considerations
Series capacitors
Areas for Development in HVDC Converters
 1. Voltage Source Converters based HVDC schemes.
 2. Grid Power Flow Controller
Modelling of HVDC Schemes

MODULE 1
Background on HVDC Development,
System Configurations and
Components

 DC was first used for power distribution
within cities
 DC was economical since power was
transmitted using 2 conductors only
 Long distance transmission posed problems
◦ Limitation of distance due to voltage drop
◦ Limitation of voltage (transmission
voltage=generation voltage)
 Reason: No transformation of voltage was possible
◦ Lower efficiency of power transmission

 Nicola Tesla first propounded use of AC for
transmission
 Benefits
◦ Ease of voltage transformation
◦ Smaller conductors
◦ Lower voltage drop because of higher voltage
◦ Lower losses because of lower current
◦ Bulk power over longer distances possible
◦ Use of 3-phase circuits further increased economy
of transmission
◦ Rugged 3-phase induction motors made AC the
automatic choice for industrial consumption

 Voltage drop includes a reactive component
also
 Reactance depends on clearance between
conductors
 Becomes high as voltage goes up
 Continuous flow of charging current
 Line to ground and line-line capacitance
 Causes voltage problems at lower loads
 Higher voltage at receiving end (Ferranti effect)
 No control on power flow but decided by circuit
parameters

Power flow control calls for use of back-to-back HVDC systems
(also called flexible AC transmission system or FACTS)

 Reduced number of conductors
 Two conductors (Bipolar) and one conductor
(monopolar)
 Solves the problem of line reactance
 Voltage regulation improves (no reactive
drop)
 Better transmission efficiency
 No continuous flow of charging current
 No Ferranti effect on light loads
 No need for frequency synchronizing
 Possibility of load flow control

Data from
Siemens
The number of thyristors that
have to be connected in series
varies – depending on the
application
-Between 10 thyristors per valve
rated 8kV in a typical SVC
application and up to 120
thyristors in a typical HVDC valve
in an 800kV
converter.

 AC is better for generation, local distribution
and consumption
◦ Ease of transformation, ease of use
 DC is advantageous for transmission
◦ Lower conductor cost, better voltage regulation
◦ Asynchronous interconnection (even between
systems of different rated frequencies)
◦ Control/modulation of power flow

 Breakeven at transmission distance > 500 km
 Shorter distance breakeven if right-of-way is
expensive
 Cable systems breakeven at > 50 km

 Two AC systems can operate independently
◦ Asynchronous interconnection
◦ Can tie systems of different nominal frequency
 Possibility of power flow control
 Improved system stability

 Systems using AC transmission require 3
conductors (for single circuit) or multiples of
3 conductors (for multi-circuit) lines
 Transmission systems using DC can be
◦ Monopolar (single conductor)
◦ Bi-polar (two conductors)
 Transmission tower carrying DC circuits
require smaller corridor and thus less
expensive

Non-controllable
valve or arm
Controllable
valve or arm
Non-controllable
bridge or valve group
Controllable bridge
or valve group

Converter
transformer
6-pulse converter
DC side
AC side
connected to
voltage source
Thyristor Switch
Smoothing
Reactor
Y
B
R
6 Pulse convertor
graphical symbol

3 Quadrivalves
DC SideAC Side
Y
B
R
Y
B
R
12 Pulse converter
unit graphical
symbol

• Continuous utilization of earth return
path
• No redundancy during contingency

 Electrochemical corrosion of long buried
metal objects such as undersea pipelines
 Underwater earth-return electrodes in
seawater may produce chlorine or otherwise
affect water chemistry
 An unbalanced current path may result in a
net magnetic field, which can affect magnetic
navigational compasses for ships passing
over an underwater cable

 Electrochemical corrosion of long buried
metal objects such as pipelines, rail tracks,
fences etc.
 Electro-osmosis

• Very little earth return current
• Higher transfer security

• Link asynchronous networks
• Link networks of different frequencies

• All HVDC terminals are at the same voltage
level

• One or more convertor bridges added in series

• Converter transformer connects directly to the generator
terminals
• Generator can have variable frequency for optimum
efficiency

• Power transmission is in one direction only
• Power flow control at the inverter
• High speed breakers for DC-line faults

Typical thyristor electronics for 8Kv thyristor www.Siemens.com

Thyristor triggering and monitoring: LTT Approach
www.Siemens.com

 Number of electrical components in the
valves reduced substantially, statistic failure
rate reduced, eliminates possibility of
electromagnetic interference (EMI),
providing inherently higher reliability.
 Firing pulses available independent of AC
system voltage, no auxiliary energy
required within the valve.
 Eliminates a potential source of partial
discharges, providing inherently longer life

MODULE 2
The Bridge Commutation Process
and Equations

Cathode
Anode
• The valve can conduct current in only one direction, the
forward direction, from the anode to the cathode
• In the opposite direction the valve blocks - reverse
blocking
• The valve starts to conduct current in the forward
direction if:
• The voltage in the forward direction across a valve is positive
• A valve control pulse is sent to the valve to trigger it into conduction.

Commutating
voltage
Converter
Commutating
reactance, XC

53
4 2
1
6
Y
B
R
R
53
4 2
1
6
Y
B
(a
)
(b
)
(c
) 53
4 2
1
6
Y
B
R R
R
53
4 2
1
6
Y
B
R
(d
)
(e
)
(f)
53
4 2
1
6
Y
B
53
4 2
1
6
Y
B
C
3
2
Udo
A E
5
B
4
D
6
1
G
B
R
Y
F

C
3
2
Udo
A E
5
B
4
D
6
1
G
B
R
Y
F
5 1 3 5
6 2 4 6
AC Voltage
DC Currents
DC Voltage

ccdo UUU 35.1
23


The average direct voltage from the two-way 6-pulse converter with X =
uncontrolled valves ( = 0) can be written as:
where:
Uc = phase-to-phase value of the commutating voltage referre
the valve side of the converter transformer, rms value
Udo = ideal no-load direct voltage, actual value

53
4 2
1
6
Y
B
R
(a)
(c)
53
4 2
1
6
Y
B
R
(b)
53
4 2
1
6
Y
B
R
µ
µ
A
B
R
Y
B
5 1 3 5
6 2 4 6

(a) (b)
53
4 2
1
6
Y
B
R
53
4 2
1
6
Y
B
R
B C
Y
B
R
µ
α
µ
α
A
1
2
3

 = Overlap angle or Commutation angle. Use
current equation if  not available
    coscosdod UU     coscos
2 c
c
d
X
U
I
d
c
dod I
X
UU


3
cos 
Commutati
ng voltage
Converter
Commutatin
g reactance,
XC

Three conditions are thus required to permit power inversion:
• An active ac voltage source which provides the commutating voltage wa
• Provision of firing angle control to delay the commutations beyond  =
• A dc power supply.
AC side
connected to
voltage source Thyristor
Switch
DC Current
Converter
Commutatin
g reactance,
XC

53
4 2
1
6
Y
B
R
(a) (b)
53
4 2
1
6
Y
B
R
B
R
Y
α
6
2
1
3

β
µ

U
Firing
Overlap area AI
A(t)
Area margin Am
t = t2
t = to t = t1
t

Ucr
Ramp
function
generator
Level
detecto
r

T/6Control
pulses
Ucr T/6+ Ucr Firing
t
60º t1   t2

Inverter : Graphs
4.980 5.000 5.020 5.040 5.060 ...
...
...
0.00
0.25
0.50
0.75
1.00
1.25
(pu)
Valve dc voltage
-1.50
-1.00
-0.50
0.00
0.50
1.00
1.50
(pu)
Valve Voltage
-0.50
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
(kA)
Valve current
-1.25
-1.00
-0.75
-0.50
-0.25
0.00
0.25
0.50
0.75
1.00
1.25
(pu)
AC Voltage

Inverter : Graphs
4.950 5.000 5.050 5.100 5.150 5.200 5.250 ...
...
...
0.00
0.25
0.50
0.75
1.00
1.25
(pu)
Valve dc voltage
-0.50
3.50
(kA)
Valve current

Inverter equations are often expressed in terms
of:
angle of advance  =  - 
extinction angle  =  - 
d
c
dod I
X
UU


3
cos  d
c
dod I
X
UU


3
cos 
)cos(cos5.0   dod UU   coscos
2

c
c
d
X
U
I

Rectifier
ULr Uv
r
Ivr
U
dr
Id
Ivi
U
Li
Uv
i
Udi
Inverter


 




XC X
C

Delay angle .
The time expressed in electrical angular measure from the zero
crossing of the idealised sinusoidal commutating voltage to the
starting instant of forward current conduction. This angle is
controlled by the gate firing pulse and if less than 90º, the
converter bridge is a rectifier and if greater than 90º, it is an
inverter. This angle is often referred to as the firing angle.
Advance angle .
The time expressed in electrical angular measure from the
starting instant of forward current conduction to the next zero
crossing of the idealised sinusoidal commutating voltage. The
angle of advance  is related to the angle of delay  by:
= 1800 - 

Overlap angle .
The duration of commutation between two converter valve
arms expressed in electrical angular measure.
Extinction angle .
The time expressed in electrical angular measure from the
end of current conduction to the next zero crossing of the
idealised sinusoidal commutating voltage.  depends on the
angle of advance  and the angle of overlap  and is
determined by the relation:
 =  - 

 MODULE 4
 Control and Protection of HVDC Systems

Uv1 Uv2
Ud1 Ud2
Rectifier
(sending)
Id
R
Inverter
(receiving)
Ud1  (Ud1  Ud2)
P = R
Ud1 - Ud2
Id = R

Idc *
Rline Vrect Estim
Vdc Ref
Contr Error

I-Response
I - order
I
Control
Amplifie
r
Firing
Control
I-Response
Ud
I
I - order
____

__
Current Margin
Rectifier Inverter

Rectifier controls current through firing angle control. Higher firing angle,
lower current.
Inverter controls for maximum voltage. Extinction angle control keeps
extinction angle constant minimum value.
Current controller at inverter receives current order from rectifier minus
current margin of 10%. Thus current controller at inverter always, during
healthy conditions, sees current higher than current order. Thus tries to
decrease extinction angle, increase voltage in opposition.
With voltage reduction at rectifier, firing angle reduce to increase voltage
on DC so that current level could be maintained. If alpha minimum is
reached, rectifier is in saturation and current value will reduce.

If DC current reduce by more than current margin,
10%, current controller at inverter will see actual
current less than order – margin.
Thus, current too low and extinction angle will be
increased to decrease voltage until current settles
at 10% less than rectifier current order.
Rectifier tap changers will increase AC voltage
until rectifier regains control through firing angle.
Inverter tap changers will correct voltage for
extinction angle control values.

Idc *
Rline Vrect Estim
Vdc Ref
Contr Error
Ma
x
Gam = 18
Gam > 18
Current
Control at
Inv on
Current
Margin
Gam =35
Gam Kick
from com
Fail protect

MODULE 3
Harmonics and Reactive Power
Requirements

Rectifier
Power Factor = Cos() = Cos() - 0.5 Xc(Id/IdN)
Inverter:
Power Factor = Cos() = Cos()- 0.5 Xc(Id/IdN)
Power Flowing through the Bridge
Pd = Id Ud
Reactive Power Required by Converter
QL = Pd Tan()

The rectifier delay angle  is usually known, for example, 10o
< 
< 18o
.
For the inverter, the normal rated extinction angle is established in
the converter bridge design, usually at  = 18o
.
Id is the d.c. load current and IdN is rated d.c. current and  is the
power factor angle.
The power flowing through the bridge Pd is:
Pd = Id Ud
where Id is the operating direct current through the converter
bridge and Ud is the operating direct voltage across the converter
bridge.

Consider an imaginative but realistic scheme with typical operating parameters of
Xc = 0.16 pu,  = 12 and  = 18 the converter reactive power absorption at rated dc
load can be calculated as follows for the rectifier and the inverter respectively:












 
2
coscostan 1
0
c
dc
X
Q 
  08.09781.0costan 1
0  
dcQ
4897.00 dcQ












 
2
coscostan 1
0
c
dc
X
Q 
  08.09511.0costan 1
0  
dcQ
56.00 dcQ
Rectifier:
of rated dc load
Inverter
of rated dc load













 
2
coscostan 1
0
c
dc
X
Q 
d
c
dod I
X
UU


3
cos 

0
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
1.8
2
0
0.2
0.4
0.6
0.8
1
1.2
12 16 20 24 28 32 36 40 44 48 52 56
ReactivePowerAbsorption
ConverterOutputVoltage
Delay Agle
DC Voltage and Q with Alpha
Ud Q

 Rectifier ac fault: AC lower, DC lower, current
lower, alpha smaller to increase voltage and
current, less Q, thus support voltage
recovery.
 Inverter ac fault: AC lower, DC lower, current
increase, comm failure, gamma kick, more
reactive power, ac suppress due to more
reactive power consumption at high gamma.
AC Voltage under more presure.







 ......11cos
11
1
7cos
7
1
5cos
5
1
cos
32
ttttIi d 







 ......11cos
11
1
7cos
7
1
5cos
5
1
cos
32
ttttIi d 

The Fourier series for the ac current waveform for a star/star connected converter transformer
The Fourier series for the ac current waveform for a star/delta connected converter transformer

For a 6-pulse converter harmonics of the order
n = 6 (k).; k - 1, 2, 3
For a 12-pulse converter we consequently get
n = 12 (k).; k - 1, 2, 3

100
3
% 
MVAinlevelfault
MVArCap
V


 MODULE 5
 HVDC Scheme Protection

 MODULE 4
 AC / DC Interactions

DC Disturbances:
Pole to ground
faults.
Converter faults.
Blocking of converters.
Inadvertent tripping of pole.
Results:
Commutation failure.
Power oscillations in ac
network.
System frequency variations.
Sub-synchronous voltage and
power oscillations.
AC Disturbances:
•1 and 3 phase faults.
High impedance faults.
Voltage unbalance.
Flicker.
Harmonic distortion.
Reactive power demand.
AC Disturbances:
1 and 3 phase faults
in the ac network
feeding the rectifier
Generation
Rectifier
IR
Inverter
AC System
AC Network

• System faults caused by short circuits on the network
which can result in the loss of equipment such as
generators, capacitors, reactors, AC lines, filters,
transformers and SVC’s.
• The connection and disconnection of AC side
components such as the switching of shunt capacitor
banks, shunt reactors, AC lines, harmonic filters,
transformers and SVC’s can result in over or under voltage
conditions, reactive power excesses or deficiency, etc.
• With fast load variation, there can be an excess or
deficiency of reactive power at the ac commutating bus
which results in over and under voltages respectively.
• Disturbances can be caused by malfunction of
protection or control circuits.
• During a line fault event somewhere on the ac power
system, generators may become unstable.

Generators
DC Line
Inverter
Receiving AC
Busbar
Sending
AC Busbar
Smoothing
Reactor
Converter
Transformer
Loads
Loads
Rectifier

Inverter
1.90 2.00 2.10 2.20 2.30 2.40 2.50 2.60 ...
...
...
-1.50
-1.00
-0.50
0.00
0.50
1.00
1.50
(pu)
Inverter AC Voltage
-0.50
1.75
(pu)
DC Voltage P1 DC Current P1
0.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40
Power
DC Pow er P1
RECTIFIER
Time 1.90 2.00 2.10 2.20 2.30 2.40 2.50 2.60 ...
...
...
-0.80
-0.40
0.00
0.40
0.80
(pu)
Rectifier AC Voltage
0.20
1.30
(pu)
Rectifier DC Volts Rectifier DC Current
0.00
0.20
0.40
0.60
0.80
1.00
1.20
(pu)
Pow er

RECTIFIER
Time 1.90 2.00 2.10 2.20 2.30 2.40 2.50 2.60 ...
...
...
-0.80
-0.40
0.00
0.40
0.80
(pu)
Rectifier AC Voltage
0.00
0.20
0.40
0.60
0.80
1.00
1.20
(pu)
Rectifier DC Volts Rectifier DC Current
0.00
0.20
0.40
0.60
0.80
1.00
1.20
(pu)
Pow er
INVERTER
Time 1.80 1.90 2.00 2.10 2.20 2.30 2.40 2.50 ...
...
...
-1.25
1.25
(pu)
Inverter AC Voltage
-0.20
1.75
(pu)
Inverter DC Volts Inverter DC Current
0.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1.60
y
DC Pow er

2000MW
HVDC
South Africa
Zimbabwe
330kV
Interconnectio
n
Cahora
Bassa
GenerationInterconnection
s
400kV
Interconnecti
on

• Commutation Failures
• Line Faults
• Load Rejections
AC – HVDC Interactions
HVDC Events

Rectifier
Time 3.50 3.75 4.00 4.25 4.50 4.75 5.00 ...
...
...
0.900
0.950
1.000
1.050
1.100
1.150
1.200
1.250
(pu)
Retifier AC Volts (RMS)
-1.00
-0.50
0.00
0.50
1.00
1.50
2.00
(pu)
DC Current P1 DC Voltage P1
-1.0k
-0.5k
0.0
0.5k
1.0k
1.5k
2.0k
2.5k
(MVAr,MW)
Q-Rectifier P-Rectifier
Inverter
Time 3.40 3.60 3.80 4.00 4.20 4.40 4.60 4.80 5.00 ...
...
...
0.900
0.950
1.000
1.050
1.100
(pu)
Inverter AC Volts (RMS)
-0.40
0.00
0.40
0.80
1.20
(pu)
-0.5k
0.0
0.5k
1.0k
1.5k
2.0k
2.5k
(MVAr,MW)
Q-Inverter P-Inverter

Rectifier Generation
Time 4.0 6.0 8.0 10.0 12.0 14.0 16.0 18.0 20.0 ...
...
...
0.9850
0.9900
0.9950
1.0000
1.0050
1.0100
1.0150
1.0200
(pu)
Generator Speed
1.00
1.20
1.40
(pu)
-0.3k
2.3k
(MW)
P-Generator

Rectifier
Time 3.00 3.50 4.00 4.50 5.00 5.50 6.00 6.50 7.00 ...
...
...
0.800
1.300
(pu)
0.00
0.50
1.00
1.50
(pu) DC Current P1 DC Voltage P1
0.00
0.50
1.00
1.50
(pu)
-1.0k
-0.5k
0.0
0.5k
1.0k
1.5k
2.0k
2.5k
(MVAr,MW)

Time 4.0 6.0 8.0 10.0 12.0 14.0 16.0 18.0 20.0 ...
...
...
0.9900
0.9950
1.0000
1.0050
1.0100
1.0150
1.0200
(pu)
Generator Speed
1.000
1.050
1.100
1.150
1.200
1.250
(pu)
Retifier ACVolts (RMS)
1.2k
1.4k
1.6k
1.8k
2.0k
2.2k
2.4k
2.6k
(MW)
P-Generator
Time 4.0 6.0 8.0 10.0 12.0 14.0 16.0 18.0 20.0 ...
...
...
0.9850
0.9900
0.9950
1.0000
1.0050
1.0100
1.0150
1.0200
(pu)
Generator Speed
1.00
1.20
1.40
(pu)
Retifier ACVolts (RMS)
-0.3k
2.3k
(MW)
P-Generator

Rectifier
Time 3.00 3.50 4.00 4.50 5.00 5.50 6.00 6.50 ...
...
...
0.40
0.60
0.80
1.00
1.20
1.40
1.60
(pu)
-1.50
-1.00
-0.50
0.00
0.50
1.00
1.50
(pu)
-1.50
-1.00
-0.50
0.00
0.50
1.00
1.50
(pu)
-1.0k
-0.5k
0.0
0.5k
1.0k
1.5k
2.0k
2.5k
(MVAr,MW)
Time 3.0 4.0 5.0 6.0 7.0 ...
...
...
0.975
1.225
(pu)
Generator Speed
0.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1.60
(pu)
0.0
0.5k
1.0k
1.5k
2.0k
2.5k
(MW)
P-Generator

ZESA
Eskom
G5
HVAC
busbar
HVDC
busbar
Bindura
Songo
ApolloMatimba
Insukamini
Phokoje
HCB
Route 1 Route 2
G3G2G1 G4

In the event of an HVDC line fault, things will happen due to the excess
energy generated:
• The generators will start to speed up, leading to over frequency.
• The remaining excess power will flow over the Zimbabwe line,
resulting
in power oscillations due to its transient destabilising nature.
• The increase in power on the Zimbabwe line will result in increased
voltage drop across the line, resulting in a voltage depression at the
receiving end substation.
• The power angle over the Songo – Zimbabwe interconnection will
increase
rapidly.
In the same way, during a line fault event somewhere on the Zimbabwe
power
system, the AC-transmission system, including the Cahora Bassa
generators
may become unstable.

The GMPC operates in two modes; namely angle control and
frequency control. The angle control mode is in operation while
the bus coupler between the HVAC and HVDC busbars at Songo is
closed. Therefore, the HVDC and HVAC systems operate in
parallel. The GMPC monitors the angle difference between Songo
and Apollo. In order to protect the HVAC network, the GMPC will
open the bus coupler if the angle difference is too large. This
situation could develop during any disturbance on the HVDC
system. This disturbance could, for example be the result of DC
line faults, commutation failures, blocking of the HVDC system or
any other disturbance that could prevent the transmission of the
Cahora Bassa generation via the HVDC system.
The frequency control mode of the GMPC controls the frequency of
the HVAC system in the north of Mozambique while the Songo bus
coupler is open and when the HVDC and HVAC systems are
effectively isolated from one another and are not operating in
parallel.

The main functions of the GMPC are to perform the following:
1. Ensure stable operation of the parallel HVDC and HVAC
systems;
2. Bus coupler opening at Songo during angle control mode
contingencies;
3. Generator tripping to reduce the generated energy at Cahora
Bassa during contingencies;
4. Ensure that the 220 kV busbar switching is in accordance with
the requirements for the safe operation of the power system;
5. Limit rate of rise of the HVDC power reference values;

6. Maximum and minimum frequency regulator intervention in
the HVDC power reference value;
7. Frequency measuring for pole 1 and pole 2 control;
8. Centre frequency regulator for slow correction of the power
reference values for the machines to keep the frequency at
precisely 50 Hz;
9. Averaging the actual power values of machines operating in
parallel;

Mitigation of Detrimental Effects
Special Purpose Controls
• AC system damping controls.
• AC system frequency control.
• Step change power adjustment.
• AC under voltage compensation.
• Sub synchronous oscillation damping.
• Power Control

Matambo
Songo/HCB
ZESA
477 MVA
247 MVA
Apollo
1920 MW
G
415 MW G
300 - 400 MW
Power flow
G
450 MW
1660 MW (4x415MW)
290 MW
HVAC island
HVDC island

Matambo
Songo/HCB
ZESA
477 MVA
247 MVA
Apollo
1920 MW
G
300 - 400 MW
G
450 MW
2075 MW (5x415MW)
HVAC Island
HVDC Island
155 MW
Movement of 5th HCB
unit to HVDC side

 MODULE 5
 Capacitor Commutated Converters

 MODULE 6
 Grid Power Flow Controllers

MODULE 7
Voltage Source Converters

HVDC-Light Configuration
(ABB)

 Control of voltage with reference to
connected network varies reactive power
(phasor diagram on the right)
 Control of phase angle varies active power
(phasor diagram on the left)
Transmission Grid Consulting

TGC
Transmission Grid
Consulting
• Turn valves on and off
• Independently control active and reactive
power
• Does not require active AC voltage
• Generate 3 phase voltage for load supply
• No harmonic filtering

 For reducing AC voltage to an appropriate
value for feeding to converters
◦ Higher voltages will require more devices to be
connected in series
 Usually of three-winding single phase type
◦ Easier for transportation
 Contribute to commutation reactance

 In VSC circuits no need for reactive
compensation
 Current harmonics directly related to PWM
frequency
 Reduced filter capacity compared to natural
commutated circuits

An indicator based on the observed ac voltage change at one inverter ac
bus for a small ac voltage change at another inverter bus provides degree
of interaction between two HVDC systems. This interaction factor is called
the Multi Infeed Interaction Factor (MIIF) and is defined mathematically as:
n
e
ne
V
V
MIIF


,
where:
ΔVe is the observed voltage change at bus e for a small
induced voltage change at bus n, ΔVn.

Inverter ac busses electrically far apart will have MIIF
values approaching zero.
MIIF values approaching unity indicate ac busses that are
very close.
MIIF values above about 0.15 indicate the possibility of
some degree of interaction.

The short circuit levels appearing at the respective inverter ac busses
cannot be considered as dedicated to the associated HVDC link but
rather must be shared amongst HVDC links in proximity.
)PdcxMIIF(Pdc
)QfSCC(
MIESCR
ji,jji
ii
i



MIESCR = multi-infeed definition of ESCR
SCCi = short circuit level present at the inverter bus.
Qfi = shunt compensation present.
Pdci = rated power of the HVDC link.
subscript j = refers to all other HVDC links in electrical proximity.
By this definition, an HVDC link may be embedded in a relatively weak MIESCR system,
say around two, whereas a conventional calculation might indicate that the system is
relatively strong at say four or five

There are four technical interaction
phenomena which are of greatest interest in
a multi-infeed network.
 Transient Over Voltage (TOV).
 Commutation failure including fault
recovery.
 Harmonic interaction.
 Power voltage instability and control
interaction.

Principles Control & Protection of HVDC Schemes

Principles Control & Protection of HVDC Schemes

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Editor's Notes