Review of Series Compensation
for Transmission Lines
FINAL
Prepared by
John Miller
Marc Brunet-Watson
Jed Leighfield
PSC North America
For
Southwest Power Pool
PSC reference
JU4715
Date
May 09, 2014
Proprietary & Confidential
Review of Series Compensation for Transmission Lines
Revision Table
Revision
1
2
2.1
Issue Date
Description
3/21/2014
4/16/2014
5/09/2014
Final Draft for submission to client
Final submission.
Final with corrections:
- general typos,
- fig 2.2 – show impact of increasing K
- fig 2.3 - removed FSC
- fig 6.3 – reversed light load and SIL curves
Reviewers
Name
Andrew Robbie
Brad Railing
Interest
Principal Engineer
Principal Engineer
Date
3/17/2014
4/14/2014
Approval
Name
Marc Brunet-Watson
Position
Power Networks Manager
PSC North America – Power Networks
Date
5/09/2014
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Review of Series Compensation for Transmission Lines
TABLE OF CONTENTS
1.......... Introduction ..........................................................................................7
2.......... Applicability of Series Compensation Technology ...........................9
2.1
General Review ...................................................................................... 9
2.1.1 Reducing Rotor Angle Separation................................................... 9
2.1.2 Voltage Regulation........................................................................ 11
2.2
Fixed Series Compensation (FSC) ...................................................... 13
2.3
Thyristor Controlled Series Compensation (TCSC)........................... 14
3.......... Sub-synchronous Interaction with Series Compensation ..............16
3.1
Key Section References ...................................................................... 16
3.2
Sub-synchronous Interaction.............................................................. 16
3.2.1 Fundamentals of Series Compensation and SSI ........................... 17
3.2.2 Classic SSR-TI and SSR-TA......................................................... 18
3.2.3 Induction Generator Effect (IGE)................................................... 19
3.2.4 SSCI Considerations for Wind Generation .................................... 20
3.3
Assessment of SSI in Series Compensated Networks ...................... 21
3.3.1 SSI Analysis.................................................................................. 21
3.3.2 Frequency Scan Screening ........................................................... 22
3.3.3 Eigenvalue Analysis ...................................................................... 23
3.3.4 Damping Torque Analysis ............................................................. 24
3.3.5 Detailed Time-Domain Analysis .................................................... 24
3.4
ERCOT – SSI Impact Study Framework for Wind Generators........... 25
4.......... SSI Mitigation and Protection Measures and Practical Applications26
4.1
Key Section References ...................................................................... 26
4.2
General Considerations and Definitions ............................................ 26
4.3
Network-Based Mitigation Measures .................................................. 27
4.3.1 Operational Procedures ................................................................ 27
4.3.2 Passive Filter Damping ................................................................. 27
4.3.3 Active Shunt Filter Damping (SVC or STATCOM)......................... 28
4.3.4 Active Series Damping (TCSC) and Shunt-Series Damping (UPFC)28
4.4
Generator-Based Mitigation Measures ............................................... 30
4.4.1 Passive Filter Damping ................................................................. 30
4.4.2 Active Filter Damping .................................................................... 31
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4.4.3 Supplementary Excitation Control Damping .................................. 31
4.4.4 Wind Turbine Control Damping ..................................................... 32
4.5
Network-Based Protection Measure ................................................... 33
4.5.1 Series Capacitor By-pass.............................................................. 33
4.6
Generator-Based Protection Measures .............................................. 33
4.6.1 SSI Relays .................................................................................... 33
5.......... Protection Schemes and Protection Relay Considerations ...........35
5.1
Key Section References ...................................................................... 35
5.2
General ................................................................................................. 35
5.3
Influence of Capacitor Protection ....................................................... 36
5.3.1 Voltage Inversion and Current Inversion ....................................... 36
5.3.2 Distance Protection – Measured Impedance................................. 38
5.3.3 Sub-synchronous Transient Signal Impacts .................................. 39
5.3.4 Adjacent Line Protection Impacts.................................................. 40
5.3.5 Other Impacts ............................................................................... 41
5.3.6 Automatic Reclosing for Series Compensated Transmission Lines41
5.4
Relay Protection Solutions.................................................................. 43
5.4.1 Advanced Relays for Series Compensation Application ................ 43
5.4.2 Protection Schemes...................................................................... 44
5.4.3 Protection Design and Performance Verification ........................... 45
5.5
Protection Case Studies ...................................................................... 46
5.5.1 BC Hydro ...................................................................................... 46
5.5.2 Hydro-Québec TransÉnergie (HQT).............................................. 49
5.5.3 Pacific Gas & Electric.................................................................... 50
6.......... Project Planning and Implementation Considerations ...................52
6.1
Key Section References ...................................................................... 52
6.2
Location of Series Compensation....................................................... 52
6.2.1 Mid-Line ........................................................................................ 53
6.2.2 Line Ends...................................................................................... 55
6.3
Modularity of Series Compensation ................................................... 57
6.4
Future Development of the Series Compensated Lines.................... 58
6.5
Operations and Maintenance Considerations.................................... 58
6.5.1 Operations and Reliability ............................................................. 59
7.......... Roadmap for Further Analysis ..........................................................60
7.1
Preliminary Design Stage Studies ...................................................... 60
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7.2
Steady state data for analyzing the active and reactive power flows and
voltage profiles in the system ............................................................. 60
7.3
Transient Stability Analysis................................................................. 61
7.4
Harmonics and Frequency Scans ....................................................... 61
7.5
Short-term Transient Voltage and Switching Studies ....................... 61
7.6
Small-signal Analysis .......................................................................... 62
8.......... References ..........................................................................................63
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TABLE OF FIGURES
Figure 2-1 - Power transfer equation
Figure 2-2 - Pmax with all lines in service
Figure 2-3 - Equal Area Criterion for a simple system
Figure 2-4 - Self-regulation of series compensation – 500 kV line, 300 miles long
Figure 2-5 – Effect of increasing compensation levels – 500 kV line, 300 miles long
Figure 2-6 - FSC main circuit components
Figure 2-7 - TCSC primary circuit components
Figure 3-1 - Generator turbine lumped mass model
Figure 3-2 - System electrical damping vs. torsional frequency (w/torsional modes) Source
[4]
Figure 4-1 - Passive filter in parallel with series capacitor
Figure 4-2 - Primary components of a TCSC
Figure 4-3 - TCSC impedance characteristic with SVR. Source: [2]
Figure 4-4 - DFIG Basic One-Line (Type-3)
Figure 5-1 - MOV protected series capacitor
Figure 5-2 - Voltage profile for a line side fault near a series capacitor (Forward Fault)
Figure 5-3 - Voltage profile for an adjacent line side fault near a series capacitor (Reverse
Fault)
Figure 5-4 - Example of current reversal condition in a SC line
Figure 5-5 - Impedance protection on a mid-point SC line
Figure 5-6 - Transmission line with remote line end SC
Figure 5-7 - Distance relay overreach due to sub-synchronous transient signals
Figure 5-8 - Zone 1 distance relay on SC line (solid) and adjacent line (dotted)
Figure 5-9 Main and back-up proctection schemes for line end and mid-line SC Source:
[33]
Figure 6-1 - Midline compensation at 33% and 66% of line length
Figure 6-2 - Mid-line compensation at 50% of line length
Figure 6-3 – Line voltage profile for mid-line series compensation
Figure 6-4 - Line end compensation, bus side shunt reactors
Figure 6-5 - Line end compensation, line side shunt reactors
Figure 6-6 – Line voltage profile for line-end series compensation
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1 Introduction
The High Priority Incremental Load Study (HPILS) was initiated in 2013 to develop a
long range plan that identified system reinforcements required in the Southwest Power
Pool (SPP) footprint in order to accommodate the unprecedented load growth that had
not been identified by previous planning studies. This rapid expansion of load was
brought about by an increase in the development of oil and gas fields, the firming of
previously interruptible loads and an increase in the forecast expansion of major
industrial loads.
As part of the HPILS process, initial screening of options by SPP staff suggested that
50% series compensation (SC) should be considered on the existing Tolk - Eddy
Country 345kV line as part of a potential EHV solution set to address the reliability needs
associated with large load additions in southeast New Mexico and west Texas. Due to
the fact that the proposed solution would introduce the first series compensated line in
the SPP footprint, significant concerns and uncertainties were expressed about the
merits and implications of adding SC to existing or planned EHV lines in SPP.
Series compensation has been in use in electrical networks worldwide since the 1950s.
It is a tried and true technology that continues to grow in popularity as an effective
means of resolving a number of network issues such as:

Improving transient system performance of the system following system
disturbances by reducing rotor angle difference between generators;

Compensating for reactive power losses in transmission lines to better regulate
system voltages;

Modifying and improving the balance of power flows between adjacent
transmission corridors by changing impedances, similar in effect to phaseshifting transformers and HVDC;

Damping of system oscillations when used with actively controlled Thyristor
Controlled Series Capacitors (see Section 2.3); and

Mitigating geomagnetic induced currents by blocking low frequency current flow.
The first two points are further discussed in Sections 2.1.1 and 2.1.2 whereas the
remainder are beyond the scope of this paper.
By addressing the above issues with less capital intensive solutions such as series
compensation, the capacity of existing transmission lines can be increased thereby
allowing for the deferral of major transmission line investments and the optimization of
total build out. This permits better management of risk through the preservation of right
of ways and corridors for future needs using an option that requires minimal permitting
and siting requirements. Overall asset utilization increases and losses are lowered.
Series compensation improves system reliability while minimizing the impact on rate
payers.
The various sub synchronous interactions between the network and the series capacitor
are well known phenomena and there are a variety of ways available to counter-act
them. The literature on the topic is extensive and the techniques are well documented
and their relative merits are discussed at length.
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Review of Series Compensation for Transmission Lines
This document seeks to provide a better understanding of the implications of adding
series compensation technology to the SPP network. The current status of the
technology is reviewed and recent advances in the techniques that deal with known
issues that affect the network are explored.
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Review of Series Compensation for Transmission Lines
2 Applicability of Series Compensation Technology
2.1 General Review
A general review of the applicability of series compensation shows that it serves to
increase power transfer under steady state and transient conditions, as well as
regulating voltage variations. A series compensation installation can be ‘Fixed’,
‘Thyristor Controlled’, or a combination of both.
2.1.1 Reducing Rotor Angle Separation
The classic power transfer equation, adapted to take account of the series capacitance,
XC, shows that as the level of compensation, K, increases, the power transfer increases
for a given angle δ. This is because capacitive impedance is negative with respect to an
inductance thereby reducing the overall impedance of the line. The equation and a
simplified network representation are shown in Figure 2-1 for illustrative purposes.
P
VS
ܲோ =
XL
VR
XC
ܸோ ܸௌ
ܸோ ܸௌ
sin ߜ =
sin ߜ
ܺ௅ − ܺ஼
ܺ௅(1 − ‫)ܭ‬
Figure 2-1 - Power transfer equation
From this, we see that when there are no changes to system impedance, the maximum
power that can be transferred occurs when the phase angle between the two ends
reaches 90o as demonstrated in Figure 2-2.
P
P=
PMAX
INCREASING COMPENSATION
(K = 50%)
VR VS
sin(δ)
XL (1-K)
PMAX
(K = 0%)
δMAX = 90˚
ܲ௠ ௔௫ =
ܸோ ܸௌ
ܸோ ܸௌ
=
ܺ௅ − ܺ஼
ܺ௅(1 − ‫)ܭ‬
Figure 2-2 - Pmax with all lines in service
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The effect of adding series compensation is shown in Figure 2-2 where for a same angle
δMAX, the theoretical maximum power transfer, PMAX, doubles when compensation level,
K, reaches 50%. Analogously, for a given power flow (say PMAX when K=0%), rotor
angle separation goes from 90o with no compensation to a much smaller value when
compensation is increased.
As faults occur and branch elements are switched out of service, the resulting changes
in network impedance cause imbalances between the electrical and mechanical torques
at play in the generator and an oscillatory behavior, best characterized by the swing
equation:
2‫݀ ܪ‬ଶߜ
= ܲ௠ ௘௖ − ܲ௘௟௘௖
߱ ௦ ݀‫ݐ‬ଶ
where H is generator inertia, ωs = 2 π fs is synchronous angular speed, Pmec is the
mechanical power generated by the turbine, Pelec is the electrical power generated by the
alternator that responds to the system demand. During steady state, when the system
frequency is at its nominal 60 Hz, both the mechanical and electrical power are equal
and the machine continues to spin at synchronous speeds.
VS
Pmec
Pelec
VR
FAULT
Pelec
Pelec both lines in service
Pelec after fault cleared
(one line out)
A2
Pmec
Pelec during fault
A1
δO
δCL
δMAX
δ
Figure 2-3 - Equal Area Criterion for a simple system
Prior to fault inception, the generator in Figure 2-3 has angle δo and is generating Pmec
on the Pelec curve with both lines in service. At the instant of the fault, the impedance
seen by the generator reduces and very little active power is generated due to the fault
being situated between the load and the generator. The generator’s operating point is
now where δo crosses the curve of P during the fault. Mechanical power from the
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turbine remains constant1 and the sudden drop in electrical power results in an
imbalance causing the rotor to speed up. The angle between rotor field and network
field increases and the generator’s operating point moves along P for the duration of the
fault until the angle reaches δCL at which time the line’s protective relays clear the fault
by disconnecting the line. Once the fault has been cleared, the generator changes its
operating point by moving up to the graph of P after the fault is cleared. Since the
impedance of the single line is double the impedance of the two lines in parallel, this
curve has a smaller amplitude than the initial but greater than during the fault. Electrical
power is now greater than mechanical power produced by the turbine and the rotor
begins to decelerate until eventually coming to rest where the electrical power is equal to
the mechanical power of the turbine.
The area identified as A1 in Figure 2-3 corresponds to the acceleration energy absorbed
by the rotor during the fault. The area A2 corresponds to the decelerating energy that
the rotor can return to the network to return to a stable operating point.
The Equal Area Criterion states that the generator will return to a stable operating point
if A2 ≥ A1. This is equivalent to saying that the decelerating energy available to the rotor
is at least equal to the accelerating energy absorbed during the fault.
The relative sizes of A1 and A2 are determined by:

The initial phase angle, δo ;

The protection clearing time that determines δCL ; and

The before and after impedances that determine the amplitude of the power
relationship.
2.1.2 Voltage Regulation
Voltage stability is improved due to the self-regulation characteristic of series capacitors.
Contrary to shunt devices where reactive output is a function of the inverse square of the
voltage change, the reactive power output of series elements increases with the square
of the current. As transfer increases across a transmission line, reactive losses caused
by the inductive nature or transmission lines are partially offset by the increase in
reactive power generated by the capacitor. Consider Figure 2-4, the reactive power
balance for a 500 kV line of 300 miles in length.
The maximum power transfer is increased for the series compensated line due to the
increased availability of reactive power to support local voltage as flow increases. Selfregulation also means that lines subject to sudden load variations due to nearby loads or
generators switching on or off will have better regulation2.
1
In the time frames where protective devices operate (~ 50 – 200 ms), governor action is
negligible and the turbine output can be said to remain constant.
2 Voltage regulation of a line generally refers to the tendency of the voltage at the receiving end to
vary for given changes in flow.
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Figure 2-4 - Self-regulation of series compensation – 500 kV line, 300 miles long
As compensation levels, K, increase the reactive output of the series capacitor increases
and the voltage regulation across the line is improved as shown in Figure 2-5.
VR / VS
1.1
1.0
NOMINAL
VOLTAGE
RANGE
0.9
P
Figure 2-5 – Effect of increasing compensation levels – 500 kV line, 300 miles long
The range of power transfer for which the voltage stays within the normal range
increases as the level of compensation increases. It must be noted that the Critical
Voltage, the point at which voltage will collapse for any increase in transfer, also
increases considerably as compensation levels increases. Post contingent voltages in
compensated systems must be verified to ensure that a voltage collapse scenario has
not been introduced along with the series compensation. This is particularly true for
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situations where unplanned outages result in unusually high flows across compensated
lines.
2.2 Fixed Series Compensation (FSC)
A fixed series compensation installation consists of a parallel combination of capacitors,
over-voltage protection, and a bypass breaker, which are all installed on an elevated
platform insulated to the line voltage. The FSC main circuit components are shown in
Figure 2-6. The capacitor bank is usually rated to line currents associated with normal
peak power flow and power swing conditions. Rating the capacitor banks to current and
voltage levels associated with fault conditions is generally not considered economical
and over voltage protection is provided to limit the voltage across the capacitor during
fault conditions. The over voltage protection typically consists of two parts:

A zinc oxide varistor (MOV) with highly non-linear characteristics that conducts
negligible current during normal operation and conducts freely once the voltage
across it reaches the protection level thereby bypassing the capacitor bank. The
MOV is built up of individual MOV blocks placed in series to obtain the desired
voltage protection level and in parallel to be to absorb the desired energy during
faults. If the fault is cleared without the ratings of the MOV being exceeded, the
MOV will stop conducting once the voltage across it drops below the protection level
and the capacitor will return to normal operating conditions.
 A fast protective device (FPD) that can be triggered for certain fault conditions such
as faults on compensated line segments or for extreme faults when the energy
absorbed by the MOV exceeds rated values. Fast protective devices have typically
consisted of triggered air gaps although new technologies are being introduced that
use arc-plasma injectors in parallel with a fast contact to avoid the difficulty of
correctly distancing and maintaining the electrodes in the air gap.
The bypass breaker is normally in the open position and can be used to switch the series
capacitor in or out during planned operations. It also serves to bypass the series
capacitor, MOV and FPD if the fault is not cleared within a pre-determined time. It must
be able to carry the rated MOV voltage as well as the maximum capacitor discharge
current. Bypass breakers are specially designed and rated to withstand the higher
transient frequency and interrupting currents when bypassing a series capacitor. Bypass
breakers are normally SF6 puffer type with controls at ground level.
A damping circuit - usually an air core reactor - is placed in series with the FPD and the
by-pass breaker to limit and dampen capacitor discharge currents when the FPD triggers
or the bypass breaker is closed.
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Series Capacitor
MOV
Damping
Reactor
FPD
Bypass Swit ch
Fixed Series Compensation
Figure 2-6 - FSC main circuit components
2.3 Thyristor Controlled Series Compensation (TCSC)
A thyristor controlled series compensation installation typically consists of two modules
connected in series:


A fixed series compensation module (as described above), and
A module consisting of a series capacitor in parallel with a thyristor controlled, aircore reactor.
As with the FSC, the TCSC is platform mounted and insulated at line voltage. A TCSC
installation can be green field or thyristors can be added to control part or all of an
existing FSC installation [2].
When the thyristor gate is blocked, full current flows through the capacitance and the line
is fully compensated. When the thyristor gate is fully conducting, the capacitor is
effectively bypassed. If the valves are gated for partial conductance, it is possible to
smoothly vary the impedance of the TCSC.
Over-voltage protection is assured by the connection of an MOV across the capacitor. A
bypass breaker or disconnect is generally included to allow for maintenance and better
over-voltage protection.
Depending on the network requirements TCSC installations may be 100% variable
although most typically have a fixed level of compensation combined with a variable
level of compensation as shown in Figure 2-7. This allows the cost to be optimized by
only controlling the series capacitance that provides reliability or other benefits. The
controlled part can be scaled as required.
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Series Capacitor
Series Capacitor
MOV
Reactor
Damping
Reactor
Thyristors
MOV
FPD
Damping
Reactor
Bypass Swit ch
Fixed Series Compensation
FPD
Bypass Swit ch
Thyristor Controlled Series Compensation
Figure 2-7 - TCSC primary circuit components
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3 Sub-synchronous Interaction with Series Compensation
3.1 Key Section References
For gaining more in-depth knowledge on the subject matter in this Section 3, the
following primary references are suggested:
[11] Anderson and Farmer. (1996). “Series Compensation of Power Systems”.
Encinitas, CA: PBLSH, Inc.
[19] Farmer, Agrawal and Ramey. (2006). “Power System Dynamic Interaction with
Turbine Generators”, Taylor and Francis Group, LLC.
http://www.beknowledge.com/wp-content/uploads/2010/09/327.pdf
[22b] IEEE. (1992). “Reader’s Guide to Subsynchronous Resonance”. Transactions on
Power Systems, Vol. 7, No. 1, 0885-8950/92: IEEE
Additional subject references are indicated in square brackets throughout the section
with the complete paper reference list presented in Section 8.
3.2 Sub-synchronous Interaction
When series compensation of transmission is introduced into the power network there is
potential for various forms of sub-synchronous interaction (SSI) with other network
components. SSI can lead to sub-synchronous oscillations (SSO), which if not
inherently damped, in turn, could lead to unpredicted outages and possibly damage to
network equipment.
The subject of SSI is not new to the electric power transmission industry as SSI events
have occurred and the associated phenomena as a result have been well-studied. As a
result, SSI study techniques, risk assessment, and preventative measures have been
developed as will be described in Section 3. Some actual SSI events will also be
presented.
SSI is a general term used to in place of more specific forms of sub-synchronous
conditions that have been defined for electric power industry. These definitions are
provided below in a structure that correlates the various types of SSI. [4][22b]
Sub-synchronous Interaction (SSI) – Is a condition where two of more parts of the
electrical system exchange energy at one or more natural frequencies below the
fundamental frequency of the power system. The most prominent forms of SSI include:
1. Sub-synchronous Resonance (SSR) – Is a condition where an electric power
system, most often with series compensated transmission lines, exchanges
energy with a turbo-generator at one or more of the natural frequencies below the
fundamental frequency of the power system. The three types of SSR are:
a. Torsional Interaction (SSR TI) – A condition when the fundamental
complement of electric system natural frequency (i.e., fundamental –
natural frequency) of a series compensated electric power system is at or
close to one of the mechanical torsional frequencies of the turbogenerator shaft system. If the rotor torsional frequency torque developed
by this condition is greater than the inherent mechanical damping, the
overall electro-mechanical system becomes excited. This is a classic
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SSR condition which was defined following a damaging oscillatory events
involving a turbine-generator (Mohave Generating Station) and a series
compensated transmission line back in 1970 and 1971 in Nevada, USA.
b. Self-excitation due to Induction Generator Effect (IGE) – A condition,
independent of the generator shaft torsional modes, where the combined
generator and electric power system results in a negative effective rotor
resistance at a natural frequency below fundamental frequency. If the
negative rotor resistance is greater than the apparent stator plus network
resistance, self-excited, sub-synchronous current and electromagnetic
torque in the machine can result. This phenomenon is a purely electric
resonance condition.
c. Torque Amplification (SSR TA) – A condition where transient torques
amplify turbo-generator shaft system stress resulting from subsynchronous currents due to a major disturbances in the power network.
These torques are proportional to the magnitude of sub-synchronous
current, so transient current due to a short circuit and fault clearing can
produce large torques, particularly if the transient current’s frequency
complements a shaft torsional mode.
2. Sub-synchronous Control Interaction (SSCI) – An electric power system
condition where a power electronic device (such as HVDC, SVC, STATCOM,
wind turbine control etc.) interacts, at a natural frequency, with the electric power
network containing near-by series compensated transmission.
3. Sub-synchronous Torsional Interaction (SSTI) – A condition involving control
interactions between a power electronic device (such as an HVDC link, SVC,
wind turbine etc.) and the mechanical mass system of a turbo-generator.
While SSTI is not associated with series compensation, the definition is provided above
for completeness and differentiation from the other SSI forms that are correlated with
series compensation. SSTI is not further addressed in this paper.
The term SSI will be used within this document unless the subject matter is only relevant
to a more specific type.
3.2.1 Fundamentals of Series Compensation and SSI
Series compensation is designed to partially compensate for the inductive reactance of a
transmission line to increase power transfer capability and system stability.
Compensation levels typically range from 20% to 80%. Consequently, the reactance
due to the series capacitor (XC) will always be less than the inductive reactance of the
transmission line (XL).
Whenever capacitance (C) is introduced into an electric system that is primarily inductive
(L) and resistive (R) in nature, new natural electrical frequencies and resonant conditions
result. In general terms, the natural frequency (f n) is a function for the R-L-C components
of the system, and when R is small the natural frequency can be approximated by:
f୬ =
1
√‫ܥܮ‬
which can also be expressed in terms of reactance as:
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fn = fo ∗ ට
௑௖
௑ಽ
where fo is the fundamental frequency of the system (60 Hz in the United States).
Consequently, since XC will always be less than XL for a series compensated network,
the natural frequencies will be less than the 60 Hz fundamental frequency. As the
amount of series compensation is increased, the natural system frequency approaches
the fundamental frequency.
3.2.2 Classic SSR-TI and SSR-TA
As discussed above, series compensation introduces new natural frequencies in the
transmission network that are below the system’s fundamental frequency. When
currents at these natural frequencies flow through the stator of a generator, they create a
rotating MMF that induces currents in the rotor. The induced rotor current will have a
sub-synchronous frequency that is fundamental complement of the stator current
frequency. For example, if a generator and series compensated network formed a
resonant electrical circuit with a natural frequency of 40 Hz, the sub-synchronous
frequency induced into the generator shaft system would be the fundamental
complement: 60-40 Hz, or 20 Hz. [22b]
3.2.2.1 Generation Mechanical Modes of Oscillation
A generator mechanical system can have a complex mechanical structure and often
consists of multiple masses coupled on a shaft system such as high pressure turbine,
low pressure turbine, generator, and exciter as shown in Figure 3-1.
Figure 3-1 - Generator turbine lumped mass model
The system can be represented as a lumped parameter model of rotating masses
connected by torsional spring segments, and mechanical dashpots on and between the
masses to represent any known inherent mechanical damping.
From this model, the torsional modes can be determined through eigenvalue analysis.
The torsional modes express the natural frequency of oscillation of one mass against
one or more of the other masses (fm). If a generator has four masses as shown above,
there will be four modes of oscillation:

Mode 0 is typically 1-2 Hz, all masses move together, typically used in generator
models for transient simulation programs such as PSS/E using a single, lumped
inertia (H).
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
Modes 1-3 involve oscillations between the masses; the more masses that
participate in a mode, the lower the frequency. Typically, these modes will all be
below the fundamental 60 Hz frequency.[23]
Only the torsional modes of oscillation that involve a participation with the generator are
of concern with regard to SSI.
3.2.2.2 Generator Electro-Mechanical Energy Exchange
In a sub-synchronous resonance condition, exchange of energy takes place in an
oscillatory form. In the case of SSR-TI, this exchange of energy and torsional interaction
occurs between the turbine-generator electro-mechanical system and the electric power
network. As discussed in Section 4.4.1, the natural frequency (f n) of stator side currents
is transformed into the rotor windings at a fundamental complement frequency (60 – f n).
Energy can readily transfer between the electrical system and the mechanical system at
this sub-synchronous frequency (60 - fn). If (60 - fn) is at or near one of the generator
mechanical torsional modes (fm), this condition can potentially destabilize the mechanical
torsional mode if there is insufficient mechanical dampening to overcome the developed
electro-magnetic torque. As the rotor oscillates at the sub-synchronous torsional mode,
voltage is induced into the stator, which sustains the sub-synchronous torque. This
combined electro-magnetic-mechanical system is then said to be self-excited.
This is the classic SSR-TI phenomenon that has historically been a concern for highpower steam generators. A generator that is connected electrically-close to a highly
series-compensated transmission network can be at considerable risk for un-damped
sub-synchronous oscillations. The risk is highest when a generator is radially connected
compensated transmission line, however, risk also exists for generators in a more
interconnected and meshed network that contains series compensation, although to a
lesser degree.
The fundamentals behind SSR-TA are the same as described above for SSR-TI; they
both involve the oscillatory exchange in energy between the electrical network and the
electro-mechanical characteristics of a generator. SSR-TA occurs when subsynchronous transients following major network disturbances have a frequency near the
fundamental complement of a generator mechanical mode. SSR-TA conditions can lead
to generator shaft oscillations with high amplitude and prolonged duration. Even though
these oscillations may be positively damped, generator shaft segments can be subject to
increased stress, and accelerated loss of life due to SSR-TA. As with SSR-TI,
generators that are connected radially, or near radially to a series compensation
transmission line are more at risk for adverse impacts from SSR-TA.
3.2.3 Induction Generator Effect (IGE)
As explained in Section 3.2, IGE is a self-excitation condition involving the electrical
characteristics of the generator and the series compensated network. Self-excitation due
to IGE could result in excessive voltages and currents on the network, and possible
equipment damage or accelerated fatigue. [22b]
For thermal generators, pole-face amortisseur windings can be applied as an effective
countermeasure to IGE. [22b]
IGE is a moderate concern with wind generation located in the vicinity of series
compensated transmission lines. Electrical self-excitation and resonance with series
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compensation is of most concern during the generator start-up sequence or during
crowbar action in a Type-3 (rotor double-fed through converter). This is because an IGE
condition becomes less damped (more likely) when the rotor resistance is increased. [4]
Crowbar action involves switching in a resistor on rotor side of a Type-3 wind generator
to limit overvoltage within the converter. Refer to Figure 4-4 for a basic one-line
arrangement of a DFIG (Type-3) wind generator.
3.2.4 SSCI Considerations for Wind Generation
An event that initiated SSI between wind generators and a series compensated
transmission line on the ERCOT grid in October 2009 led to a nearly 2 per-unit
overvoltage which damaged wind generator rotor side protection circuits. The SSI was
initiated when wind generator became radially connected to the transmission grid
through a series compensated line. The SSI condition lasted only 1.5 seconds before
being mitigated by a protective action which by-passed the series capacitor. [20][30][36]
Prior to this event, it was generally accepted that there was minimal risk of SSI involving
wind generation. As a consequence, this event sparked considerable research by
various industry specialists, wind turbine vendors, and academics, especially when
considering the increasing application of large scale wind farms and series
compensation.
Detailed analysis of event records and post-event simulations determined that the SSI
was due to neither classical SSR nor SSTI. Rather, it was determined that the exchange
in energy between the wind turbines and the series capacitor was due to an electricalside resonance involving the wind turbine converter and controls. This form of SSI and
been specifically labeled Sub-synchronous Control Interaction (SSCI).
As SSCI involves only the electrical characteristics of the wind turbine and the network,
oscillations can develop extremely fast. In the 2009 ERCOT event, it is estimated that
oscillations commenced within 200 ms from initiation of the event, and damage likely
occurred within the next few hundred milliseconds. [20] This is unlike an SSI event
involving machine mechanical interaction where oscillations typically develop over
seconds rather than msec. Fortunately, there were no mechanical shaft torsional modes
near the frequency of SSCI or catastrophic damage to the wind machines could have
resulted.
SSCI with wind turbines involves the associated converter and control system and as
such, only Type-3 (rotor double-fed through converter) and Type-4 (full converter directly
connected to stator) wind turbines are at risk for SSCI. Type-1(squirrel cage) and
Type-2 (wound rotor) wind turbines do not have converters, so they are immune to SSCI,
however, there is a moderate risk for SSR-TI and IGE when radially connected to series
compensated line. [4][27]
Type-3 wind generators are more at risk than Type-4 wind generators based on our
research. In some cases the turbine vendor claims their Type-3 converter control
system can be tuned to mitigate SSCI. [27] Conclusions in a study by Siemens indicate
that their Type-4 wind turbine can be designed to be immune to SSCI over a wide range
of sub-synchronous frequencies and are suitable to be applied in series compensated
networks with proper control tuning. [31]
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Because of the non-linear nature of the converter and controls of Type-3 and Type-4
wind generators, special care must be taken in their modeling for SSI assessment. This
is further emphasized in Sections 3.3 and 7.
3.3 Assessment of SSI in Series Compensated Networks
The previous section presented the theory and consequences of SSI with particular
focus on interactions with series compensation. This section highlights the
methodologies and tools that are available to assess the potential for SSI within series
compensated networks.
3.3.1 SSI Analysis
Depending on the form of SSI that is being evaluated, different study techniques are
required. For certain forms of SSI, screening techniques can be used to make the
overall process more manageable. Results of the screening analysis can be used to
determine if more detailed analysis is required.
Classic SSR, IGE and SSCI can be initiated from a minor perturbation, and thus small
signal, linear analysis models and techniques can be applied. Eigenvalue analysis is a
technique often applied to understand the natural frequencies of oscillation and the
associated damping of each oscillatory mode. A frequency scan method can also be
used to assess the potential for SSI. When non-linear system components and control
systems such as control strategies for power-electronic based devices are involved,
damping torque analysis methods in a time-domain-based system model may be most
suitable.
SSR TA can result as in response to a major network disturbance where system nonlinear characteristics can influence the condition. Consequently, more sophisticated
modelling and time-domain, EMT-type, simulation programs are used to evaluate
potential SSI TA.
Information from the generator manufacturer on the generator impedance as a function
of sub-synchronous frequency, as well as information on the torsional characteristic of
the machine can be very beneficial for SSI analysis. [4]
It should also be noted that if turbine-generators are connected to the electric network at
the same point of interconnection and possess the same characteristics, the units can be
lumped together for the analysis. The total generation plant MVA should be used as the
basis for the per unit representation. This aggregation technique holds true for both
large turbine generators as well as wind farms with common wind generation units.
Depending on the network configuration, the level of series compensation, and the
number of transmission lines containing series compensation, the quantity and subsynchronous level of natural frequencies will change. Comprehensive analysis must be
performed to evaluate the potential for SSI in all credible network conditions.
Combinations of the following system conditions should be considered in the overall SSI
analysis:

All credible network line outage conditions.

Different levels of series compensation, including the outage of one or more
series capacitor segments.
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
Outage of any near-by HVDC, SVC or other power electronic based devices that
may influence system damping.

Low and high generation output levels. This can be influential in the SSI
evaluation associated with large scale turbo-generators and wind generation.

Future planned changes to the network as practical.
Depending on the nature of the system under study, the above variable system
conditions can escalate to hundreds if not thousands of combinations to be evaluated.
However, SSI issues typically manifest only when generation plant (e.g. wind generators
or conventional generators), are part of a network that becomes radial or nearly radial
with a series capacitor installation. These situations are generally the most critical ones.
The sections below provide screening techniques that can be employed to make the
evaluation process more manageable and practical.
3.3.2 Frequency Scan Screening
The frequency scan screening process involves the following steps for each potential
network configuration and level of series compensation:
1. From behind the generator in question looking out into the interconnected
network, scan the network and calculate the apparent impedance for frequencies
from 0 to 60 Hz.
2. Determine the equivalent reactance and resistance over the range of frequency
to evaluate the potential for IGE. A near zero reactance coincident with a
negative resistance indicates the high probability of IGE.
3. For classic SSR evaluation, the calculated impedance and electrical damping
coefficient should be reflected to the rotor reference frame and compared to the
torsional modes of the turbine-generator as shown in Figure 3-2.
4. For SSCI with wind turbines, the calculated impedance and the electrical
damping characteristics are compared to the modes of the wind turbine including
its electric power electronic-based control system.
The screening should start with system conditions where the generation in question is
radially or near-radially connected to a series compensated transmission line (i.e.,
perhaps several contingency levels from the normal all-lines-in base condition, up to N5) as these would conditions would generally pose the most of SSI. This approach could
rule out the need to evaluate network conditions with more elements in-service,
depending on the results associated with the more onerous network conditions.
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Figure 3-2 - System electrical damping vs. torsional frequency (w/torsional modes)
Source [4]
For SSI screening associated with wind generation (i.e., Type 3 and Type 4), [12]
suggests the frequency scans should be performed separately for the electrical network
and the generator. The scans should be performed from the point of interconnection
(POI) looking out into the network, and looking back into the generator independently.
Since the wind generators with active power electronic devices are highly non-linear, the
frequency scan method used on the generator must take this factor into account. The
use of a white noise excitation technique is suggested in [12] for the turbine side
frequency scan. System resonance points and negative damping indicators can be
deduced from the pair of frequency scans to assess the possibility of SSR and SSCI.
3.3.3 Eigenvalue Analysis
Eigenvalue analysis involves modeling the electrical network, generators, and controls of
interest in a common linear system of differential equations. The linear system is used
to closely predict the change in system states due to a small perturbation. This method
can provide additional information on system performance beyond the screening
frequency screening analysis. The results provide both frequency and associated
damping for each identified mode of oscillation for the combined system.
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For classic SSR TI, the generator mechanical system must be modeled along with the
generator electrical representation. [34] For the study of SSCI, the wind turbine converter
and control system must also be represented in detail.
This method is more complex and computationally intensive as it requires more detailed
system models and a separate linear model must be established for each network
configuration to be analyzed.
3.3.4 Damping Torque Analysis
Damping torque analysis can also be used to predict the frequency of sub-synchronous
oscillations and the associated electrical damping through the application of time-domain
simulation. The approach does not require the modelling of the mechanical
characteristics of system generation; only the electrical representation is necessary
within an EMT-type digital simulation or real-time simulation program.
In this method, a small sinusoidal change in generator speed is used to determine the
resulting change in electrical torque at the generator. The resulting change in electrical
torque is simulated and if the electrical torque counters the machine speed it provides
positive damping and vice-versa. The complex electrical torque response to the small
speed perturbation can be used to calculate the electrical damping at the frequency of
the injected perturbation signal. In general terms, the real part of the transfer function (or
system apparent impedance) between speed change and the electrical torque
represents the electrical damping factor. This damping torque analysis is performed over
the full range of sub-synchronous frequencies to produce a damping factor curve versus
frequency as shown in Figure 3-2.
Even though this is a small-signal analysis method, the system model can be non-linear
and represent system control strategies such as controls associated with SVC, HVDC
and TSCS, and thus is practical for evaluating SSTI. This offers an advantage over
eigenvalue analysis methods presented previously.
3.3.5 Detailed Time-Domain Analysis
Time-domain analysis requires even more computational power as it involves
determination of the system state with time though numerical integration of a system set
of differential equations represented in a EMT-type digital software program or real-time
simulator. As noted previously, the technique is useful for the evaluation of SSR-TA as
system non-linearities are realized in response to a major network disturbance. Both
electrical and mechanical dynamic characteristics are typically modelled, and the
generator torque response can be simulated for large network disturbances and
protective actions. [42] In the condition of SSR-TA, the response over time would show
torque amplification and any undesirable oscillatory behavior.
Detailed time-domain analysis has the advantage over linear analysis techniques as the
overall system response can be simulated with account for control actions and limits,
protection system actions, and unbalanced system conditions. The drawback with the
method is that system set-up and simulations can be very time consuming and often
times impractical. This is especially true when multiple combinations of network
topologies and system conditions are to be analyzed. Accordingly, screening techniques
should first be performed to determine those system conditions that should be evaluated
using detailed time-domain analysis. [42]
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The effectiveness of any mitigation measures (see Section 4) designed with regard to
SSI can also be evaluated through detailed time-domain analysis.
3.4 ERCOT – SSI Impact Study Framework for Wind Generators
ERCOT has established special requirements for the interconnection of wind generation
in the generator interconnection process considering the existing and planned series
compensated transmission lines in their region. ERCOT employs a multi-phase
approach to their interconnection studies including a Screening Study, Full
Interconnection Study, followed by and Interconnection Agreement. [17]
For a generator project to be approved in ERCOT, it must be demonstrated that the
project meets ERCOT’s technical grid compliance requirements, which include SSI per
Section 5 of the ERCOT Planning Guide.
The risk of SSI is first evaluated in the Screening Study phase through the use of
frequency scan methodology. Based on the outcome of the SSI screening study, more
detailed SSI analysis will performed during the Full Interconnection Study phase of the
project interconnection process.
The model used for the SSI screening will be prepared using the appropriate ERCOT
power flow base case. An equivalent model will be created in PSCAD for the screening
analysis that extends, as a minimum, to include local series compensated transmission
lines. In general, detail would be maintained for five to six buses away from the POI.
Reference [6] indicates that the level of buses in the equivalent can influence the
frequency scan results and suggests that the GSU should be included in the model as it
can have a significant influence on electrical damping. Looking out into the network from
the behind the GSU at the POI, impedance versus frequency plots are produced under
various system conditions to evaluate the risk of SSI. ERCOT requires the evaluation of
both Critical and Credible Contingencies and various levels of series compensation as
may be relevant to the analysis:

Credible Contingencies – as defined in the ERCOT Planning Guides.

Critical Contingencies – outage of transmission elements to achieve a radial or
near radial topology between the POI and a series compensated line. Generally
up to the N-5 level of contingency is the practical limit for selection.
The combination of network topology that provides the most risk of SSI is determined
from the frequency scans. Interpretation of the frequency scans will show worst case
conditions through the identification of significant apparent dips in the apparent
reactance, negative values of resistance, and negative values of resistance coincident
with zero crossings of reactance. From the screening analysis, the system conditions
and range of sub-synchronous frequencies of concern can be identified for detailed SSI
studies. [12][35]
For the detailed SSI studies, ERCOT will provide the appropriate base PSCAD model
and list of contingencies that should be studied. ERCOT has set the proximity criteria
limit to N-5 from the POI for the detailed SSI studies [35]. The developer is required to
introduce a detailed representation of the generator in the PSCAD model. For a wind
farm, this can be an appropriately aggregated representation. The developer is
responsible for performing the detailed SSI analysis using PSCAD or equivalent, and for
providing results to ERCOT for review and approval.
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4 SSI Mitigation and Protection Measures and Practical
Applications
4.1 Key Section References
For gaining more in-depth knowledge on the subject matter in this Section 4, the
following primary references are suggested:
[11]
Anderson and Farmer. (1996). “Series Compensation of Power Systems”.
Encinitas, CA: PBLSH, Inc.
[19]
Farmer, Agrawal and Ramey. (2006). “Power System Dynamic Interaction with
Turbine Generators”, Taylor and Francis Group, LLC. http://www.beknowledge.com/wpcontent/uploads/2010/09/327.pdf
[22b] IEEE. (1992). “Reader’s Guide to Subsynchronous Resonance”. Transactions on
Power Systems, Vol. 7, No. 1, 0885-8950/92: IEEE
Additional subject references are indicated in square brackets throughout the section
with the complete paper reference list presented in Section 8
4.2 General Considerations and Definitions
Consideration must be given to the potential for SSI whenever series compensation is
being considered to improve that transfer capacity of a network. The ability to analyze
and mitigate SSI has been clearly demonstrated over the last 30 years. Various
countermeasures for SSI control have been researched, developed and successfully
applied and advances in mitigation and protection measures are continuing.
SSI risk assessment and management is not a simple task as the risk level is generally
low, however, the consequence of an SSI event can be significant. The risk of SSI and
the consequence of an event from both a generator and network reliability perspective
should factor into the appropriate level of mitigation and/or protective measures to be
applied. Other factors that will dictate the preferred measures include:

Effectiveness of various measures

Initial capital cost and O&M costs

Responsibility for implementation and allocation of costs, and O&M

Future plans for additional generation and/or series compensation

Consequence of operating restrictions if measures are not implemented
beyond operation procedures
There are several measures that can be applied to mitigate the potential for SSI and
protect equipment from exposure or damage from SSI. The measures can be classified
as follows:
Mitigation Measures (or Countermeasure) – Preventative measures implemented if
the risk of SSI is probable for credible system configurations.
Protection Measures – Measures implemented to protect equipment due to the
detection of an SSO conditions. These can be applied as a back-up to mitigation
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measures. Protection may be the only measure implemented if SSI is only likely as a
result of contingencies beyond the credible set.
Furthermore, the mitigation and/or protective measures may be sub-classified as:
Network-based – measures applied in the network. For example, an SSI
damping scheme installed at the series capacitor would be a Network-based
Mitigation Measure. This can also be designated as an “outside-the-fence”
measure as it would be applied on the network beyond the generator
developer/owner’s asset boundary.
Generator-based – measures applied at the generator or at the generator POI.
For example, a torsional relay installed on a generator would be a Generatorbased Protection Measure. This can also be considered an “inside the fence”
measure.
The subsequent sections present various forms of SSI mitigation and protection
measures, and based on our findings, summarize some of the basic pros and cons of
each. Focus is on those measures that have been applied in the industry, however,
some others that appear more commonly in literature are described, even though we
were not always able to confirm an actual application.
4.3 Network-Based Mitigation Measures
4.3.1 Operational Procedures
One countermeasure for dealing with SSI is to alter the network configuration or
generation dispatch to limit the risk of SSI. This may involve restricting the operation of
the generator under certain configurations that pose a risk to the unit(s).
Another operating procedure may involve the by-pass or reduction of the level of series
compensation under certain conditions to mitigate the chance of an SSI condition. For
example under light load conditions when system damping is low it may be
advantageous to simply bypass the series compensation to mitigate a possible SSI
condition, as the series compensation is not needed at low power transfers.
Overall, implementing appropriate operational procedures may be an acceptable and
cost effective process if the system is not complex and where network conditions that
pose a high risk are unlikely (i.e., several levels of contingency), or where the SSI
condition only manifests during light load or low power transfers.
4.3.2 Passive Filter Damping
As explained in Section 3.2.1 the risk of SSI in a series compensated network stems
from the natural resonant condition of the network. From the fundamental standpoint, a
series compensated line can form a series resonant R-L-C circuit which at a certain
frequency has very low apparent impedance. This condition cab be countered by adding
additional passive elements to the network with the appropriate impedance as a function
of frequency. This approach can be used to effectively dampen the SSI and can be
accomplished with either a shunt filter, series filter or a combination of the two. A
properly designed series filter will provide the most influence considering the SSI risk is
due to a series resonant condition of the network.
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The addition of a 60-Hz blocking filter in parallel with series capacitor is one means of
series passive filtering. The primary components of such a passive blocking filter is
shown in Figure 4-1 below. The filter would block 60-Hz currents while effectively bypassing the capacitor for lower frequency currents.
This would be a fairly expensive option as the ratings of the elements would have to be
high due to short circuit exposure, and protections (MOV) would likely be required to
control the voltage across the capacitive elements of the blocking filter.
Series Capacitor
I line
XC
Ic
I filter
XCF
XLF
Passive Filter
Figure 4-1 - Passive filter in parallel with series capacitor
4.3.3 Active Shunt Filter Damping (SVC or STATCOM)
A network connected SVC or STATCOM can be designed and tuned to actively mitigate
SSI through the use of a supplemental damping control. The advantage of an active
device is that it can be effective independent of the network configuration or level of
series compensation. The input to the supplemental control can be generator speed,
local voltage, or line current to provide damping by modulating the reactive current
reference of the STATCOM. While this approach may be somewhat effective out on the
network in providing positive damping over a range of sub-synchronous frequencies, it is
generally more effective if applied close to specific generator(s). Various control
strategies have been designed to mitigate SSI through the use of a STATCOM. Refer to
Section 4.4.2 for further discussion.
If an SVC or STATCOM is already present on the network to provide AC voltage control,
Var compensation, and/or power system stability enhancement, the addition of a
supplemental damping controller may prove beneficial depending on its location relative
to generators.
These active devices will produce harmonics that must be controlled in accordance with
applicable harmonic standards. The capital cost and O&M cost of a new SVC or
STATCOM installation is appreciable.
4.3.4 Active Series Damping (TCSC) and Shunt-Series Damping (UPFC)
4.3.4.1 Thyristor-Controlled Series Compensation (TCSC)
Through the application of a TCSC, power flow over a transmission line can be
dynamically controlled, providing improved power system stability and transfer capacity.
Furthermore, through the introduction of a specific thyristor angle control method, the
effective reactance of a TCSC can by modulated to effectively mitigate SSI.
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XC
Iline
Iloop
XL
THYRISTOR
CONTROL
Figure 4-2 - Primary components of a TCSC
As shown in Figure 4.2, the main circuit components of a TCSC includes a capacitor in
parallel with a reactor that is controlled with opposite-poled thyristors. There are three
basic operating modes:
1. Blocked Mode – the thyristor is not fired and the reactor is therefore blocked.
The TCSC then appears as a pure capacitive reactance based on the series
capacitor.
2. By-passed Mode – the thyristor is controlled to conduct current continuously,
and the apparent impedance becomes inductive.
3. Controlled Mode – the thyristor path is partially conducting resulting in a current
flow around the capacitor-reactor loop. Depending on the control angle of the
thyristors, the apparent impedance can be either capacitive or reactive. Through
certain control schemes such as Synchronous Voltage Reversal (SVR) the
apparent capacitive reactance can even be boosted above the reactance of the
capacitor alone. [2]
Figure 4-3 - TCSC impedance characteristic with SVR. Source: [2]
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As illustrated in Figure 4-3, a TCSC can include control methods which make the
apparent impedance of the TCSC reactive in the sub-synchronous frequency range.
Consequently, the TCSC can be very effective in mitigating the potential for SSI. At the
same time, the scheme presents a capacitive reactance that can be controlled around
the fundamental frequency.
A TCSC includes several additional components as compared to a fixed series
capacitor, including a control system, water cooled thyristors, and an appropriately rated
series reactor. Consequently, the initial capital cost and ongoing maintenance costs
must be factored into the decision to use a TCSC solution. A fixed series capacitor can
be designed and constructed such that conversion to a TCSC can more efficiently
accomplished in the future.
TCSC have been installed in many locations around the world, and studies and
performance show the risk of SSI can be mitigated through a specially designed control
scheme. [2]
Harmonic currents will be generated by a TCSC, however, the harmonics substantially
remain within the loop formed by the capacitor and reactor and only low levels flow out to
the transmission network.
While the application of a TCSC provides effective and proven SSI mitigation, this
approach would present a relatively high capital investment and O&M requirement that
must be considered.
4.3.4.2 Unified Power Flow Controller (UPFC)
A UPFC is another type of FACTS device that can be applied to actively mitigate the risk
of SSI. As an UPFC provides a combination of shunt and series dynamically controlled
compensation to a transmission system, studies have shown that a UPFC with
supplemental control logic can introduce positive electrical damping at sub-synchronous
frequencies. [32]
Reference [21b] provides a comparison of SSR damping performance between a TCSC
and a UPFC on an IEEE SSR Benchmark Case. The presented results show the UPFC
can be supplemented with control to provide positive electrical damping for SSR
mitigation with wind turbines, and performance is somewhat better than the TCSC that
was simulated.
More research is required to determine if a UPFC has been specifically designed and
applied in the field to mitigate SSI. In general, the application of a UPFC would present a
relatively high capital investment and O&M requirement as compared to other mitigation
solutions.
4.4 Generator-Based Mitigation Measures
4.4.1 Passive Filter Damping
A static blocking filter connected in series with a generator can protect a generator unit
from SSI at specific sub-synchronous frequencies of concern. The blocking filter can be
applied at the neutral or network-side of the associated GSU transformer and consists of
a parallel inductor and capacitor which creates a parallel resonance (really high
impedance) at the electrical frequency corresponding to the critical torsional mode of the
generator. The blocking filter prevents the resonant sub-synchronous current from
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entering the generator stator to effectively mitigate the potential for SSR-TI and SSR-TA.
The design is independent of the current and future network conditions. Reference [13]
states that this form of passive filter protection was installed at the Navajo Generation
Station in Arizona in 1976.
Component ratings, de-tuning impacts, and maintenance considerations would need to
be considered to optimize the appropriate design.
4.4.2 Active Filter Damping
Active filters at the generator side of the generator step-up transformer or at the point of
interconnection can be effective at controlling SSI. Shunt devices can be more practical
as they don’t have to be rated to carry the rated current of the generator as would be
required in a series filter application. An active shunt device used solely for SSI damping
purposes only has to be rated to counteract the highest initial expected levels of subsynchronous current through the generator.
Active shunt filters can include thyristor-controlled reactors (TCR) much like an SVC,
thyristor-controlled resistors, or a STATCOM. With generator speed as the control input,
an active shunt filter can be effective in damping torsional oscillations within the
bandwidth of control no matter what the form of SSI. In addition, an electrical side control
input signal can provide the feedback needed to dampen purely electrical side
oscillations such as IGE or SSCI. Other advantages of active filtering are: detuning is
not a concern; and it is substantially immune to network changes including the level
series compensation.
STATCOMs and VSCs have been studied extensively in regard to SSI mitigation,
including the mitigation of SSCI in wind turbines. In some cases, it has been shown that
the device may be used in combination with other mitigation measures to provide
increased positive electrical damping at the local generator(s). [39]
4.4.3 Supplementary Excitation Control Damping
Supplementary Excitation Control Damping (SECD) modulates the synchronous
generator excitation voltage to dampen torsional oscillations. It can be implemented
through the fast active voltage regulator (AVR) and/or a Power System Stabilizer using
an input signal derived from the shaft speed.
Industry literature presents extensive research and efforts to demonstrate the use for
excitation control to dampen SSI since the 1970s. More recently, advanced non-linear
control techniques have been studied considering different types of excitation systems
and PSS with regard to SSR-TI damping characteristics. [37] SECD can be a cost
effective solution to mitigating SSR-TI as no new significant high voltage equipment is
required. [15]
This method of control is not practical for all types of exciters, as the time constants of
exciters are critical to performance. Rotating exciters generally have effective time
constants that are too large for the control of signals in the sub-synchronous frequency
range. The power rating and location of the exciter on the shaft must also be considered
in the possible implementation of SECD.
In should be noted that the presence of a PSS may inherently contribute negative
electrical damping at sub-synchronous frequencies, which can exacerbate an SSI
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condition. [47] Consequently, care must be taken to properly include the representation
of existing PSS in any SSI evaluation.
Our research findings indicate that SEDC has been successfully applied together with
TSR protection on the Shangdu steam turbine-generation plant in China [15], however,
more research is recommended to determine if this SSI countermeasure has been
successfully applied in the US. In general, it appears that SEDC may be practical to
increase positive electrical damping of SSI when applied in conjunction with other
mitigation measures such a specifically designed FACT device or when the risk of SSI is
marginal.
4.4.4 Wind Turbine Control Damping
The use of doubly-fed (DFIG) and direct connected induction wind turbines is becoming
more prevalent in the industry. The benefits of these variable speed wind turbines
include improved power efficiency and control of reactive power exchange with the AC
system. Both of these types of wind turbines use voltage source converters (VSC) as
the basis for the variable speed drive and reactive power control.
Figure 4-4 presents a basic one-line diagram of a Type-3, DFIG that shows the back-toback VSC arrangement. The rotor side converter connects to the turbines rotor winding
and the grid side converter connects to the generator terminal.
ST
A TO
R
IS
AC
NETWORK
ROTOR
XTG
IG
IR
RSC
GSC
Figure 4-4 - DFIG Basic One-Line (Type-3)
Since the first occurrence of the SCCI phenomenon involving wind turbines in Texas in
2009, there has been extensive study of the mitigation measures through the proper
design and tuning of the turbine’s control system. Several papers on the subject have
been published by wind turbine suppliers, academics and consultants. The papers
consider various control input signals as well as rotor versus grid side converter
supplemental control strategies in Type-3 wind turbines. [36][44] In a presentation by
General Electric, it is shown that control strategy used in their wind turbines can mitigate
SSCI. [27] Vestas also claims that most SSCI issues can be addressed through the
proper tuning of their control system [36]. Regardless of the wind turbine supplier and
control scheme, care should be exercised to demonstrate the performance through
detailed simulation if the potential for SSCI exists.
Modification of the control scheme on wind turbines that are in service prior to the
application of a near-by series compensated line will be much more involved and costly
than designing and testing a proper scheme for a new installation.
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4.5 Network-Based Protection Measure
4.5.1 Series Capacitor By-pass
A protection to by-pass the capacitor can be implemented upon the detection of
sustained or growing sub-synchronous currents through the element. This would quickly
change the resonant state of the network to cease the SSO. The drawback of this
method is that permanently bypassing the series capacitor will reduce the dynamic
stability of the network and thus generation may have to be tripped concurrently.
4.6 Generator-Based Protection Measures
4.6.1 SSI Relays
Relay protection can be applied to a specific generator or group of generators to protect
the unit(s) from damage due to an SSI condition. Typically, the relays are set to trip the
generator unit(s) based on a level and duration of the SSI. This type of protection is
sometimes applied as back-up to SSI mitigation measures. These types of relays were
initially developed in the 1970 timeframe in response to the first occurrence of SSR-TI
events. More recently, relay manufacturers have researched and developed solid-state,
micro-processor relays for the purpose of SSI protection. The following table presents a
summary of generator-based SSI relay types currently available in the industry: [45]
Relay
Signal Input
Comments
Torsional
Motion (Stress)
Relay
Shaft Speed
Developed and applied in the late 1970s. Speed is
processed by band-pass filters to calculate
conditions at particular sub-synchronous
frequencies of interest. Torsional Stress Relays
(TSR) have been applied at several generator
units and are still available. Newer torsional
motion relays are micro-processor based.
S. California
Edison patent
Terminal
voltage
Micro-processor relay that uses exclusive timedomain analysis on wave parameters of
successive half cycles. More research is
recommended as to the application of this 1986
patent, performance information, and current
status.
ABB Research
Ltd. patent
Generator
terminal
voltage
Micro-processor based relay developed in the
2011 timeframe.
ERLPhase
Power
Technologies
Generator
terminal
voltage and
currents
Micro-processor based relay is used to perform
frequency spectrum analysis on the inputs to
compare sub-synchronous frequency components
with fundamental component.
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Relay
Application
Innovation
Armature
current
Micro-processor based relay. Developed in late
2009 and applied in 2010 by AEPSC at two
locations as backup generator protection.
The torsional stress relay (TSR) appears to be the most widely applied measure to
protect generators from the potential of SSI due to the proximity of HVDC converters or
series compensated lines.
The input to a TSR is shaft speed measured by magnetic pickups at toothed wheels
installed on the turbine and generator end of the shaft. The shaft speed measurements
are evaluated for indications of torsional oscillations at the critical mechanical
frequencies of interest. A TSR relay can have programmable settings for the critical
frequencies and magnitude/duration of oscillations to issue actions such as a warning,
alarm or trip. Some TSR relays have a built in event and signal recorder to aid in fault
tracing. In addition to shaft speed, a TSR would need electrical inputs to be effective for
protection of IGE or SSCI since these forms of SSI do not involve the mechanical
aspects of the generator and can’t be detected from shaft speed.
A generator outage would be required to install and commission a TSR and there is
always risk of mis-operation of a TSR that could result in an undesired generator outage.
Information of generator stress versus cycles to failure is required to properly set the
relays.
Our research indicates that TSR relays have been applied on several generating units,
primarily to protect against the possible occurrence of SSTI since the late 1970s.
However, detailed performance information and operations and maintenance experience
with TSR relays was not found to be readily available.
In response to the recent SSCI phenomenon, relay manufactures have proposed and
developed new SSI protection based on high speed signal measuring, advanced
filtering, and fast processing with micro-processor based relays using electrical quantity
inputs. Oscillations in an SSCI event can develop very rapidly which imposes the
requirement for a very fast detection scheme. [20] The filtering and signal processing for
the older generation of SSI relays introduce a long time delay which makes these relays
less reliable or even ineffective for SSCI protection.
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5 Protection Schemes and Protection Relay Considerations
5.1 Key Section References
For gaining more in-depth knowledge on the subject matter in this Section 5, the
following primary references are suggested:
[3]
ABB. (2012). “Series Compensated Line Protection”. ABB Webinar.
http://www.youtube.com/watch?v=rKWnMyTYUDM
Altuve, Mooney and Alexander. (2008). “Advances in Series-Compensated
Transmission Lines”. TP6340-01, Schweitzer Engineering Laboratories, Inc.
Anderson and Farmer. (1996). “Series Compensation of Power Systems”.
Encinitas, CA: PBLSH, Inc.
IEEE. (2007). “IEEE Guide for Protective Relay Application to Transmission-Line
Series Capacitor Banks”, IEEE Power Engineer Society – Power Systems Relaying
Committee, Std C37:116-2007
Kasztenny. (2001). “Distance Protection of Series-compensated Lines: Problems
and Solutions”. GER-3998: GE Power Management
Wilkinson. “Series Compensated Line Protection Issues”. GER-3972: GE Power
Management
[10]
[11]
[22]
[26]
[43]
Additional subject references are indicated in square brackets throughout the section
with the complete paper reference list presented in Section 8
5.2 General
Series compensation may be installed in the middle of a transmission line or at one or
both ends. In general, there are more protective relay complexities when the series
capacitor is installed at the line end(s). Of course, if series compensation is initially
installed in the middle of a transmission line the addition of a new substation within the
line may increase the protection complexities - therefore it is important to understand the
line end issues as will be highlighted in this section.
The addition of series compensation within a transmission line presents complexities
with regards to the relay protection of the line itself, and in many cases the relay
protection of adjacent and parallel lines. These complexities will be a function of:

system configuration,

level of series compensation,

series capacitor protection and control schemes, and

other factors.
The application of series compensation first occurred in the 1950s in the US, and the
use of series compensation is becoming more prevalent, so fortunately there is sufficient
industry experience and knowledge available with regard to associated protection issues
and solutions. If the complexities are well understood, relay protection systems can be
reliably designed, tested and applied, especially through the use of modern relay
technologies. [43]
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This section begins by describing the unique system protection issues associated with
the introduction of transmission line series compensation. It then describes the
advanced relays and schemes that can be applied to address the issues described.
Lastly, case examples which present philosophies and experience with the protection of
series compensated transmission lines from three utilities are summarized.
5.3 Influence of Capacitor Protection
Modern series capacitors are protected by a parallel metal oxide varistor (MOV) as
illustrated in Figure 5-1. The MOV limits the voltage across the capacitor based on its
rated protective level. For transient conditions, the MOV will conduct to absorb energy
as necessary to limit the periodic overvoltages across the capacitor. When the MOV
conducts, the apparent series impedance of the parallel elements changes in a nonlinear manner as the MOV has non-linear resistive characteristics. The protective
voltage level of the MOV is selected based on normal conditions, system power swing
conditions and anticipated overload conditions. [29]
VS C
Series Capacitor
MOV
Bypass Switch
Figure 5-1 - MOV protected series capacitor
The MOV is also protected by a bypass switch which is triggered based on its rated
energy dissipation level. When this switch operates, both the MOV and the series
capacitor are bypassed until the energy level decreases below the desired setting.
For most faults that result in high currents through the series capacitor, the MOV-based
protection will bypass the series capacitor and impedance relays will see the line
transmission line impedance only. For high impedance line-ground faults however, the
current may not be sufficient to trigger the bypass switch and the capacitive reactance
will influence the apparent impedance seen by impedance distance relays. For singlephase faults, only the MOV protection on the faulted phase may function, while the
capacitors on the un-faulted phases will not be circumvented. Consequently, the MOV
protection can greatly influence the apparent impedance seen by impedance relays and
this must be carefully considered in the relay protection system design. High impedance
faults as well as faults under minimum generation conditions should be evaluated as part
the relay system design and evaluation. [10][29]
5.3.1 Voltage Inversion and Current Inversion
Faults electrically close to series capacitors can lead to voltage and or current inversions
where the phase angle changes by 180 degrees. [3][10][26]
When the impedance between a relay and a fault is capacitive, the local voltage at the
relay may invert depending on the relative magnitude of other system impedances. The
diagram in Figure 5-2 presents a fault condition on a series compensated line between
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Bus B and Bus REMOTE, where voltage inversion will occur across the series capacitor;
VB is 180 degrees out of phase from VC. For this particular voltage inversion condition
to occur the Xc impedance conditions listed must hold true. If the line has impedance (or
distance) protection, then if the relay uses Bus B for the voltage input, the relay would
sense the fault as a reverse fault rather than an actual forward fault, and may fail to
operate. However if point C was used as the voltage input then the forward fault would
be correctly detected. As shown, the voltage at Bus B is reversed and remains reversed
as you move toward the source until you reach Point A. If a new bus were to be added in
this segment in the future, voltage reversal would be a concern at this bus as well as at
Bus B.
kXL2
SO URCE
XS
XL1
B
A
VS
XC
REMOTE
XR
XL2
C
VC
XC > kXL2
VR
VA
XC < XS + XL1 + kXL2
VF
VB
Figure 5-2 - Voltage profile for a line side fault near a series capacitor (Forward
Fault)
Figure 5-3 shows a voltage profile for a fault on a line behind a series compensated
transmission line. For the impedance conditions listed, the voltages on either side of the
capacitor will again be 180 degrees out of phase. If an impedance relay protecting the
series compensated line at Bus B uses the line side voltage (Point C), under this
condition the voltage will reverse and the apparent impedance will indicate a forward
fault rather than an actual reverse fault, and mis-operation may result. Conversely, if the
Bus B voltage was used then the relay would correctly register the fault in the reverse
direction.
gXL2
SO URCE
XS
REMOTE
B
XL1
XC
C
XR
XL2
VB
VS
VR
VF
XC > gXL1
XC < XR + XL2 + gXL1
VC
Figure 5-3 - Voltage profile for an adjacent line side fault near a series capacitor
(Reverse Fault)
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The simple voltage inversion examples presented above are based on three phase
faults and positive sequence impedance. Similar voltage reversal conditions can affect
the directional discrimination of both negative and zero sequence relays. Refer to
Reference [10] for supporting explanation and examples.
When the impedance on one side of the line fault is inductive and the other side of a line
fault is capacitive a current inversion can occur. This condition is illustrated in Figure 5-4.
As shown the current from one end of the line is 180 degrees out of phase from the
current of the other side of the series compensated line. This current inversion condition
is opposite of the condition that defines an internal fault on an uncompensated line as
one appears as an in-feed and the other as an out-feed.
There are also system conditions that may result in the current being indeterminate at
one end during an internal fault. The same current reversal issues can occur with the
negative and zero sequence currents if Xc is larger than the negative sequence source
impedance or zero sequence source impedance, respectively. [10]
SOURCE
XS
REMOTE
XC
XR
XL
IS
IR
VR
XC > XS
IS
IR
VS
Figure 5-4 - Example of current reversal condition in a SC line
Current inversion and indeterminate current conditions can affect the desired operation
of distance, phase comparison, and directional elements of protection relays. [10]
5.3.2 Distance Protection – Measured Impedance
Special considerations have to be made when applying distance protection on a series
compensated line as explained in this section and in Section 5.3.3.
Distance relay impedance characteristics (blue circles) shown in Figure 5-5 are
associated with the protection of a mid-point series compensated transmission line. The
apparent impedance seen by the relay is much less if the series capacitor remains inservice, as opposed to if the capacitor is by-passed. If the Zone 1 mho relay is set for
the condition of the series capacitor by-passed (dashed circle), it can overreach beyond
the end of the line and potentially trip the line inadvertently for an external fault condition.
Depending on the level of series compensation, the Zone 1 reach would have to be
reduced well below the typical 80-90% reach used to protect an un-compensated line.
[10]
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X
B
ZL
B
A
R
-jXC
Figure 5-5 - Impedance protection on a mid-point SC line
The example above explains the measured impedance difference for the two system
states with and without the series capacitor by-passed. This issue gets further
compounded with the dynamic and non-linear characteristics of the MOV when the
element is triggered and is not in the by-passed state.
The location of the series capacitor and the degree of compensation will impact the
measured apparent impedance. For a close-in fault to the series capacitor, the net
reactance seen by a distance relay could be capacitive. In such a case, a standard
impedance relay would sense that the fault was in the reverse direction, leading to
potential mis-operation. Thus, series capacitors located at the line end can also effect
directional discrimination in addition to the measured impedance. [10][26]
5.3.3 Sub-synchronous Transient Signal Impacts
As explained previously in Section 3.2.1, the application of series compensation within a
power system introduces new electrical resonance conditions at sub-synchronous
frequencies. When faults and switching operations occur in the vicinity of series
compensation, transient electrical system oscillations at sub-synchronous frequency will
be imposed on the fundamental frequency response. The magnitude and number of
sub-synchronous transients will depend on the degree and number of series
compensated transmission lines in service and the operation of the protection function
associated with each series capacitor. The transient response of the power system due
to large disturbances can adversely impact the operation of protective relay systems on
the series compensation line and potentially on adjacent lines. The input signal filter
response of protective relays should be appropriately considered. [26]
Figure 5-6 illustrates a transmission line that is compensated on the remote end. For a
fault at the remote end past the series capacitor, the capacitor’s reactance in series
combination with the line’s inductance will produce a sub-synchronous transient.
Considering that this transient response will be at a frequency less than the fundamental
frequency as explained in the previous paragraph, the lines inductance will appear less
and the capacitance of the will be higher. This will result in a higher transient voltage
drop across the capacitor and the line will appear to have a higher compensation level
during the transient period from the perspective of a distance relay at the sending end of
the line. [26] This can result in mis-operation of the distance relay for faults beyond the
line end series capacitor as further explained below.
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XL
XC
FAULT
Figure 5-6 - Transmission line with remote line end SC
The apparent impedance seen by a Zone 1 distance relay at the sending end of the line
is shown in Figure 5-7 by the red arrowed trace along with the zone 1 characteristic as
the blue circle.
The apparent impedance (red trace) changes over several cycles due to the transient
response superimposed on the line from the fault. In this case, it is assumed that there
is some resistance in the system to dampen the transient response. The apparent
impedance initially appears less due to the transient response, so the relay sees the
impedance entering the Zone 1 trip region (blue circle). The outcome is that the relay
could erroneously trip the local end for faults which are actually beyond the Zone 1
intended reach, or potentially beyond the remote end itself, and may lead to coordination
issues with other protection schemes.
It may be possible to alleviate this problem by further reducing the reach (reduce
diameter of the blue circle to below the red apparent impedance trace) and/or by
introducing a Zone 1 time delay to allow time for the transient to move out of the blue
circle before the relay initiates a trip. In either case, the consequence for coordination
with other protections would have to be carefully studied.
X
A
R
Figure 5-7 - Distance relay overreach due to sub-synchronous transient signals
Sub-synchronous transients will also occur after a fault is cleared if the series capacitor
MOV stops conducting and the series capacitor is effectively re-inserted into the
network. These transients may adversely impact relay operation and thus they must also
be considered.
5.3.4 Adjacent Line Protection Impacts
When series compensation is added to a transmission line, attention must be paid to the
protection of adjacent transmission lines in addition to the protection on the series
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compensated line itself. This is particularly true for line end applications of series
compensation. Distance relays on adjacent lines can be influenced by the negative
reactance characteristic of the series capacitor. [10]
The dotted circle in Figure 5-8 below depicts a Zone 1 relay on an adjacent line to a local
end series compensated transmission line. As shown as standard distance relay would
incorrectly operate for line faults on the series compensated line that are close-in to the
capacitor.
X
B
B
A
-jXC
R
A’
Figure 5-8 - Zone 1 distance relay on SC line (solid) and adjacent line (dotted)
If the adjacent lines are short and the line reactance is less than the capacitor reactance,
the concern gets extended to the remote bus as well as the local bus of the adjacent
line; two or more line sections away. [3]
5.3.5 Other Impacts
Series capacitors can exacerbate relaying issues associated with un-transposed lines
and zero sequence mutual impedance between parallel lines. Since the addition of a
series capacitor effectively lowers the line balanced self-impedance, any unbalanced line
impedance and mutual impedance will become more pronounced with increased series
compensation. [26]
Series compensation provides for higher steady-state power flows in the power system
and the increase in load current can impact the sensitivity setting of protective relays.
5.3.6 Automatic Reclosing for Series Compensated Transmission Lines
Automatic reclosing strategies may be used in conjunction with series compensated
transmission lines. The relay protection complexities presented within this paper must
be factored into an automatic reclosing design strategy. Furthermore, the scheme must
be properly coordinated with the series capacitor control and protection.
Based on the system requirements, either three-phase reclosing or single-phase
reclosing may be appropriate. The primary advantage of for single-phase reclosing is to
maintain the healthy two phases to maintain some level of power transfer to enhance
system stability.
The series compensated case studies summarized in Section 5.5 address the general
automatic reclosing philosophies applied by the corresponding transmission owner. For
example, BC Hydro does not switch their series capacitors as part of the transmission
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line; rather the series capacitor is switched separately but in coordination with the
transmission line switching sequence. [33]
Definitions used in this Section 5.3.6 include:
SPT/SPR – Single-pole tripping and single-pole reclosing
3PT/3PR – Three-pole tripping and three-pole reclosing
5.3.6.1 Series Capacitor Switching
When designing the automatic reclosing philosophy and practice for a series
compensated transmission line, consideration should be made for whether the capacitor
is to be switched as part of the transmission line, or if the capacitor will be separately
switched. In the latter case, the capacitor switching must be carefully coordinated with
the transmission line protections and switching. Benefits associated with separately
switching the series capacitor include:
1. Minimizing transmission line circuit breaker transient recovery voltage (TRV) duty
requirements,
2. Reducing the series capacitor MOV capacity requirements,
3. Mitigating dc current component in transmission line shunt reactors,
4. Mitigating low-frequency transients and the possibility of SSR-TA with nearby
generators during reclosing,
5. Reducing the secondary short circuit arc by increasing the network impedance
during reclose dead time (for SPT/SPR schemes only). [22]
If by-passing the series capacitor is required to keep the TRV duty within the rating of the
transmission line circuit breakers, the by-pass operation would need to occur prior to the
line breakers opening.
The series capacitor switching logic and coordination can be accomplished by using
local current and voltage signals. Zero sequence mutual coupling from unbalanced
faults on parallel lines should be analyzed to prevent undesired operation of the series
capacitor switching logic. Alternatively, signals can be communicated from the
transmission line terminals to properly operate and time the series capacitor by-pass and
re-insertion. The speed and reliability of the communication channels needs to be
factored into the design. [22]
The benefits listed in this Section apply to the switching of series capacitors during line
energization as well as to automatic reclosing.
5.3.6.2 Three-phase Automatic Reclosing (3PT/3PR)
Coordination of 3PT/3PR is more straightforward than using single-pole reclosing on a
series compensated transmission line. If it is decided to implement only 3PT/3PR on a
series compensated line, both the line protection switching, and capacitor protection and
switching should be done on the three-phase basis. The reclosing scheme should be
carefully tested using an EMT-type simulation program to assess breaker duties,
transient effects, dependability and security of local and adjacent line relaying, and
coordination with any series capacitor protections and enabled switching schemes.
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5.3.6.3 Single-phase Automatic Reclosing (SPT/SPR)
System stability may be improved by employing a SPT/SPR scheme on a critical series
compensation transmission line. Furthermore, it may be beneficial to leave the series
capacitors of the healthy two phases in service to maximize the transfer capacitor during
the SPT/SPR interval.
It is important that the series capacitor protection is properly coordinated with the
SPT/SPR scheme such that no three-phase capacitor switching is triggered during the
automatic reclosing sequence.
Rapid and precise phase selection is required for SPT. With series compensated
transmission lines, phase selection can be more complex due to possible current and
voltage signal inversions for high impedance faults, so proper relays and phase selection
methods must be applied and tested. Furthermore, low frequency transients associated
with series compensated lines can introduce errors in the signals measured by the
relays. With advanced relays and high-speed, multi-channel communications for PILOTaided schemes, these complexities can be overcome. [43]
5.3.6.4 Spurious By-pass Operation
There is the possibility of spurious operation of series capacitor protection due to certain
external faults. If the series capacitor protection results in a single phase by-pass/reinsertion, it can be problematic for the transmission line protection on the series
compensated line. This circumstance is more prevalent when directional-based
comparison schemes are utilized with sensitive ground fault protective elements, as
undesired tripping may occur. [33]
5.4 Relay Protection Solutions
5.4.1 Advanced Relays for Series Compensation Application
Protective relays have advanced for the special purpose of protecting series
compensated transmission networks. Modern relays and systems have been devised
and proven to enhance the reliability of distance, directional, and differential based
protection of series compensated networks. The relays described below are
substantially based on documentation produced by two vendors; Schweitzer and
General Electric. Other vendors may offer variations or other advanced relays for the
protection of series compensated lines that are not covered in this summary.
5.4.1.1 Memory Polarization
Standard distance relays are self-polarized through the typical use of positive sequence
voltage or un-faulted phase voltages. Use of these quantities for polarization may lead
to relay mis-operation in the case of voltage inversion or close-in three-phase faults
where the relay input voltage is very low.
Modern distance relays provide the capability to use memory polarization with multi-input
comparators to enhance relay pickup and fault directional recognition. Memory
polarization uses a time-dependent combination of pre-fault and post-fault voltage
conditions when this feature is enabled in a relay. The time-dependent memory function
is used to phase out the pre-fault information with time to position the relay for proper
operation in response to situations such as system swings or line switching into a fault.
[10][26]
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In series compensated networks, the duration of the polarization memory should be set
for proper relay pickup with consideration of the series capacitor MOV protection
response, and the slowest fault clearing time. [10]
5.4.1.2 Special Series Compensation Logic
Over the many years of developing and testing protection systems for series
compensated lines, special logic has been incorporated to improve overreach in Zone 1
of distance relays. Through the proper setting of the special logic, the relay can detect
when a fault is beyond the series capacitor and block the operation to prevent
overreach. If the fault is between the relay and the series capacitor, the relay will
correctly operate. This is accomplished through the comparison of a measured voltage
with a calculated voltage by the relay. The special logic requires the capacitive
reactance to be specified as part of the setting, with the appropriate sign based on the
value measured by the relay. With the relay logic and careful setting, correct directional
sensing will be accomplished regardless of the location of the voltage transformer in
relation to the series capacitor. The zone 1 reach is set based on the uncompensated
transmission line impedance. [10]
5.4.1.3 Sequence Component Impedance for Directional Discrimination
Relays that use negative or zero sequence component inputs provide superior
directional discrimination for single-phase faults. When analyzing the apparent
impedance with negative sequence quantities for example, there is generally sufficient
margin in the calculated apparent impedance between forward and reverse fault
conditions and the sign of the apparent impedance is opposite depending on the faults
direction. Proper settings in these relays provide correct directional discrimination even
with the possibility of voltage reversal. [10][26]
5.4.2 Protection Schemes
5.4.2.1 Line Current Differential Protection
Line current differential schemes can be a very good choice for protection of series
compensated transmission lines. Some of the advantages of this scheme include:

Immunity to voltage inversion

No impact due to series capacitor protection (i.e., MOV operation)

The location of the associated potential transformers is not a concern
The sub-synchronous transients may influence the operational time of differential
element so the relay’s filter response should be understood. As series compensated
lines may be very highly loaded, load flow impacts should be reflected in the design,
setting selections, and testing.
Reference [10] suggests the use of Alpha Plane differential elements to accommodate
the potential for current inversion and sub-synchronous transients. The use of a
negative sequence differential scheme in parallel with the positive sequence scheme
may also be used to contend with current inversion and ensure correct operation.
A reliable communications path between line end relays is required as the scheme
requires a precise measurement and comparison of current signals from each end.
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Improvements in communications and signal conditioning techniques has enhanced the
security of differential scheme performance.
5.4.2.2 Directional Comparison Protection
Directional comparison can provide a secure and reliable protection system for series
compensated lines with the application of the advanced relays such as those
summarized previously in this Section 5.4, and through careful consideration of the relay
complexities discussed herein.
Directional comparison schemes should be equipped with blocking units and transient
blocking circuits to eliminate the possibility of false tripping due to CT saturation and
transient blocking logic may be necessary for situations where directional integrity
cannot be maintained for slow clearing faults. [10][26][43]
In contrast to a line current differential scheme, variations in signal communication time
can be easily accommodated though use of a time delay greater than the maximum
communication time. Furthermore, a directional comparison scheme is comparing
discrete relay signals rather than instantaneous current phasor signals, so it can again
be easier to make adjustments to optimize dependability and security. [43]
Permissive Overreach Scheme
A permissive overreach scheme can provide secure protection of a series compensated
line. The reach of the schemes distance devices should cover the condition where the
series capacitor is by-passed by its overvoltage protection (i.e., the uncompensated line
impedance). The drawback to this is that the relays will have a high degree of overreach
when the series capacitor is not by-passed and this presents more potential for misoperation during external faults. [10][26]
Underreaching Direct Trip and Direct Transfer Trip Scheme
As series compensated lines are often very long, direct trip schemes are frequently
added to supplement a differential or directional comparison scheme to provide an
enhanced level of security.
As presented in Section 5.3.1, current reversal is possible in series compensated lines,
and this can be an issue for directional comparison protection schemes. For faults at
one end of the line, the current at the other end can be indeterminate or reversed
depending on network impedances. This condition causes permissive overreach
schemes to be less reliable for line end fault as compared to faults near the middle of the
line.
In series compensated lines, a direct transfer trip scheme using underreaching relay
settings can be used to provide dependable protection for near end line faults. Thus, a
direct transfer trip scheme together with a permissive overreach scheme can greatly
enhance the dependability of the overall protection system.
5.4.3 Protection Design and Performance Verification
Design and testing protective relaying schemes for and in the vicinity of a series
compensated transmission line with detailed models of the transmission network and key
components is essential. Digital simulation of relay performance using an electromagnetic transient program (EMT-Type) or real time digital simulator (RTDS) is
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Review of Series Compensation for Transmission Lines
recommended to ensure a secure and dependable relay protection design. A steadystate short circuit program will not reflect transients due to series compensation.
Detailed electromagnetic transient simulation is required to produce the subsynchronous transients that will be associated with series compensation in the network
and determine impacts to the relay system performance. Other important modeling
requirements include detailed representation of:

The non-linear MOV characteristics for the series capacitor protection and
reinsertion control

Relay performance

Potential transformer or CCVT transient response

Frequency dependency of the local transmission lines and transformers

Automatic reclosing controls
Various system conditions should be analyzed with a combination of fault location and
fault types. It is important to apply ground faults with low and high resistance as this
may influence the operation the series capacitor protection, which in turn, can impact the
relay system response. Variation of the fault inception angle is also recommended to
produce different dc transients and different levels of sub-synchronous frequency
transients. [10][18]
The use of an RTDS program will go one step further in the performance verification as
actual relays can be connected directly to the simulator.
5.5 Protection Case Studies
5.5.1 BC Hydro
Source
Protection of EHV Transmission Lines with Series Compensation: BC Hydro’s Lessons
Learned [33]
Summary
Protection challenges with regard to series compensation of BC Hydro’s 500 kV
transmission network included:

Undesired operation of fault direction and detection elements:
o
Zone 1 overreach
o
Voltage inversion
o
Current inversion

Influences of unbalanced currents caused by single pole switching (SPS) or line
tripping (SPT) and reclosing (SPR).

Series capacitor switching.

Sub-synchronous transient impacts on relay operation.
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Review of Series Compensation for Transmission Lines
The paper focuses on capacitor switching issues during line faults and routine line
energization.
Issues magnified by the addition of series compensation in the BC Hydro system
include:

Unequal line transpositions.

Unequal transmission line lengths per phase (adjacent cable circuit).

Transmission line single pole open (SPO) conditions.
Protection Scheme
BC Hydro uses identical primary and standby systems with minor setting differences
(dual primary systems). They claim this arrangement provides the benefit of increased
security and lower costs.
Permissive overreaching transfer trip (POTT) with echo logic is used on all 500 kV
transmission lines. Residual and negative-sequence directional overcurrent elements
are used as part of the POTT. Phase-segregated direct transfer trip (DTT) is also
applied to improve selectivity and lower operating time for certain single-phase faults.
Time-overcurrent ground relays are used for backup ground fault protection.
The paper presents their approach for setting the negative-sequence directional
overcurrent element to minimize the chance for mis-operation based on lessons learned
from actual studies and application. The suggested approach is to:

Set considering the minimum Z2 source for forward and reverse faults, as well as
the line Z2 and setting the elements to half of this total impedance. This method
is recommended when the system impedances are dissimilar at each line
terminal. An appendix in the reference paper discusses the pros and cons to this
approach over the method recommended by the rely manufacturer for BC
Hydro’s applications.
BC Hydro addresses the impact of security of negative-sequence directional element
operation due to non-transposed circuits by appropriately adjusting the unbalanced-tobalanced current ratio factors, and forward and reverse negative sequence impedance
settings accordingly.
Auto-reclosing challenges
BC Hydro has multiple modes of protection, and the normally operated mode is:


SPT/SPR for single line to ground faults
Three pole tripping/reclosing (3PT/3PR) for multi-phase faults
The interval between SPT/SPR operations appears as an internal fault to a POTT
scheme. When incorporating sensitive operation for high impedance ground faults,
certain elements must be temporarily disabled to avoid undesired operation. For
uncompensated lines, a time delay of 6 cycles is used to mitigate undesired operation of
the ground elements. For a series compensated line, an extended time delay was
required (12 cycles) to accommodate single pole capacitor switching (see next section).
Alternatively, BC Hydro suggests that digital communications can be used to provide
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Review of Series Compensation for Transmission Lines
signals from the series capacitor back to the terminal relays to block sensitive elements
during switching.
Series Capacitor Switching
BC Hydro uses what they claim is a unique switching practice for their series
compensated transmission lines. Rather than switching the transmission line and
associated series capacitor as a single element, BC Hydro uses the practice of
separately switching the capacitor when the line is tripped, and then reinserting the
series capacitor after the line is successfully reclosed. For SPT/SPR operations, only
the effected phase of the series capacitor is switched out/in to maximize the power
transfer through the healthy series compensated phases. The capacitor switching takes
place 6 cycles after the line (or phase) is tripped and is reinserted 10 cycles after the line
(or phase) is successfully re-closed.
Protection Scheme Testing and Verification
The BC Hydro paper emphasizes the importance of detailed transient testing for
protective relaying applications through the use of real-time digital simulation that
incorporates the actual micro-processor based relay algorithms. BC Hydro recommends
that the following be included in the simulation model:





Reclosing controls on adjacent and parallel lines.
Automatic shunt reactor switching controls.
Circuit breaker closing controls and logic.
Series capacitor bypass and automatic reinsertion controls.
Series capacitor protection elements.
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Review of Series Compensation for Transmission Lines
5.5.2 Hydro-Québec TransÉnergie (HQT)
Source
Transmission Line Protection by Simon Chano - Cover Story PAC World Magazine,
Winter, 2008 [14]
Summary
HQT has implemented series compensation into their EHV system since the early 1990’s
to increase power transfer capacity. Series compensation levels ranged from 20 to 44%.
Extensive system studies were performed to determine the best location to introduce
series compensation and as a result, some lines have the series capacitor installed at
one end and others lines have the series capacitor installed at mid line as shown in
Figure 5-9.
Figure 5-9 Main and back-up proctection schemes for line end and mid-line SC
Source: [33]
Relay Protection Challenges
Voltage reversal issues were addressed primarily through the use of polarized or
memorized voltage based directional elements. Current reversal was not observed due
to the level and location of series compensation together with series capacitor MOV
protections.
Protection Schemes
Relay selection and main protection philosophies were developed and implemented
based on extensive real-time simulation testing on HQT’s Transients Network Analyzer
(TNA).
Figure 5-9 above shows the Main 1, Main 2 and backup protection arrangements used
to protect HQT’s series compensated lines. As shown, different schemes are used
based on the location of the series capacitor on the line (i.e., middle or end).
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Review of Series Compensation for Transmission Lines
The Main 1 and Main 2 schemes are communications dependent whereas the backup
scheme does not rely on communications between the line terminals. The integrity of
the communications channel(s) is very important for the Main’s schemes and as such
digital fiber-optic based communications are rapidly replacing analog communications in
the HQT system for high-capacity performance and speed.
The backup protection uses an impedance based measurement relay. The modified
impedance relay incorporates a lens characteristic to avoid sensitivity to load and power
swings. Based on careful selection and testing, the backup impedance relays proved
reliable and secure for transient and dynamic effects associated with series
compensation.
Automatic Reclosing
HQT utilizes three-phase automatic reclosing for single phase fault detection/clearing on
their EHV series compensated transmission lines. The paper did not note any specific
issues related to automatic reclosing of series compensated line.
Testing and Verification
HQT indicates that transient simulator testing using a real-time TNA was the most
effective method to test and verify various relay protection devices and schemes. This
method provides for the following complex issues to be effectively analyzed:
 Weak in-feed.
 Harmonic and sub-harmonic transient effects.
 Low frequency current oscillations.
 Zero sequence mutual coupling between parallel lines.
 Voltage and current reversal conditions.
 Shunt reactor and line reclosing switching operations/logic.
 Series capacitor control and protection systems.
 Varying fault incidence angles.
 CT and CVT characteristics.
 High resistive faults, evolving faults, and reclosing on a permanent fault.
5.5.3 Pacific Gas & Electric
Source
PG&E 500 kV Series-Compensated Transmission Line Relay Replacement: Design
Requirements and RTDS Testing [18]
Summary
High speed protection was designed and implemented to:
 Improve system transient stability
 Maintain 500 kV system availability
 Reduce possible damage to insulators and conductors
 Permit high-speed reclosing
 Compensate for reduced Zone 1 reach in series compensated lines
Relay Protections Schemes
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Review of Series Compensation for Transmission Lines
PG&E uses the following main and backup schemes. Sets A, B and C rely on
communication channels. The backup Set D does not use communications between the
terminals.
Relaying Challenges
The series capacitors introduce the possibility of overreach and undesired operation of
Zone 1 distance relays. The options that PG&E considered to mitigate this issue
included:
 Introduce a Zone 1 time delay – this was not recommended
 Further reduce Zone 1 reach and verify though RTDS testing
 Enable SC logic in to block Zone 1 for fault beyond a series capacitor located in
front of the relay
The presentation demonstrates that Zone 1 overreach can occur for faults on adjacent
series compensated lines as well as on a directly protected series compensated line.
The use of advanced relays with series compensation logic and memory polarization
mitigates the possibility of mis-operation due to voltage inversion and overreach.
Automatic Reclosing
The PG&E presentation indicates that both single phase and three phase automatic
reclosing is utilized on the series compensated transmission lines.
Testing and Verification
The presentation strongly advises the use of a RTDS platform with direct connection of
the relays to test and verify relay protection performance. See Section 5.4.3 of this
paper.
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Review of Series Compensation for Transmission Lines
6 Project Planning and Implementation Considerations
6.1 Key Section References
For gaining more in-depth knowledge on the subject matter in this Section 6, the
following primary references are suggested:
[11] Anderson and Farmer. (1996). “Series Compensation of Power Systems”.
Encinitas, CA: PBLSH, Inc.
[48] IEC 60143 ‘Series Capacitors for Power Systems’, Parts 1, 2, and 4
Figure 6-3 and Figure 6-6 are adapted directly from Chapter 4 of [11].
6.2 Location of Series Compensation
The location of series compensation along a transmission line is a critical design factor in
selecting to integrate this technology into AC transmission networks. The principal
considerations in selecting location of series compensation are [11]:

The “effectiveness” of series compensation varies as a function of location along
a transmission line;

The location of series compensation affects the voltage profile along the
transmission line;

Transmission line protection settings and capacitor bank bypass energy
dissipation specifications depend on the location of the series compensation
along the transmission line;

Future configurations of the transmission lines being compensated; and

Operations and maintenance issues such as site accessibility, land availability
and telecommunications depend on local conditions where the series
compensation is installed.
The “effectiveness” of a series capacitance is determined using the distributed
parameter theory of transmission lines. It provides a measure of how well the receiving
end voltage of a transmission line is maintained depending on the placement of the
series capacitor from the sending end. From the perspective of the effectiveness of
series compensation, the optimal location for a single series capacitive reactance is at
the mid-point of a transmission line. [11]
The voltage profile of a series compensated line varies according to the location of any
series capacitor banks and the loading levels of the transmission line. Series capacitor
installations can be installed mid-line, either a single unit at the mid-point or two units
each a third of the way along the line, or they can be installed at the line ends with busside or line-side shunt reactors. The topologies are shown in Figure 6-4, Figure 6-5,
Figure 6-2, and Figure 6-1.
As the The following general observations can be made in regards to the voltage profile
of a series compensated line:
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Review of Series Compensation for Transmission Lines

Voltage varies smoothly along the transmission line and undergoes a step
change at the capacitor;

The amplitude of the voltage variation across series capacitors increases with the
level of compensation of the line (the size of the capacitor) and the current
flowing through the capacitor;

For highly loaded lines (above impedance loading), the voltage profile is concave
upwards3;

Lightly loaded lines (below surge impedance loading) are concave downwards4;

Lines loaded to surge impedance loading will generally show a linear voltage
profile along the length of the transmission line;

Increased levels of compensation result in a decrease of the “sag” in the voltage
with a tendency to increase the overall voltage profile;

The voltage variation across a series capacitor is always in the direction that
improves the voltage profile whatever the loading level;
6.2.1 Mid-Line
This can either consist of a single capacitor bank located halfway along the transmission
line or two installations each located one-third of the length between the two line ends.
Multiple installations may be required when the insulation coordination plan for existing
lines do not allow for the relatively high voltages just prior to the series capacitor. Midline stations are unattended.
XL
3
XC
XL
2
3
XC
XL
2
3
Figure 6-1 - Midline compensation at 33% and 66% of line length
XL
2
XL
XC
2
Figure 6-2 - Mid-line compensation at 50% of line length
3
4
Concave upwards refers to situations where the tangent to the curve lies below it.
Concave downwards refers to situations where the tangent to the curve lies above it.
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Review of Series Compensation for Transmission Lines
Mid-Line, 33%, 66%
K=30%
K=50%
K=70%
1.10
1.00
0.90
150
Distance from Receiving End (miles)
Voltage Magnitude (p.u.)
Voltage Magn itude (p.u.)
1.00
300
150
Distance from Receiving End (miles)
1.10
1.00
0.90
300
150
Distance from Receiving End (miles)
0
0
K=30%
K=50%
K=70%
1.00
300
150
Distance from Receiving End (miles)
0
K=30%
K=50%
K=70%
1.20
Voltage Magn itude (p.u.)
Voltage Magnitude (p.u.)
Heavy Loading
(2 x SIL)
150
Distance from Receiving End (miles)
1.10
0.90
0
K=30%
K=50%
K=70%
1.20
300
1.20
1.10
0.90
1.00
0
K=30%
K=50%
K=70%
1.20
Surge Impedance
Loading (SIL)
1.10
0.90
300
K=30%
K=50%
K=70%
1.20
Voltage Magnitude (p.u.)
Voltage Magnitude (p.u.)
1.20
Light Loading
(½ x SIL)
Mid-Line, 50%
1.10
1.00
0.90
300
150
Distance from Receiving End (miles)
0
Figure 6-3 – Line voltage profile for mid-line series compensation. Source [11]
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Review of Series Compensation for Transmission Lines
Advantages:

Results in lower short circuit through the series capacitor equipment;

Improved effectiveness of series capacitors.
Disadvantages:

Access issues: the addition of series compensation installations along existing
right of ways is not always possible;
Future expansion:

Tee-off on transmission line between sub stations and series capacitor

Modular series capacitor consisting of two elements in series separated by a bus
and breaker arrangement
6.2.2 Line Ends
In this arrangement, the capacitors are located very close to the line terminal if not within
the substation. Generally a shunt reactor will be installed along with the series
compensation facility to keep voltages down during periods of low flow. The reactor can
either be on the bus side of the series compensation or on the line side.
XC
XL
2
XC
2
Figure 6-4 - Line end compensation, bus side shunt reactors
XC
XL
2
XC
2
Figure 6-5 - Line end compensation, line side shunt reactors
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Review of Series Compensation for Transmission Lines
Line-ends, bus side – reactors
K=30%
K=50%
K=70%
1.10
1.00
0.90
300
150
Distance from Receiving End (miles)
1.10
1.00
0.90
300
150
Distance from Receiving End (miles)
1.10
1.00
0.90
300
150
Distance from Receiving End (miles)
150
Distance from Receiving End (miles)
0
K=30%
K=50%
K=70%
1.00
300
150
Distance from Receiving End (miles)
0
0
K=30%
K=50%
K=70%
1.20
Voltage Magnitude (p.u.)
Voltage M agn itude (p.u.)
Heavy Loading
(2 x SIL)
300
1.10
0.90
0
K=30%
K=50%
K=70%
1.20
1.00
1.20
Voltage Magnitude (p.u.)
Voltage Magn itude (p.u.)
Surge Impedance
Loading (SIL)
1.10
0.90
0
K=30%
K=50%
K=70%
1.20
K=30%
K=50%
K=70%
1.20
Voltage Magn itude (p.u.)
Voltage Magn itude (p.u.)
1.20
Light Loading
(½ x SIL)
Line-ends, line-side – reactors
1.10
1.00
0.90
300
150
Distance from Receiving End (miles)
0
Figure 6-6 – Line voltage profile for line-end series compensation. Source [11]
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Review of Series Compensation for Transmission Lines
Advantages:

Use of available space, no access issues when in substation

Easier access to banks and equipment for maintenance and operations

No additional site to acquire
Disadvantages:

Lower effectiveness meaning more compensation for the same impact

Increased short circuit-circuit currents require higher bypass equipment ratings
Further expansion:

Totally depends on space availability;

Further compensation can be added at cut in points if flows are greatly increased.
6.3 Modularity of Series Compensation
A series capacitor installation can consist of more than one module and the installation
of the modules can be staged according to planning and project requirements. Each
module consists of a capacitor bank, MOV and bypass circuit for the three phases so
that each module can be operated independently. [48]
Series capacitor installations are generally installed in single modules to reduce capital
costs. In some cases, particularly where future uncertainty is high, modularity presents
certain advantages [11]:

Staged development lowers risk of stranded assets if ultimate transmission
capacity is not required;

The addition of a bus between modules increases flexibility for future connections
allowing for the future connection of a circuit to a generator, load or substation in
a tee-off arrangement;

Individual modules can be switched independently in steps to allow for greater
flexibility to the system operator under varying system loads;

Additional modules could consist of TCSC units allowing for control of dynamic
stability issues that could arise in the future; and

Allows for conditions where high levels of compensation and high currents result
in voltage variations across the banks that exceed standard equipment
specifications.
At a minimum, one platform is required per phase and generally each module will be
built on its own platforms. However, in instances where it is virtually certain that the
ultimate compensation levels will be achieved it may be economically viable to build a
larger platform from the outset and add additional modules to the same platform.
Provision would need to be made for allowing switching and control equipment to be
accessible at ground level.
The modules can be connected directly or to a common bus. Connecting directly will
reduce capital costs but limit flexibility for future expansion and reconfiguration.
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Review of Series Compensation for Transmission Lines
The principal disadvantage to modularity is the increased capital cost per ohm of
compensation.
6.4 Future Development of the Series Compensated Lines
The configuration of the initially installed series compensation will impact on the future
extendibility of the network.
The impact of future segmentation is dependent on the location of the series capacitor/s
on the transmission line, the magnitude of compensation and the specific nature of the
new addition. In general, if future network modifications are committed or likely, then this
should be included in the initial studies for the series capacitors.
The type of the new addition, i.e. load or generation, and its location in relation to the
series capacitor/s are significant factors when analyzing the impact of said addition.
Load may be subjected to over-voltages that significantly exceed the typical
overvoltages impressed on other loads on the system. If generators are added then
short-circuit, stability and SSR studies will need to be repeated.
The magnitude and configuration of the initial capacitor bank installation may preclude
future segmentation of the transmission line with significant cost to reconfiguration the
series compensation if not considered up front.
6.5 Operations and Maintenance Considerations
Operation of series compensation equipment requires a robust Control and Protection
(C&P) system to operate efficiently with the connected transmission line. The C&P
system provides constant monitoring of the equipment to provide appropriate protective
actions during external line and internal equipment fault conditions, and deliver real time
monitoring of components. The C&P system’s real time monitoring can give indication of
abnormal operating conditions within the equipment to allow for repairs to be scheduled
to appropriately mitigate the risk of a subsequent forced outage of the series
compensation or possibly the entire line.
Operations and Maintenance (O&M) requirements for series compensation would add
minimal impacts to the current utility operations. A majority of the equipment used in
series compensation is most likely already found in the typical high voltage transmission
systems. Equipment includes capacitor banks, reactors, circuit breakers, switches, and
MOV arresters which can easily be introduced into the current utility O&M policies. Usual
maintenance items would include:

Infrared (IR) scans of equipment for hotspots or overloads;

Visual inspections to identify damaged equipment such as leaking capacitors or
broken insulators;

Verification of density monitors in SF6 filled equipment;

Periodic capacitor measurements; and

Ordinary inspections maintenance as required by the manufacturer.
Thyristor Controlled Series Compensation (TCSC) requires power electronics which will
have additional maintenance requirements. These power electronics are the same that
have operated reliably in HVDC converters, SVCs, and medium voltage motor drives for
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Review of Series Compensation for Transmission Lines
decades. The additional maintenance would be limited to periodic inspection of the
power electronic cooling system and replacement of faulty power electronic modules
when they are identified by the C&P system. The TCSC will have redundant power
electronic modules built in to system to allow for replacement during planned
maintenance periods.
6.5.1 Operations and Reliability
Real time information such as alarms or equipment status would typically be provided via
RTU or Remote Control Interface to the SCADA/EMS at the local and/or area system
control center(s). The switch from local to remote control would typically require handoff
from the local control unit.
Remote control capabilities can be customized to permit the system operator to perform
certain functions from the SCADA/EMS. For example, the system operator could be
permitted to manually by-pass the series capacitor based on network conditions (i.e., to
avoid the potential for SSI following certain contingencies). Special C&P interlocking
may be required for remote access security. Remote control functionality should be
determined and specified as early as possible to avoid modification requirements after
initial design, installation and testing.
The expected utilization level and required availability of a series compensated
transmission should be factored into the location and design for the compensation
device(s). Some basic considerations include:

Single, partly redundant, or completely redundant C&P systems.

Compensation in the middle of the transmission line or alternatively, at one or
both ends. The time for personnel to respond to series capacitor location(s) as
well as the reliability of required communications will be a function of the
location(s).

Split of the series capacitor blocks onto separate energized platforms, per phase.
50% series compensation could be split into two 25% blocks to increase overall
availability and power transfer capability with consideration of scheduled and
forced outage rates for each block.

Staffing and availability of qualified maintenance personal to respond to alarms
and device issues on a 24/7 basis in accordance with utility best practices and
procedures.

Specification of digital fault recorders (DFR) and/or sequence of events recorders
(SER) to provide tools for more efficient fault tracing and corrective measures.
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Review of Series Compensation for Transmission Lines
7 Roadmap for Further Analysis
7.1 Preliminary Design Stage Studies
During the preliminary design stage of series compensation projects, various steady
state and transient studies are required to determine technical specifications to provide
to vendors. The model used for the series capacitor and the bypass system is
dependent on the study conducted.
The design parameters required from the preliminary analysis are

Series capacitor bank rated impedance;

Series capacitor bank rated current, overload current;

Series capacitor bank insulation requirements;

Varistor energy requirements; and

Number of series compensation modules and or intermediate steps.
To determine these variables, the following studies are required.
7.2 Steady state data for analyzing the active and reactive power
flows and voltage profiles in the system
The series capacitor can be modelled simply as a negative reactance connected in
series with the transmission line. Note that when conducting the study either “Newton” or
“Modified Gauss-Seidel” solution techniques must be used as the traditional “GaussSeidel” solution technique cannot handle series capacitors.
Short circuit data for analyzing the fault currents flowing in the system as well as the
series capacitor for various system configurations during internal and external faults. The
through fault current is needed to identify the required ratings for the series capacitor.
The model representation of the series capacitor during the short circuit will change
depending on whether the bypass spark gap has triggered or the bypass varistors are
conducting a significant amount of current. This depends on how the fault type and
location affects the voltage across the bypass devices. For faults external to the series
capacitor several iterations of short circuit calculations may be required to determine the
bypass path representation for any given fault location and type, so a range of values for
positive, negative, and zero sequence information may be appropriate for an accurate
representation in a short circuit study. An EMT analysis can be used to determine an
equivalent impedance for the bypass path, to be used in the PSS/E short circuit analysis
but would only be valid for a particular fault location and system configuration. If only the
worst case extremes of fault current magnitude (ignoring fault current phase, which is
important for relay settings) are required then for external faults:

The highest fault currents (at the point of fault) would be obtained with the bypass
circuit open, so the positive and zero sequence impedance of the series
capacitor itself is sufficient information for sequence components of the model,
and;

The lowest fault currents (at the point of fault) would be obtained with the series
capacitor bypassed completely. In this case no information is required – the
series capacitor can be modelled as a zero impedance branch.
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Review of Series Compensation for Transmission Lines
7.3 Transient Stability Analysis
The short circuit representation of the bypass path is be used to represent the fault
impedance. After the fault is cleared the bypass path must continue to be modelled until
it ceases to conduct current. PSS/E v30 (and higher) dynamics application offers a
series capacitor gap model (SCGAP2). This model will bypass the capacitor after a
defined time, if the capacitor current (and associated capacitor voltage) exceed a
defined value. The capacitor can be reinserted if the current falls below a defined value,
or permanently shorted by a bypass switch. Note that the varistor action is not modelled
as it is assumed to be sufficiently brief so as to not affect the stability response.
7.4 Harmonics and Frequency Scans
Frequency scan studies will need to be carried out for both sub-synchronous and
harmonic frequencies.
For sub-synchronous frequencies, frequency scans should be conducted to determine
the driving-point system impedance as seen from the neutral point of each nearby
generator. The intent is to identify any sub-synchronous resonance issues.
For harmonics, scans will assess the change in system impedance at either end of the
interconnector and at selected major buses elsewhere in the system, between the
present conditions and following installation of the series compensation in credible
operating conditions. This information can then be used to identify whether harmonic
resonances are likely to be worsened appreciably by the introduction of series
compensation.
7.5 Short-term Transient Voltage and Switching Studies
The following fast transient studies are typically carried out using an electromagnetic
transient type program such as EMTP-RV or PSCAD/EMTDC:
1) Lightning Strikes in the vicinity of the series capacitor
a) Direct strikes to phase conductors due to shielding failure
b) Back-flash from tower to phase conductor due to high stroke current
c) Shielding failure at the substation
2) Energization and de-energization of compensated line
a) Energization from either end with capacitor inserted/bypassed
b) De-energization from either end with capacitor inserted/bypassed, including
breaker TRV
3) Bypass and insertion of capacitor under load
4) Fault response for
a) Different fault types
i)
1-phase-ground (with and without single phase auto-reclose)
ii) 2-phase
iii) 2-phase-ground
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iv) 3-phase
b) Different fault locations
i)
Within capacitor
ii) On compensated line
iii) On adjacent lines
c) Transformer or shunt reactor energization on lightly loaded series compensated
line for ferro-resonance effects.
These studies will determine the maximum energy on varistors, maximum transient
voltage and current on capacitors, and TRV on circuit breakers. They also serve to size
MOV and damping circuit components.
7.6 Small-signal Analysis
The use of series capacitors in a power system typically improves small signal stability
by reducing the series inductive reactance between regions. In general the impact of
series capacitors range from increasing the frequency of local/area/regional modes of
oscillation, dampening the oscillations, or a combination of both.
No special mitigation measures are envisaged however an eigenvalue analysis should
still be carried out on the pre and post compensated system to determine the specific
impact of the series capacitors. This will identify the impact of the series capacitors on
current modes of oscillations, and should consider a range of credible network
configurations, generation dispatch profiles (including wind), demand scenarios, and
inter-state power transfers. In addition, small signal models are needed for generators
(including wind) and HVDC. This may require the re-tuning of any Power System
Stabilizers present on generating units.
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