Download Application of SVCs by CenterPoint Energy to Address Voltage

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Application of SVCs by CenterPoint Energy to
Address Voltage Stability Issues:
Planning and Design Considerations
Wesley Woitt, Alberto Benitez, David Mercado;
CenterPoint Energy
Abstract - CenterPoint Energy (CNP) is in the process of
installing two SVCs on its transmission system which serves the
greater Houston, Texas metropolitan area. Extensive voltage
stability assessment was performed to understand the problem
and determine the optimum size and location of the SVCs. This
paper presents planning and design aspects of the SVC
installations. As part of the planning consideration, the
fundamental problem, alternative solutions evaluated, selection of
the preferred option and other reactive power issues are covered.
Additionally, as part of the design considerations, the SVC
configuration, control strategy and other design issues are
discussed.
Index Terms- Voltage Stability, FACTS, SVC, STATCOM, and
DVAR
I. INTRODUCTION
The last ten years have seen extraordinary changes to the
operation of the electric grid of the Electric Reliability
Council of Texas (ERCOT). Foremost among the changes
was the deregulation of the wholesale and retail electricity
markets starting in 2002. Many new generating plants were
built from 1999-2004 throughout the State of Texas which
ultimately displaced many of the older less economical
generating units. As a result of this change in generation
dispatch, historical flow patterns were drastically changed
across the ERCOT grid. Specifically, the CNP transmission
system, which serves the greater Houston metropolitan area,
prior to 2002 very little flow across the 345kV tie lines
occurred that connect Houston with other parts of Texas;
however, after 2002, imports into Houston across the 345kV
tie lines of several thousand megawatts became routine. This
occurred because more economical generation outside the
Wesley Woitt, Alberto Benitez and David Mercado are with CenterPoint Energy,
Houston,
TX
77002,
USA
(e-mail:
[email protected],
[email protected] and [email protected]).
Frank Schettler, Heinz Tyll and Ralph Nagel are with Siemens AG – PTD High
Voltage Division, Power Transmission Solutions, 91058 Erlangen, Germany (e-mail:
[email protected], [email protected] and [email protected]).
Brian Gemmell and Tammy Savoie are with Siemens Power Transmission &
Distribution, Inc. Wendell, NC 27591, USA (e-mail: [email protected] and
[email protected]).
Frank Schettler, Heinz Tyll, Ralph Nagel, Brian
Gemmell, Tammy Savoie; Siemens
Houston area began displacing large amounts of less
economical generation within the Houston area. A by-product
of this displacement was a reduction in local dynamic reactive
support.
History has shown that metropolitan areas that import large
amounts of power are susceptible to voltage collapse events
[1]. This situation is exacerbated for the CNP system since
the Houston area has one of the highest concentrations of
residential air conditioning load in the world. It is well known
that residential air conditioners have response characteristics
that contribute to slow transmission system voltage recovery
during voltage dips. With these developments as a backdrop,
CNP began investigating ways to mitigate risk, including
adding new sources of dynamic reactive support to its
transmission system.
In 2003, CNP performed studies necessary to determine an
under-voltage load shedding (UVLS) scheme, which was
installed in 2004. In 2004, CNP completed a study which
identified a set of projects that would allow additional transfer
capability into the Houston area from both the north and the
south. That study contained analysis that indicated the
transmission system also required the addition of some
amount of dynamic reactive support. The transmission
projects were approved by ERCOT in March 2005 through
their open planning process. Prior to ERCOT approval of the
transmission projects, it was announced that 3,800MW of
generation connected to the CNP transmission system was to
be retired before the summer of 2005. It was at this point that
CNP undertook an analysis that will be discussed in this paper
and ultimately to the decision to install two 140MVar Static
VAR Compensators (SVC) by summer 2008.
This paper will discuss the planning and design aspects of
the two SVCs. In Section II, the study methodology and
performance criteria will be discussed, including the various
dynamic models that were developed for the study. Section
III will focus on the study results and the various technologies
that were considered. Section IV discusses design
considerations of the SVC as well as the control and
protection philosophy.
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II. STUDY METHODOLGY AND CRITERIA USED
The CenterPoint Energy transmission system is extremely
strong with high fault currents throughout the system. The
Texas-New Mexico Power Company’s (TNMP) Texas City
and West Columbia systems are basically radial feeds from
CNP’s system totaling 2,100MW of load. The TNMP system
and load are included in the detailed models that were
developed for these studies. For system events, CNP and
TNMP buses essentially act as one contiguous bus group,
meaning severe voltage dips are felt across the entire system.
CNP studied projected 2006 summer peak conditions with the
expectation that summer peak conditions would provide the
worst conditions for voltage recovery. The projected 2007
summer peak conditions included a CNP and TNMP system
load of 20,936MW. CNP’s stability studies included the
normal ERCOT dynamics data as well as the following
additional models that were deemed to be necessary for the
study:
• Generator Over-excitation Limiter (OEL) models for
units connected to the CNP transmission system
• Under-voltage load shedding (UVLS) models simulating
the CNP UVLS scheme
• Load models which include explicit motor models
• Large motor contactor drop-out models
A. Models Included for Voltage Recovery Studies
1) Generator OEL Models
OEL models are intended to model the control
characteristics of generators that reduce reactive output to
continuous rating to avoid damage to the field windings.
Generators typically allow several multiples of the steadystate reactive rating for a short length of time, approximately
10 seconds. For voltage recovery studies where low voltage
persists for more than this length of time, OEL action needs to
be considered because of its negative impact on recovery.
With some exceptions, ERCOT Operating Guides require
generators connected to the transmission system to have an
over-excited (lagging) power factor capability of ninety-five
hundredths (0.95) or less determined at the generating unit’s
maximum net power to be supplied to the transmission
voltage level. Generators are modeled in steady-state base
cases with reactive capability based on generator reactive test
results and operational history. In some cases, this may result
in even greater than 0.95 power factor capability. For the
voltage recovery studies, CNP decided to set the OEL models
to reduce reactive output down to the higher of the two levels.
In other words, CNP modeled all generators providing
reactive output equal to or greater than that required by
ERCOT standards. The models were designed to allow the
generator reactive power output to be driven by the excitation
system model for an amount of time inversely proportional to
the generator reactive output. Once the timer output has been
met, the model reduces the reactive output to a continuous
level as described above. For example, if the generator
reactive output is twice rated value, the OEL model will limit
its reactive output to its rated value after 10 seconds.
2) UVLS Models
Models were included that represent the UVLS scheme
installed on the CNP system. The system is designed to utilize
an undervoltage element in the under-frequency load shedding
relays that were already installed on the system. This
represents about 25-30% of the non self-serve load connected
to the CNP system. The scheme has three blocks of load, all
with a voltage setpoint of 0.91 pu. Block 1 has a time delay
of 3 seconds, block 2 has a time delay of 5 seconds, and block
3 has a time delay of 8 seconds.
3) Load Models
Load modeling is incredibly important to voltage recovery
studies, as has been demonstrated in many studies where
actual voltage collapse events did not match simulated
response. In many cases, one of the reasons for the disparity
between simulated and actual response was incorrect load
modeling. It has been proven that for voltage recovery studies
the characteristics of motor response to voltages below about
80% of nominal must be taken into account to produce
reasonable response. Therefore, CNP decided to convert the
simple load modeled at each bus in the Houston area into load
separated components, such as small motors, large motors,
discharge lighting and resistive load. While this information
can only be definitively determined by very involved research
of the native load, reasonable assumptions can be made for
each of these components. In this case, past ERCOT voltage
studies had used load models developed by Powertech Labs,
Inc. (Powertech) that were based on previous research [2].
CNP decided to use the same load models that were used for
the previous ERCOT study.
The method for determining the load model at a bus is to
determine the breakdown of the load at the bus by percentage
of load which is residential, commercial, and industrial. This
is information that is readily available for the CNP system.
The Powertech load model converts the residential,
commercial and industrial load into various standard
percentages of resistive, small motor, large motor and
discharge lighting, as shown in Table 1. The small motor
model is intended to represent the typical residential air
conditioner load that exists at summer peak conditions.
The derivation of the parameters for the small motor, large
motor, and discharge lighting models is described in previous
research [2]. These models were applied to distribution
substations in both CNP’s and TNMP’s system, which
represents 15,377MW of load. Most of the remaining load
exists at customer-owned substations in CNP’s transmission
system. Nearly all of these substations are industrial in
nature; therefore, the load components were broken down by
applying the percentages associated with the industrial load
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classification in Table 1. Any remaining loads in the CNP
system were modeled as 100% constant MVA. All loads
outside of the Houston area were modeled using a similar
procedure based on load classifications taken from previous
ERCOT study.
Load Class
/ Season
Residential /
Summer
Commercial
/ Summer
Industrial
/ Summer
Load Composition
Small
Large
Resistive
Motor
Motor
Discharge
Lighting
25%
75%
0%
0%
14%
51%
0%
35%
5%
20%
56%
19%
Table 1: Residential, Commercial and Industrial Load Model Composition
4) Large Motor Contactor Drop-Out
CNP operational experience and research has led to the
conclusion that at voltages less than 60% of nominal, large
motors, such as those used in industrial applications, tend to
disconnect or ‘drop out’ due to the contactor opening after a
short delay time and then are reconnected after the voltage
has recovered. Since the amount of large motor load on the
CNP system is a significant portion of the overall load (i.e.
~25%), the large motor contactor drop-out has a significant
effect on overall system response and needs to be included.
The specific model is applied to all load classified as large
motor load. It drops the large motor load if the voltage dips
below 60% of nominal for 0.5 seconds and then reconnects
after the voltage rises above 80% of nominal for 1 second.
B. Disturbances Studied
CNP’s Transmission Design Criteria specifically requires
that system instability should not occur due to a three-phase
fault and a breaker failure condition resulting in a common
mode multiple contingency condition. This requirement is
based on operational experience which shows that these types
of disturbances are credible even though they are classified as
Category D by the North American Electric Reliability
Council (NERC) Reliability Standards [3].
C. Performance Criteria
CNP chose to apply two different performance criteria to
the voltage recovery studies, the first applies to voltages at
generator terminals based on ERCOT criteria and the second
applies to the amount of UVLS load that is shed. In 2005,
ERCOT adopted a requirement for generators to remain
connected to the grid for disturbances where voltage recovers
to at least 90% of rated design voltage within 10 seconds.
CNP chose to apply a companion criterion that requires
system response to ensure that all generator terminal voltages
recover to at least 90% of nominal within 10 seconds after
falling below 90%for the breaker failure events described in
Section II-B. Therefore, as long as generators are meeting the
ERCOT requirements, the transmission system is designed to
ensure no generators are tripped due to a low voltage event.
The second performance criteria applied to CNP’s voltage
recovery studies is to limit the amount of load shed due to
activation of the UVLS relays. CNP currently has about 2530% of its summer peak load (approximately 5,000MW)
available to be shed by UVLS relays. The potential UVLS
load is considered a safety net to help protect the system
during a severe system event; however, it seems unwise to
plan for using the entire available UVLS load for a simulated
event due to the uncertainty inherent in study assumptions.
Also, too much load being removed from the system within a
few seconds is likely to result in a frequency excursion which
could put generators in danger of tripping due to overfrequency. Currently, the ERCOT transmission system is
designed to withstand generation outages of 1,250MW;
therefore, in a similar fashion, CNP chose to limit the UVLS
load shed to 1,250MW for events described in Section II-B.
D. Dynamic Reactive Device Models and Location
CNP chose to evaluate a number of dynamic reactive
device types to meet the performance criteria. The study
evaluated synchronous condenser, Distribution Static
Compensator
(D-STATCOM),
Static
Synchronous
Compensator (STATCOM), Static VAR Compensator (SVC),
and Thyristor Switched Capacitor (TSC) solutions. For each
of these types of devices, typical step-up transformers were
modeled along with typical block diagrams and parameters.
From CNP’s discussions and meetings with other
transmission companies and dynamic reactive device vendors,
it became apparent that blocking voltage could be a concern.
Basically, to protect the device or some component of the
device, it would not react until the voltage rose above a safe
level. For the disturbances on the CNP system, system-wide
post-fault voltages could be 0.5-0.8 pu at most buses. If the
dynamic reactive device had a blocking control function in
this voltage range, then CNP was concerned that it would be
blocked from operation precisely when the system needed the
reactive support the most. A model was developed that
blocked each of the devices below a user defined voltage,
except for the synchronous condenser which operates through
low voltages. For the study, blocking voltages of 0.5 pu, 0.6
pu, and 0.7 pu were tested for each device.
It was decided that dynamic reactive devices would be
placed at not one, but two locations, to avoid a single point of
failure and that the two devices would be of equal size. CNP
investigated likely sites for locating dynamic reactive devices
and determined the top three optimal sites: one Eastern, one
Central and one Western location.
III. STUDY RESULTS
A. Screening Studies
With the models described above, a screening analysis was
performed on the base case to determine the fault locations
resulting in the slowest voltage recovery. This screening
study placed an 8 cycle three-phase fault on each 345kV bus
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in the Houston area with subsequent clearing of a single
345kV transmission line connected to that same bus. 8 cycles
is the breaker failure delayed clearing time for CNP’s 345kV
substations. All buses 138kV and above were monitored and
the duration recorded for bus voltages to recover to 0.7 pu of
its pre-fault value. The contingencies were then ranked by
maximum duration to recover to 0.7 pu. The 20 worst
contingencies were for outages at two 345kV buses that are
very close to each other. Further analysis identified the worst
contingency as one where the fault with breaker failure is
followed by tripping one generator and one transmission line
that share a common breaker at this 345kV substation. This
contingency, which will be identified as #6-L72, was chosen
for all remaining analysis.
B. Voltage Recovery Studies
Figure 1 shows Houston area bus voltage plots for
contingency #6-L72. This disturbance resulted in 2709 MW
of UVLS load shed; however, UVLS activation allowed all the
generator terminal voltages to recover to 90% voltage well
within 10 seconds. Therefore, for this contingency one of the
two performance criteria were not met. At this point, the
various dynamic reactive devices were added and studied at
the various blocking voltages.
always considered an optimal site. Subsequent discussion with
dynamic reactive device vendors, led to the conclusion that
specifying a blocking voltage of 0.5 pu or lower was
appropriate for alleviating the blocking voltage concerns. It
was determined that the TSC based SVC technology was best
suited for this application.
CNP issued a functional technical specification for two
dynamic reactive devices, one at the Central 138kV substation
and one at the Eastern 138kV substation. Figure 2 shows the
expected reactive output from the Central and Eastern SVCs
for the contingency #6-L72.
Dynamic
Reactive
Device
Blocking
MVA of Resulting
Best Two of the
Voltage
Each MW Load
Three Sites
(pu)
Device
Shed
Synchronous
Condenser
DSTATCOM
STATCOM
SVC
TSC
N/A
Western/Eastern
70
996
0.5
Central/Eastern
35
1,246
0.6
Western/Eastern
40
1,093
0.7
Central/Eastern
70
1,061
0.5
Central/Eastern
85
1,226
0.6
Western/Eastern
95
1,093
0.7
Western/Eastern
160
1,214
0.5
Central/Eastern
120
1,170
0.6
Western/Eastern
130
1,104
0.7
Central/Eastern
200
1,189
0.5
Central/Eastern
140
1,121
0.6
Central/Eastern
255
1,079
0.7
Central/Eastern
360
1,204
Table 2: Reactive Device and Blocking Voltage Analysis Results
Buf.
Binary Result File
Scenario
Contingency
1
2
07bc+hill+.5tsc140_47015+40390_wapL.bin
07bc+hill+.5tsc140_47015+40390_wapL.bin
07bc+hill+tsc
07bc+hill+tsc
1 -- WAP#6-L72
1 -- WAP#6-L72
Output of SHCUDM block (MVAR)
200
Bus #
Bus Name
40388
block:
47013
block:
CROSBYSC13.8
QCOMP
BELAIRSC13.8
QCOMP
ID Buf.
1
1
1
2
150
100
Figure 1: Houston Area Bus Voltages for Worst Case Contingency
Table 2 lists the device sizes that need to be added at the
two best locations to reduce the UVLS load shed below
1,250MW. It was not attempted to size the devices so that
exactly 1,250MW of UVLS was shed, but the sizes were
increased by 5MVar blocks until UVLS load shed fell below
1,250MW.
The synchronous condenser results were
primarily for comparison purposes as CNP was not
considering synchronous condensers for installation. As seen
in Table 2, the remaining devices all showed that the Eastern
location was one of the best two locations. For devices with
blocking voltages of 0.5 pu or 0.7 pu, the Central site was
50
0
0.000
5.000
10.000
15.000
20.000
25.000
30.000
Time (sec)
TSAT
Figure 2: Simulated Reactive Power Output for Central and Eastern SVCs
IV. SVC DESIGN CONSIDERATIONS
Based on the study results in the previous Sections and in
conjunction with CNP’s specification, the contract to design
and construct the Central and Eastern SVCs was awarded on a
turnkey basis to Siemens, in partnership with Beta
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Engineering, LLC for constructing two 140MVAr TSC based
SVCs. Both SVCs are identical in topology, deriving their
continuous 140MVar continuous rating from one 140MVar
thyristor switched capacitor (TSC). A one-line diagram of the
SVC is shown in Figure 3. The configuration of the TSC and
the voltage level on the low side of the SVC coupling
transformer were chosen by Siemens to optimize the
performance and cost of the SVC components.
VNHV = 138 kV, fN = 60 Hz
SN = 154.4 MVA
uk =9.1 %
VNLV = 26 kV
CTSC
The V-I characteristic of the SVCs as seen at the HV side
is shown below in Figure 4, which was the basis for the
determination of the secondary side connected components.
The SVCs are designed to operate under system voltage
conditions as shown in Figure 5. Table 3 shows the voltage
and current stresses of the SVC components, related to the
different system voltage conditions as defined in Figure 5.
The capacitive design point of 140MVar is achieved with the
TSC conducting and the reactive power of 0MVar at 1.0 pu
voltage is achieved with the TSC branch blocked. Operation
at 1.05 pu system voltage defines the rating of the
transformer, with increased power output at 1.10 pu system
voltage achieved by the transformer design. At 1.2 pu and 1.3
pu, the TSC branch is blocked and the power output at the HV
side of the transformer is 0 MVAr.
LTSC
2B
TSC
Figure 3: Central and Eastern Simplified SVC One-Line Diagram
A. SVC Design
The LV-side is connected to the HV system via an SVC
coupling single phase transformers with a nominal power
rating of 154.4MVA and a leakage impedance of 9.1%. The
nominal voltage of the secondary busbar of the SVC was
optimized with respect to best utilization of the thyristor
current carrying capability to 26kV. The number of series
connected anti-parallel thyristors is determined from transient
stress calculations based on the assumption of having a
misfiring in the TSC. Internally fused capacitors are used for
the TSC capacitor bank. Each capacitor is rated 714kVAr at
9,817V.
Figure 5: SVC Continuous and Overload Duty from the Specification
V/I Stresses
VNHV (pu)
QHV (MVar)
QLV (MVar)
VNLV (pu)
ITSC (A)
VCTSC (pu)
1.00
140.0
151.57
1.083
3108.8
1.155
Time
Continuous
1.00
1.05
1.10
0.00
154.35 169.40
0.00
167.11 183.40
1.000
1.137
1.191
0.0
3264.3 3419.7
0.0
1.213
1.270
180s
1.20
0.00
0.00
1.200
0.0
0.0
1s
1.30
0.00
0.00
1.300
0.0
0.0
Table 3: Voltage and Current Stresses of TSC Components at Characteristic
Operating Points (See Figure 5)
The technical specification requirements specifically
emphasized life cycle cost together with a loss evaluation
which shows 0MVar operation for most of the time. This was
considered an ideal application for a single TSC solution: at
0MVar the TSC is switched off and does not generate any
load losses, nor excessive magnetic fields, nor load or
harmonic current related audible noise.
Figure 4: V-I Characteristic of the SVC at the HV-side of the Transformer
B. SVC Control
The redundant controller includes the control function of
the SVC and also coordinates the switching interaction of:
two existing 138kV mechanically switched capacitor (MSC)
banks (129.6MVar and 108MVar) and one tap changer at the
Central substation; one 115MVar MSC and one 75MVar
reactor bank at the Eastern substation.
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The control system of the SVC consists primarily of open
and closed loop control functions. The controller has been
built up in a fully redundant system which uses standardized
hardware and software modules, which secures maximum
availability of the SVCs.
The Plant Control contains all the necessary functions to
control and monitor the entire SVC components with
associated control systems (e.g. protection, cooling, valve
base electronics (VBE), local switchyard controls and remote
control). A simplified control overview is shown in Figure 6.
components are integrated in the input circuits of the
controller. The signals are then transformed by galvanically
isolated V/V or I/V converters into signals at control circuit
potential with voltage limitation and interference suppression.
Calibration facilities are integrated for each input.
All frequency dependent circuits are automatically
adjusted to the actual frequency of the power system. This
feature ensures that the evaluation of the actual system values
is precise for a system frequency range of 60Hz ±5Hz.
2) Control Philosophy
The primary purpose of the two SVCs is to provide
Dynamic Voltage Support (DVS Mode) for the CNP
transmission grid for specific three-phase faults with delayed
clearing under certain conditions. In addition, the SVCs shall
be capable of controlling the 138kV bus voltage in steady
state voltage regulation (SSVR Mode). The control loops are
operational simultaneously and are adjustable independently
of each other.
a) 138kV Dynamic Voltage Support Mode
Figure 6: Control Overview
1) Closed Loop Control Functions
The control system of the SVC is of a three-phase
symmetrical, closed loop voltage control type. The simplified
block diagram of the closed loop controller is shown in Figure
7.
Figure 7: Closed Loop Controller – Central SVC
a) Input Signal Processing
The actual voltage signal Vact is the average of the
magnitudes of the 3-phase fundamental frequency busbar
voltages VHV. This signal must be accurate, insensitive to
system harmonics and system frequency deviations.
Over-voltage protection devices and interference
suppression filters to guard against high frequency voltage
Dynamic Voltage Support (DVS) Mode is to provide
voltage support for the transmission system during network
faults, and is always active. If the system voltage drops below
the adjusted Vmin setpoint, a sequence of events happens. At
the Central substation, the TSC and MSCs are switched in to
support the 138kV system voltage. During low voltage events
the load tap changer (LTC) control will be blocked to prevent
tap change operations in the event of a network breakdown.
The short-circuit calculation and dead band adjustments are
blocked if the system voltage decreases under the minimum
voltage setpoint Vmin.
With voltage recovery, the LTC control will be enabled at
the adjusted LTC enable level. The MSCs will remain
switched in and will only be switched off if there is an overvoltage condition >1.1 pu. During system faults the SVC will
stay on-line to stabilize the system voltage. After a period of
ten minutes following the low voltage event, the SVC control
will return to steady state voltage support mode automatically.
There is a similar sequence of events at the Eastern
substation.
Special additions must be incorporated into the secondary
SVC equipment (i.e. cooling system). All primary and
auxiliary equipment must be designed to ensure that the SVC
can remain on-line for the low voltage ride through event. In
this case, the primary cooling pumps used to cool the thyristor
valve were supported via a set of stand-by redundant
inverters.
b) 138kV Steady State Voltage Regulation Mode
The 138kV steady state bus voltages at the Central and
Eastern Substations are controllable to a reference value
which can be set by the operator to a continuously adjustable
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value between 0.90 pu and 1.10 pu. The control objective is to
maintain the steady state bus voltage close to the reference
value. As can be seen from the block diagram in Figure 7, the
Steady State Voltage Regulation mode can be activated or
deactivated.
The voltage deviation ∆V determined by the difference
between the Vact and Vref voltage is fed to the deadband
controller which is used for TSC, MSC and Tap Change
control. Dependent of the measured short circuit level, the
deadband is adjusted for each element.
c) Special Control Functions
Additional control functions are implemented and will
override the normal control. Specific control features for
optimal use of the SVC are explained below.
Due to the fact that the SVC will operate in stand by
position for most of the time, the TSC will be off for the
majority of the time. To test the availability of the SVC, a
periodical TSC on/off test function is integrated to the
controls.
Furthermore, to ensure optimum dynamic response of the
SVC during various network conditions and to avoid
continuous on/off actions of the TSC, automatic deadband
adjustment dependent on the measured short circuit level is
included in the regulator.
A stability controller is integrated which is an important
feature for stability improvement under very weak system
conditions in combination with transient interactions. The
voltage controller output is monitored in order to detect
multiple consecutive changes in direction of the Qreg signal. In
this case, it will increase the deadband stepwise until stability
is reached. The deadband adaptation is activated for hunting
above a pre-defined frequency level. This detection level
ensures sufficient margin to avoid unwanted increases of the
deadband in the lower frequency range of power swings.
Such specific controls improve the SVC performance and
provide benefits to the SVC user.
d) Supervision and Protection Functions
Special control and protection functions are integrated in
the SVC controller to detect abnormal operating conditions
and to react rapidly to avoid damage and unnecessary tripping
by the plant protection system. These control features, which
are included in the closed loop control software, are very
flexible and can be adapted to specific customer
requirements.
The special control and protection functions consist of:
•
•
•
•
•
HV Over-voltage Protection
HV Under-voltage Protection
LV Under-voltage Protection
TSC Current Supervision
TSC Thermal Replica
The outputs of these protection devices are evaluated by
the interrupt and protection logic for optimal reactions. These
features increase the overload capability, in addition to
improvements in the availability and performance of the SVC.
e) Verification of Control Design
The Control and Protection cubicles are connected to a
Real Time Digital Simulator (RTDSTM) which is used to
perform all TNA tests of the SVCs in Erlangen, Germany.
With this RTDS system, steady state and transient behaviors
of the original control, measuring and protection equipment
can be studied under real network conditions. Some of the
specific tests are:
•
Steady state and functional performance tests
•
Verification of protection strategies
• Performance tests under transient system conditions
The digital and real-time simulation is used to optimize the
SVC control design and regulator adjustment and results in
minor adjustments being required on site during
commissioning. Thus the time required to put the SVCs in
operation is minimized.
3) Control and Protection Summary
The two static Var compensators installed at the Central
and Eastern substations will improve the system stability by
providing dynamic reactive power support in case of faults
but also by controlling the 138kV bus voltage. As part of the
SVC commissioning, the real time digital simulator tests
proved to be particularly helpful in studying and
understanding the control and protection systems of the
SVCs.
V. SUMMARY AND CONCLUSION
In this paper, the results of the voltage stability assessment
for CenterPoint Energy’s transmission system are discussed.
Metropolitan areas that import large amounts of power are
susceptible to voltage collapse events. CenterPoint Energy
had to include various models for their dynamic studies, as
well as the performance criteria and evaluation of several
Flexible Alternating Current Transmission Systems (FACTS)
to mitigate the problem. Two identical 140MVar SVCs
connected at Central and Eastern 138kV substations were
selected as the preferred options. The two SVCs are expected
to enter commercial service in May 2008, and a follow-up
paper is planned which will present the construction and final
commissioning considerations.
8
VI. REFERENCES
[1]
[2]
[3]
[4]
[5]
Krebs, R.; Lemmer, S.; Retzmann, D.; Sezi, T.; Weinhold, M., "Blackout
Prevention by Online Network and Protection Security Assessment," IEEE
Power Engineering Society General Meeting, pp.1-3, 24-28 June 2007.
C.W.Taylor, Power System Voltage Stability, McGraw-Hill Inc, 1992.
North American Electric Reliability Council Standards, available at
http://www.nerc.com.
H. Tyll, K. Leowald, F. Labrenz, D. Mader, “Special Features of the
Control System of the Brushy Hill SVC”, CEA HVDC and SVC Control
Committee, Power System Planning and Operating Section, March 1989.
S.R. Chano et al., “Static Var Compensator Protection”, IEEE
Transactions on Power Delivery, Vol. 10, No. 3, July 1995.
VII. BIOGRAPHIES
Wesley D. Woitt received his Bachelors degree in
Electrical Engineering from Mississippi State University
in 1993. He joined CenterPoint Energy in 1993 and has
worked in transmission planning functions for over 14
years where he is currently Supervising Engineer of the
Special Studies group of Transmission Network
Planning.
Alberto Benitez received his BSEE and MEE from
the University of Houston in 1993 and 1998,
respectively. He joined CenterPoint Energy in 1994 in
the Substation Project Department and is currently a
Consulting Engineer for CenterPoint Energy.
David L. Mercado received his Bachelors of Science
Degree in Electrical Engineering from Rice University
in 2003. He joined CenterPoint Energy in 2001 and is
currently working as an Engineer in the Special
Studies group of Transmission Network Planning at
CenterPoint Energy.
Frank Schettler received his Dipl.-Ing. and PhD in
Electrical Engineering from the Technical University
of Ilmenau, Germany in 1992 and 2003 respectively.
He has been working with Siemens in the field of
power transmission and distribution for about 15 years.
As a systems engineer he gained experience in the
fields of power system design, development,
application engineering and sales. He is currently head
of the System Engineering team for FACTS in
Siemens.
Heinz Karl Tyll (M’88, SM’93) graduated in 1968 in
Electrical Engineering from Coburg Polytechnikum. In
1974 he received the Diplom degree from the Technical
University of Berlin. After joining Siemens AG, he
worked in their High Voltage Transmission Engineering
Department since 1975 in the field of network and SVC
system analysis with transient network analyzer and
digital programs. In 1988 he transferred to the System
Engineering Group of the HVDC and SVC Sales
Department. Since 1996 he is responsible for Basic Design of SVC, SC and
FACTS applications. He contributed to CIGRE WG 38 TFs and to relevant
IEEE WG. He is member of IEEE and VDE.
Ralph Nagel received his Dipl.-Ing. in Electrical
Engineering from the Technical University of Leipzig,
Germany in 1988. He has been with Siemens since
1991 and since 1996 working in the SVC Control and
Protection engineering design group. He has been
involved in design, test and commissioning of various
SVC projects.
Brian D. Gemmell (M’00) received his MEng and
PhD in Electrical and Electronic Engineering from the
University of Strathclyde, UK in 1990 in 1995
respectively. During 1992, he spent 6 months as a
Visiting Engineer at the Massachusetts Institute of
Technology. He worked for ScottishPower (1994-2000)
in Substation Engineering and Transmission Planning.
He has spent the past 7 years working in FACTS &
HVDC Business Development and is currently Director
of Business Development with Siemens Power Transmission & Distribution,
Inc., based in Wendell, NC.
Tammy M. Savoie (M ’97) received her BS in 1997
from North Carolina Weslayan and her MBA from the
University of Houston in 2005. She is an Industrial
Advisory Board Member for the Electrical and
Computer Engineering Department at the University of
Houston and a member of IEEE Women in Engineering.
She has worked for Siemens for the past 13 years.