1
Application of Static VAr Compensator in
Entergy System to address Voltage Stability
Issues – Planning and Design Considerations
Venkat S. Kolluri, Senior Member, IEEE,
Sujit Mandal, Samrat Datta, Raymon D. Powell,
Douglas Mader, Member, IEEE,
Entergy Services, Inc.
Abstract- Entergy is in the process of installing SVCs at two of
its major load centers. Extensive voltage stability assessment was
performed to understand any operational problems and to
determine the most efficient size and location of the SVCs. This
paper presents planning and design aspects of one of the
installations. As part of the planning consideration - problem,
alternative solutions evaluated, selection of the most preferred
option and other reactive power issues are covered. Additionally,
as part of the design considerations - SVC Configuration,
Control Strategy and some of the design issues, such as
coordinated capacitor control, are discussed.
Index Terms- Voltage Stability, FACTS, SVC, STATCOM, and
DVAR
I. INTRODUCTION
Restructuring of the electric utility industry in North
America has resulted in many new generation
interconnections. Most of this new generation is located away
from major load centers. The major load centers in the
southern part of United States have a high concentration of
induction motor loads and have historically been heavily
dependent on local generation to provide the reactive support.
The existing fleet of local generation presently serving the
native load customers is slowly being replaced by the new
generation located remotely from the load. The major portion
of the real power into the load center will in the future be
Venkat S. Kolluri is with Entergy Services, Inc., New Orleans, LA 70113,
USA (e-mail: vkollur@entergy.com).
Sujit Mandal is with Entergy Services, Inc., New Orleans, LA 70113, USA
(e-mail: smandal@entergy.com).
Samrat Datta is with Entergy Services, Inc., New Orleans, LA 70113, USA
(e-mail: sdatta@entergy.com).
Raymon D. Powell is with Entergy Services, Inc., New Orleans, LA 70113,
USA (e-mail: rpowel1@entergy.com).
Douglas Mader is with Entergy Services, Inc., New Orleans, LA 70113,
USA (e-mail: dmader@entergy.com).
Matthias Claus is with Siemens Power Transmission & Distribution,
Erlangen, Germany (e-mail: matthias.claus@siemens.com)
Horst Spachtholz is with Siemens Power Transmission & Distribution,
Erlangen, Germany (e-mail: horst.spachtholz@siemens.com)
Matthias Claus, Horst Spachtholz, Member,
IEEE, Siemens Power Transmission &
Distribution, Inc.
supplied from outside the area through long transmission
lines. This phenomenon can result in voltage instability
problems at the major load centers requiring in depth analysis
to prevent operational problems [1].
Based on planning, studies two major load centers in
Entergy were identified as areas with potential voltage
stability problems. These two areas are the Down Stream of
Gypsy Area (DSG) which includes the City of New Orleans,
and the Western Region of the Entergy system located in the
southeastern part of Texas, between Beaumont and Houston.
Comprehensive voltage stability studies were performed for
these two areas and various reinforcement options were
evaluated. Based on technical, economical and reliability
factors, Static VAR Compensators (SVC) were considered as
the preferred solution for both of these areas. The first 300
MVAR SVC will be installed at the Ninemile 230 kV station
just west of New Orleans in May 2005, and the second 300
MVAR SVC is expected to go into service at the Porter 230
kV station in the area of The Woodlands, north of Houston, in
May 2006. These two SVCs have similar configurations and
are substantially identical from a design standpoint.
In this paper, the planning and design aspects of the SVC
for the Western Part of the Entergy System are discussed.
Section II describes the problem in the Western Region, the
study methodology, load modeling issues and the criteria used
in the studies. Section III discusses the study results, the
alternative options considered and the reasons for selecting a
SVC as the preferred option. Section IV goes into design
considerations of the SVC, such as configuration issues,
control strategy used, SVC scheduling and coordinated
capacitor bank control design. Section V provides conclusion
to the paper in the form of a summary.
II. STUDY METHODOLGY AND CRITERIA
USED
The Western Region is a load pocket within Entergy’s Gulf
States, Inc (EGSI) service territory. The 2005 expected peak
load for the region is 1700 MW and generating sources in the
Western Region consists of two 260 MW generating units at
2
Lewis Creek. These units are required to run in order to
support area voltage under high load conditions. The
Woodlands area located on the northern side of Houston has a
very high concentration of load with an average load growth
of approximately 5% every year. The one line diagram of the
Western Region is shown in Figure 1. The voltage stability
problems in this area were first identified in 1997 and
indicated that under peak load and certain contingency
conditions, the region can experience voltage instability
including rapid collapse [2]. Historically, EGSI has sought to
minimize the amount of load at risk under extreme double
contingency conditions. To maintain this general operating
condition, EGSI has performed numerous transmission
improvements, such as line upgrades, adding capacitor banks,
series compensation of a critical tie line, installing D-SMES
units and implementation of an Under Voltage Load Shedding
(UVLS) program [3,4]. The planning studies performed in
2003 indicated that transmission improvement would be
required to serve the load past 2004 because of thermal and
voltage
issues.
Additionally,
major
transmission
reinforcements would be necessary by 2005 to keep up with
the load growth in the area. This analysis led to the
requirement of an additional 230 kV series compensated line
and the 300 MVAR SVC at the newly built Porter station.
Coordinating Council (WSCC) reliability criteria [5]. This
criterion considered three main factors: a. Voltage Dip b.
Duration of the voltage dip, and c. Post Transient Voltage
recovery level. The voltage dip criteria required that the
voltage at any load bus should not dip below 30% for more
than 20 cycles. If the voltage at trip motor terminals fell
below 0.7 pu continuously for 20 cycles the motor would trip
offline. For post transient voltage level criteria, the buses with
voltage below 0.92 pu at the end of dynamic simulation were
flagged. The primary objective of the dynamic study was to
come up with a solution which would minimize number of
motors tripping and lead to acceptable post recovery voltage
levels.
B. Load Models
For dynamic voltage stability assessment a detailed load
model is necessary to capture the load dynamics, e.g. impact
of induction motors under low voltage conditions. For study
purposes the loads were modeled at the distribution level in
the region of interest. These loads were represented as 50%
induction motor and 50% static load. The induction motor
was further separated into two classes: 1. low inertia such as
pumps 2. high inertia such as fans. A portion of the low
inertia motor loads was modeled with the option of tripping
under low voltage conditions. The load model used for the
dynamic studies is shown in Figure 2. The load outside the
area of study was modeled at transmission level. The purpose
of modeling static load at the distribution level was to
represent non motor loads such as lighting, electronic and
computer equipment, and self restoring loads. Based on
extensive research and literature survey, the static load
composition for Western Region was determined to be 25 %
as constant current for the P portion and constant impedance
for the Q portion and 25 % as constant impedance.
138 kV
138 kV
120 MW
0.96 pf
aa
13.8 kV
Fig. 1: Western Region one-line diagram
The voltage stability assessment was carried out using both
steady state and dynamic analyses. As part of the steady state
assessment, loadflow studies to alleviate the thermal problems
and PV analysis for determining the load serving capability of
the region and establishing voltage stability margin were
performed. This was followed with dynamic analysis to study
fast voltage collapse, perform load sensitivity, compare
alternative solutions and size the dynamic compensation.
NERC criterion of multiple contingencies was applied to the
load pockets for identifying problems. Contingencies were
restricted to N-1-1, a unit and a line out condition, since such
a combination has a higher probability of occurrence, than
that of two transmission lines.
A. System Performance Criteria
In order to compare various alternative solutions a standard
set of performance criteria was established. This dynamic
performance criterion was based on the Western Systems
ZIP
load
120 MW
0.96 pf
Pump
motor
59.4 MW
0.95 pf
Fan
Trip
motor motor
Power Factor
adjustment
capacitor
19.8 MW 19.8 MW 19.8 MW
0.90 pf
0.90 pf
0.90 pf
Fig. 2: Detailed load modeling at the distribution level
III. STUDY RESULTS
The studies were performed on the 2005 summer peak
model. As discussed in the previous section, detailed steady
state and dynamic studies were performed. The study results
are discussed in this section.
A. Steady state analysis
Initially a detailed steady state N-1 screening analysis was
performed to identify thermal and voltage problems. The
system was found to be adequate to handle single element
3
outages. Subsequently double contingencies were simulated
and several thermal and voltage problems were identified. The
analyses lead to the conclusion that a new 230 kV line from
China substation to Porter would be needed to maintain the
steady state post contingency thermal and voltage criteria.
The line will also have series compensation. The addition of
this series compensated tie line into the Western Region had a
very big impact in enhancing the load serving capability of the
region. The PV curves indicating the impact of the line are
shown in Figure 3. In these curves, the voltage at the Conroe
station, which is a critical 138 kV station in the load pocket, is
plotted against the western region load level. The solid curve
is the voltage profile with the China-Porter line and the
dashed curve is the voltage profile without the line, with one
of the two 260 MW units off line. It can be seen that the line
increases the load serving capability of the Western Region by
approximately 400 MW under the loss of a line and a unit.
The voltage decline in the system with the new transmission
line is gradual, unlike the case without the line.
1.03
identify the most critical contingency from a dynamic
standpoint. This worst case scenario was identified to be a
three phase fault and tripping of the Jacinto to Peach Creek
138 kV line. The proximity of the fault to the load center
made the results of the fault more severe. The results of the
simulation are plotted in Figure 4. It was found that although
the system recovered to healthy voltage level, several motors
tripped in the process due to sustained low voltages.
Since the motor tripping was in the order of several
hundred MWs, it was unacceptable from a reliability
perspective. Moreover, as the voltages decrease the motors
decelerate and the reactive power drawn by them increases
substantially. These motors can stall and worsen the situation.
Hence, it was decided that the solution be such that the
voltage recovery be fast enough to minimize motor tripping.
With this in mind several fast dynamic VAR devices were
evaluated. These included SVC, Static Compensator
(STATCOM) and Distribution VAR device (DVAR). Studies
were also done to optimize the sizes and locations of these
devices. A summary of the different solutions considered is
provided in Table 1.
1.01
0.99
TABLE 1: ALTERNATIVE SOLUTIONS TO THE DYNAMIC PROBLEM
0.97
Voltage
(pu)
Solution
SVC
STATCOM with
Capacitor banks
DVAR
DVAR with
Capacitor Banks
0.95
0.93
0.91
Conroe w line
0.89
Conroe wo line
0.87
0.85
1350
1550
Load
(MW)
1750
1950
Fig. 3: PV curves showing the increase in load serving capability with the China
– Porter 230 kV series compensated line
B. Stability analysis
The transmission improvement identified in the steady state
analysis was included in the model while performing the
stability studies. As discussed in the previous section all the
loads in the Western Region were modeled in a detailed
manner at the distribution level. One-third of the motor loads
were modeled with the option that they will trip if the voltage
fell below 0.7 pu for more than 20 cycles. This was done so as
to understanding of the severity of the contingencies and
Size
300 MVAR
±125 MVAR plus three
36 MVAR cap banks
10 units of ± 8 MVAR
4 units of ± 8 MVAR
with 37 MVAR cap banks
Based on the cost estimates, which included installation
and maintenance costs, and reliability of the devices the SVC
was found to be the preferred alternative. The system
performance with the 300 MVAR SVC at Porter station is
shown in Figure 5. From the figure, it can be seen that the
SVC VARs are required for a very short period. However,
there were some other N-2 contingencies which were more
critical in terms of steady state and those situations demanded
the full output of the SVC on a continuous steady state basis.
Hence, it was decided to size the device with continuous
rating of 300 MVAR.
1.1
1.1
Voltage
(pu)
Voltage
(pu)
0.1
0.1
Time (sec)
Time (sec)
Fig. 4: Voltage profile in the western region for the worst case scenario
Fig. 5: System performance with the 300 MVAR SVC at Porter
4
Studies were also performed to see if there was a need for
inductive compensation. As the voltage overshoot following
discharge of the SVC was found to be within acceptable limits
inductive compensation could not be justified. In addition, it
was determined that the maximum step change of the SVC
needed to be restricted to 75 MVAr to limit the voltage
deviation to 2.5% under the most probable weakened system
conditions. Therefore, it was decided that continuous or
vernier control of voltage was not necessary for the Porter
SVC.
IV. SVC DESIGN CONSIDERATIONS
Based on the study results and in conjunction with
Entergy’s SVC design specifications, an SVC proposed by
Siemens was selected for the Porter station. The SVC’s 300
MVAr continuous rating is derived from two wye-connected
75 MVAr TSCs and one delta-connected 150 MVAr TSC. A
one-line diagram of the Porter SVC is shown in Figure 6. The
configuration of the TSC legs and the voltage level of the low
side of the SVC coupling transformer were chosen to
optimize the performance and cost of the SVC components.
Porter 138 kV bus voltage and the reference voltage) is
processed through a deadband controller, the PI controller
and limiter to obtain the susceptance command for the SVC
output. The gain and bandwidth of the deadband controller
have been set such that the SVC responds to a 1 pu voltage
error signal with a 1 pu change in the SVC susceptance in 50
ms. During weak system conditions when hunting is detected
in the SVC output, the stability controller activates gain
reduction of the PI controller and an increase in the
bandwidth of the deadband controller. In addition, the Porter
SVC is equipped with an automatic gain optimization feature
which tests the system short circuit level, on a time interval
which is adjustable, by momentarity switching in one 75 Mvar
step, and automatically optimizes the gain and deadband. The
V-I characteristics of the SVC follow an adjustable slope
(between 0 and 10%). Based on the SVC output, the slope
adjustment controller modifies the reference voltage signal to
achieve the desired slope. The SVC can also be set to the
manual mode where the output of the SVC is set to a userdefined value regardless of the voltage error signal.
Fig. 7: Simplified primary voltage controller schematic
Fig. 6: Porter SVC one-line
As can be seen from the one-line diagram, the SVC
coupling transformer is a 300 MVA, 138/15.5 kV
transformer. There are 13 levels of series connected
antiparallel thyristor valves, two of those levels being
redundant. There are also two surge arresters to limit transient
over-voltages per TSC - one across the thyristor and the other
connected across the thyristor and the current-limiting reactor
in each TSC leg. The current limiting reactors are tuned to the
4.5th harmonic for the 75 MVAr TSC and to the 4th harmonic
for the 150 MVAr TSC. Internally Fused capacitors will be
used for the all the TSCs.
A. Porter SVC Control
The voltage control of the Porter SVC consists of a
Proportional Integral (PI) controller as shown in Figure 7. The
voltage error signal (obtained from the difference between the
Frequent capacitor bank switching in the Western Region
has led to several capacitor bank failures and switching device
malfunctions in the past few years. It was, therefore, decided
to take advantage of the reactive power accorded by the SVC
and displace the capacitor bank reactive power, whenever
possible, in order to minimize capacitor bank switching and
operator intervention. Since the entire 300 MVArs of the SVC
would be required to be held in reserve for fast switching
during heavy load conditions to respond to potential
contingencies, the SVC could only be used to displace
capacitor bank VArs during lightly and intermediately loaded
conditions. From planning studies it was determined that
below a load of 1200 MW in the Western Region, the entire
reactive capacity of the SVC could be used to replace static
capacitor bank VArs. Above the load level of 1500 MW, the
static capacitor banks will have to be switched on to maintain
the voltage profile in this area and the SVC output would be
limited to 0 MVAr. Between these two points, it was found
5
that a linear relationship approximates the ratio between the
allowable steady-state output of the SVC and the load level of
the region.
The SVC reactive power dispatch as a function of load
level is implemented in the controls of the Porter SVC by
using coordinated external capacitor bank switching. This is
done by allowing the SVC controls to manage the switching
of up to ten capacitor banks in the area in such a way as
would require the steady-state output of the SVC to follow the
dispatch set points. For instance, if the reactive power output
of the SVC at a particular load level is less than the desired
value, the SVC will switch off capacitor banks. Consequently
the resulting drop in voltage forces the SVC to increase its
reactive output, thereby meeting its reactive power schedule.
This coordinated external capacitor bank control will be
implemented using the SCADA system. The SCADA system
will connect the RTUs at the SVC substation and at each of
the capacitor banks substations to the host computer residing
at the Transmission Operations Center in Texas. By polling
the signals at the various RTUs at the capacitor bank and the
SVC stations, the host computer facilitates the SVC control
system to switch the desired capacitor banks.
When the coordinated capacitor bank control is disabled or
when there are no more external capacitor banks in the area to
maintain the desired reactive power output of the SVC, the
reactive power set point will be realized using the Qcontroller. This integral type controller slowly biases the
reference voltage set-point in order to change the output of
the SVC. The time constant of this Q-controller is set several
times higher than that of the voltage controller in order to
avoid improper interactions between the two controllers.
V. SUMMARY
In this paper the results of the Voltage Stability Assessment
for the Western Region of the Entergy System are discussed.
The study results indicated that with generation out-of-service
and under certain single contingency conditions the region
can be subjected to serious voltage stability problems. Several
Flexible Alternating Current Transmission System (FACTS)
devices such as SVC, STATCOM and DVAR were evaluated
to mitigate the problem and a 300 MVAR SVC at Porter 138
kV station was selected as the preferred option. The
configuration of this SVC consists of two 75 MVAR TSC
branches and one 150 MVAR TSC branch. Besides providing
rapid voltage control to the region under high load conditions,
this SVC will be used for supporting the reactive power
requirements in the area along with the shunt capacitor banks.
The SVC controls will be used to coordinate capacitor bank
switching. This SVC is expected to go into service in May
2006.
VI. ACKNOWLEDGMENT
The authors gratefully acknowledge the contributions of
Robert T. Hellested, John J. Paserba of Mitsubishi Electric
Power Products Inc and John Diazdeleon of American
Superconductor Inc. for providing support on the study.
VII. REFERENCES
[1]
[2]
[3]
[4]
[5]
P.Pourbeik, R.J.Koessler, B.Ray, “Addressing Voltage Stability Related
Reliability Challenges of San Francisco Bay Area With a Comprehensive
Reactive Analysis,” 2003 IEEE PES Summer Power Meeting, Toronto,
CA.
C.W.Taylor, Power System Voltage Stability, McGraw-Hill Inc, 1992
S,Kolluri, K.Tinnium, M.Stephens, “Design and Operating Experience
with Fast Acting Load Shedding Scheme in the Entergy System to Prevent
Voltage Collapse,” 2000 IEEE PES Winter Power Meeting, Singapore.
S.Kolluri, A.Kumar, K.Tinnium, R.Daquila, “Innovative Approach for
Solving Dynamic Voltage Stability Problem in the Entergy System,” 2002
IEEE PES Summer Power Meeting, Chicago, IL.
WECC Reliability Criteria Document.
VIII. BIOGRAPHIES
Sharma Kolluri (SM’ 86) received his BSEE degree from Vikram University,
India in 1973, MSEE from West Virginia University, Morgantown in 1978 and
MBA from University of Dayton in 1984. He worked for AEP Service
Corporation in Columbus, Ohio from 1977 through 1984 in Bulk Transmission
Planning Group. In 1984 he joined Entergy Services Inc, where he is currently
the Supervisor of Technical Studies Group. He is involved in several IEEE
committees and working groups and is a member of CIGRE. Sharma’s areas of
interest are Power System Planning and Operations, Stability, Reactive Power
Planning and Reliability of Power Systems.
Sujit Mandal (S’97, M’99) received the B.Tech degree in Electrical
Engineering from the Indian Institute of Technology (IIT), Kanpur, India and the
M.S. degree in Electrical Engineering from Kansas State University, Manhattan,
KS in 1997 and 1999, respectively. He worked as a consultant at Power
Technologies, Inc., Schenectady, NY, from 1999 to 2000. Presently, he is with
Technical System Planning, Entergy Services, Inc., New Orleans, LA.
Samrat Datta received his BE degree in Electrical Engineering from Nagpur
Unversity in 2001 and MSEE degree from the University of Texas at Austin in
2003. He is currently with Technical System Planning, Entergy Services, Inc.,
New Orleans, LA.
Douglas Mader received his Bachelors degree in Electrical Engineering from
the Technical University of Nova Scotia with Distinction in 1973. He began his
career at the Nova Scotia Power Corporation and moved to the unregulated
subsidiary of Nova Scotia Power in 1997 as Vice President, Engineering. He
moved to Entergy Transmission Business in 1998 and is currently Director of
Technology Delivery Group. He is a member of the IEEE WG on simulation of
electromagnetic transients using digital programs. Mr. Mader is the author of
number of papers in the field of insulation coordination, power system studies,
and static VAR compensation.
Raymon D. Powell is currently the manager of Technical System Planning
group at Entergy Services Inc. He has over 20 years of experience in the Electric
Power Industry and has held several key positions involving
Transmission/Distribution substation design, relaying, planning and operations.