Application of Static VAr Compensator in Entergy System to address Voltage Stability Issues - Planning and Design Considerations
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Application of Static VAr Compensator in
Entergy System to address Voltage Stability
Issues – Planning and Design Considerations
Venkat S. Kolluri, Senior Member, IEEE, Matthias Claus, Horst Spachtholz, Member,
Sujit Mandal, Samrat Datta, Raymon D. Powell, IEEE, Siemens Power Transmission &
Douglas Mader, Member, IEEE, Distribution, Inc.
Entergy Services, Inc.
supplied from outside the area through long transmission
Abstract- Entergy is in the process of installing SVCs at two of lines. This phenomenon can result in voltage instability
its major load centers. Extensive voltage stability assessment was problems at the major load centers requiring in depth analysis
performed to understand any operational problems and to to prevent operational problems [1].
determine the most efficient size and location of the SVCs. This Based on planning, studies two major load centers in
paper presents planning and design aspects of one of the Entergy were identified as areas with potential voltage
installations. As part of the planning consideration - problem,
alternative solutions evaluated, selection of the most preferred
stability problems. These two areas are the Down Stream of
option and other reactive power issues are covered. Additionally, Gypsy Area (DSG) which includes the City of New Orleans,
as part of the design considerations - SVC Configuration, and the Western Region of the Entergy system located in the
Control Strategy and some of the design issues, such as southeastern part of Texas, between Beaumont and Houston.
coordinated capacitor control, are discussed. Comprehensive voltage stability studies were performed for
these two areas and various reinforcement options were
Index Terms- Voltage Stability, FACTS, SVC, STATCOM, and evaluated. Based on technical, economical and reliability
DVAR factors, Static VAR Compensators (SVC) were considered as
the preferred solution for both of these areas. The first 300
I. INTRODUCTION MVAR SVC will be installed at the Ninemile 230 kV station
Restructuring of the electric utility industry in North just west of New Orleans in May 2005, and the second 300
America has resulted in many new generation MVAR SVC is expected to go into service at the Porter 230
interconnections. Most of this new generation is located away kV station in the area of The Woodlands, north of Houston, in
from major load centers. The major load centers in the May 2006. These two SVCs have similar configurations and
southern part of United States have a high concentration of are substantially identical from a design standpoint.
induction motor loads and have historically been heavily In this paper, the planning and design aspects of the SVC
dependent on local generation to provide the reactive support. for the Western Part of the Entergy System are discussed.
The existing fleet of local generation presently serving the Section II describes the problem in the Western Region, the
native load customers is slowly being replaced by the new study methodology, load modeling issues and the criteria used
generation located remotely from the load. The major portion in the studies. Section III discusses the study results, the
of the real power into the load center will in the future be alternative options considered and the reasons for selecting a
SVC as the preferred option. Section IV goes into design
Venkat S. Kolluri is with Entergy Services, Inc., New Orleans, LA 70113, considerations of the SVC, such as configuration issues,
USA (e-mail: vkollur@entergy.com). control strategy used, SVC scheduling and coordinated
Sujit Mandal is with Entergy Services, Inc., New Orleans, LA 70113, USA capacitor bank control design. Section V provides conclusion
(e-mail: smandal@entergy.com).
Samrat Datta is with Entergy Services, Inc., New Orleans, LA 70113, USA
to the paper in the form of a summary.
(e-mail: sdatta@entergy.com).
Raymon D. Powell is with Entergy Services, Inc., New Orleans, LA 70113, II. STUDY METHODOLGY AND CRITERIA
USA (e-mail: rpowel1@entergy.com). USED
Douglas Mader is with Entergy Services, Inc., New Orleans, LA 70113,
USA (e-mail: dmader@entergy.com). The Western Region is a load pocket within Entergy’s Gulf
Matthias Claus is with Siemens Power Transmission & Distribution, States, Inc (EGSI) service territory. The 2005 expected peak
Erlangen, Germany (e-mail: matthias.claus@siemens.com)
Horst Spachtholz is with Siemens Power Transmission & Distribution,
load for the region is 1700 MW and generating sources in the
Erlangen, Germany (e-mail: horst.spachtholz@siemens.com) Western Region consists of two 260 MW generating units at2
Lewis Creek. These units are required to run in order to Coordinating Council (WSCC) reliability criteria [5]. This
support area voltage under high load conditions. The criterion considered three main factors: a. Voltage Dip b.
Woodlands area located on the northern side of Houston has a Duration of the voltage dip, and c. Post Transient Voltage
very high concentration of load with an average load growth recovery level. The voltage dip criteria required that the
of approximately 5% every year. The one line diagram of the voltage at any load bus should not dip below 30% for more
Western Region is shown in Figure 1. The voltage stability than 20 cycles. If the voltage at trip motor terminals fell
problems in this area were first identified in 1997 and below 0.7 pu continuously for 20 cycles the motor would trip
indicated that under peak load and certain contingency offline. For post transient voltage level criteria, the buses with
conditions, the region can experience voltage instability voltage below 0.92 pu at the end of dynamic simulation were
including rapid collapse [2]. Historically, EGSI has sought to flagged. The primary objective of the dynamic study was to
come up with a solution which would minimize number of
minimize the amount of load at risk under extreme double
motors tripping and lead to acceptable post recovery voltage
contingency conditions. To maintain this general operating
levels.
condition, EGSI has performed numerous transmission
improvements, such as line upgrades, adding capacitor banks, B. Load Models
series compensation of a critical tie line, installing D-SMES For dynamic voltage stability assessment a detailed load
units and implementation of an Under Voltage Load Shedding model is necessary to capture the load dynamics, e.g. impact
(UVLS) program [3,4]. The planning studies performed in of induction motors under low voltage conditions. For study
2003 indicated that transmission improvement would be purposes the loads were modeled at the distribution level in
required to serve the load past 2004 because of thermal and the region of interest. These loads were represented as 50%
voltage issues. Additionally, major transmission induction motor and 50% static load. The induction motor
reinforcements would be necessary by 2005 to keep up with was further separated into two classes: 1. low inertia such as
the load growth in the area. This analysis led to the pumps 2. high inertia such as fans. A portion of the low
requirement of an additional 230 kV series compensated line inertia motor loads was modeled with the option of tripping
and the 300 MVAR SVC at the newly built Porter station. 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
aa 0.96 pf
Fig. 1: Western Region one-line diagram 13.8 kV
The voltage stability assessment was carried out using both ZIP Pump Fan Trip Power Factor
load motor motor motor adjustment
steady state and dynamic analyses. As part of the steady state capacitor
assessment, loadflow studies to alleviate the thermal problems
120 MW 59.4 MW 19.8 MW 19.8 MW 19.8 MW
and PV analysis for determining the load serving capability of 0.96 pf 0.95 pf 0.90 pf 0.90 pf 0.90 pf
the region and establishing voltage stability margin were
performed. This was followed with dynamic analysis to study Fig. 2: Detailed load modeling at the distribution level
fast voltage collapse, perform load sensitivity, compare
alternative solutions and size the dynamic compensation. III. STUDY RESULTS
NERC criterion of multiple contingencies was applied to the The studies were performed on the 2005 summer peak
load pockets for identifying problems. Contingencies were model. As discussed in the previous section, detailed steady
restricted to N-1-1, a unit and a line out condition, since such state and dynamic studies were performed. The study results
a combination has a higher probability of occurrence, than are discussed in this section.
that of two transmission lines.
A. Steady state analysis
A. System Performance Criteria Initially a detailed steady state N-1 screening analysis was
In order to compare various alternative solutions a standard performed to identify thermal and voltage problems. The
set of performance criteria was established. This dynamic system was found to be adequate to handle single element
performance criterion was based on the Western Systems3
outages. Subsequently double contingencies were simulated identify the most critical contingency from a dynamic
and several thermal and voltage problems were identified. The standpoint. This worst case scenario was identified to be a
analyses lead to the conclusion that a new 230 kV line from three phase fault and tripping of the Jacinto to Peach Creek
China substation to Porter would be needed to maintain the 138 kV line. The proximity of the fault to the load center
steady state post contingency thermal and voltage criteria. made the results of the fault more severe. The results of the
The line will also have series compensation. The addition of simulation are plotted in Figure 4. It was found that although
this series compensated tie line into the Western Region had a the system recovered to healthy voltage level, several motors
very big impact in enhancing the load serving capability of the tripped in the process due to sustained low voltages.
region. The PV curves indicating the impact of the line are Since the motor tripping was in the order of several
shown in Figure 3. In these curves, the voltage at the Conroe hundred MWs, it was unacceptable from a reliability
perspective. Moreover, as the voltages decrease the motors
station, which is a critical 138 kV station in the load pocket, is
decelerate and the reactive power drawn by them increases
plotted against the western region load level. The solid curve
substantially. These motors can stall and worsen the situation.
is the voltage profile with the China-Porter line and the
Hence, it was decided that the solution be such that the
dashed curve is the voltage profile without the line, with one voltage recovery be fast enough to minimize motor tripping.
of the two 260 MW units off line. It can be seen that the line With this in mind several fast dynamic VAR devices were
increases the load serving capability of the Western Region by evaluated. These included SVC, Static Compensator
approximately 400 MW under the loss of a line and a unit. (STATCOM) and Distribution VAR device (DVAR). Studies
The voltage decline in the system with the new transmission were also done to optimize the sizes and locations of these
line is gradual, unlike the case without the line. devices. A summary of the different solutions considered is
1.03 provided in Table 1.
1.01
0.99 TABLE 1: ALTERNATIVE SOLUTIONS TO THE DYNAMIC PROBLEM
0.97
0.95
Solution Size
Voltage
(pu)
0.93 SVC 300 MVAR
0.91 STATCOM with ±125 MVAR plus three
Conroe w line
0.89
Conroe wo line
Capacitor banks 36 MVAR cap banks
0.87
0.85
DVAR 10 units of ± 8 MVAR
1350 1550 Load 1750 1950 DVAR with 4 units of ± 8 MVAR
(MW)
Capacitor Banks with 37 MVAR cap banks
Fig. 3: PV curves showing the increase in load serving capability with the China
– Porter 230 kV series compensated line Based on the cost estimates, which included installation
and maintenance costs, and reliability of the devices the SVC
B. Stability analysis was found to be the preferred alternative. The system
The transmission improvement identified in the steady state performance with the 300 MVAR SVC at Porter station is
analysis was included in the model while performing the shown in Figure 5. From the figure, it can be seen that the
stability studies. As discussed in the previous section all the SVC VARs are required for a very short period. However,
loads in the Western Region were modeled in a detailed there were some other N-2 contingencies which were more
manner at the distribution level. One-third of the motor loads critical in terms of steady state and those situations demanded
were modeled with the option that they will trip if the voltage the full output of the SVC on a continuous steady state basis.
fell below 0.7 pu for more than 20 cycles. This was done so as Hence, it was decided to size the device with continuous
to understanding of the severity of the contingencies and rating of 300 MVAR.
1.1 1.1
Voltage
Voltage
(pu)
(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 Porter4
Studies were also performed to see if there was a need for Porter 138 kV bus voltage and the reference voltage) is
inductive compensation. As the voltage overshoot following processed through a deadband controller, the PI controller
discharge of the SVC was found to be within acceptable limits and limiter to obtain the susceptance command for the SVC
inductive compensation could not be justified. In addition, it output. The gain and bandwidth of the deadband controller
was determined that the maximum step change of the SVC have been set such that the SVC responds to a 1 pu voltage
needed to be restricted to 75 MVAr to limit the voltage error signal with a 1 pu change in the SVC susceptance in 50
deviation to 2.5% under the most probable weakened system ms. During weak system conditions when hunting is detected
conditions. Therefore, it was decided that continuous or in the SVC output, the stability controller activates gain
vernier control of voltage was not necessary for the Porter reduction of the PI controller and an increase in the
SVC. bandwidth of the deadband controller. In addition, the Porter
SVC is equipped with an automatic gain optimization feature
IV. SVC DESIGN CONSIDERATIONS which tests the system short circuit level, on a time interval
Based on the study results and in conjunction with which is adjustable, by momentarity switching in one 75 Mvar
Entergy’s SVC design specifications, an SVC proposed by step, and automatically optimizes the gain and deadband. The
Siemens was selected for the Porter station. The SVC’s 300 V-I characteristics of the SVC follow an adjustable slope
MVAr continuous rating is derived from two wye-connected (between 0 and 10%). Based on the SVC output, the slope
75 MVAr TSCs and one delta-connected 150 MVAr TSC. A adjustment controller modifies the reference voltage signal to
one-line diagram of the Porter SVC is shown in Figure 6. The achieve the desired slope. The SVC can also be set to the
configuration of the TSC legs and the voltage level of the low manual mode where the output of the SVC is set to a user-
side of the SVC coupling transformer were chosen to defined value regardless of the voltage error signal.
optimize the performance and cost of the SVC components.
Fig. 7: Simplified primary voltage controller schematic
Fig. 6: Porter SVC one-line Frequent capacitor bank switching in the Western Region
has led to several capacitor bank failures and switching device
As can be seen from the one-line diagram, the SVC malfunctions in the past few years. It was, therefore, decided
coupling transformer is a 300 MVA, 138/15.5 kV to take advantage of the reactive power accorded by the SVC
transformer. There are 13 levels of series connected and displace the capacitor bank reactive power, whenever
antiparallel thyristor valves, two of those levels being possible, in order to minimize capacitor bank switching and
redundant. There are also two surge arresters to limit transient operator intervention. Since the entire 300 MVArs of the SVC
over-voltages per TSC - one across the thyristor and the other would be required to be held in reserve for fast switching
connected across the thyristor and the current-limiting reactor during heavy load conditions to respond to potential
in each TSC leg. The current limiting reactors are tuned to the contingencies, the SVC could only be used to displace
4.5th harmonic for the 75 MVAr TSC and to the 4th harmonic capacitor bank VArs during lightly and intermediately loaded
for the 150 MVAr TSC. Internally Fused capacitors will be conditions. From planning studies it was determined that
used for the all the TSCs. below a load of 1200 MW in the Western Region, the entire
A. Porter SVC Control reactive capacity of the SVC could be used to replace static
The voltage control of the Porter SVC consists of a capacitor bank VArs. Above the load level of 1500 MW, the
Proportional Integral (PI) controller as shown in Figure 7. The static capacitor banks will have to be switched on to maintain
voltage error signal (obtained from the difference between the the voltage profile in this area and the SVC output would be
limited to 0 MVAr. Between these two points, it was found5
that a linear relationship approximates the ratio between the VII. REFERENCES
allowable steady-state output of the SVC and the load level of [1] P.Pourbeik, R.J.Koessler, B.Ray, “Addressing Voltage Stability Related
the region. Reliability Challenges of San Francisco Bay Area With a Comprehensive
Reactive Analysis,” 2003 IEEE PES Summer Power Meeting, Toronto,
The SVC reactive power dispatch as a function of load
CA.
level is implemented in the controls of the Porter SVC by [2] C.W.Taylor, Power System Voltage Stability, McGraw-Hill Inc, 1992
using coordinated external capacitor bank switching. This is [3] S,Kolluri, K.Tinnium, M.Stephens, “Design and Operating Experience
done by allowing the SVC controls to manage the switching with Fast Acting Load Shedding Scheme in the Entergy System to Prevent
Voltage Collapse,” 2000 IEEE PES Winter Power Meeting, Singapore.
of up to ten capacitor banks in the area in such a way as [4] S.Kolluri, A.Kumar, K.Tinnium, R.Daquila, “Innovative Approach for
would require the steady-state output of the SVC to follow the Solving Dynamic Voltage Stability Problem in the Entergy System,” 2002
dispatch set points. For instance, if the reactive power output IEEE PES Summer Power Meeting, Chicago, IL.
[5] WECC Reliability Criteria Document.
of the SVC at a particular load level is less than the desired
value, the SVC will switch off capacitor banks. Consequently
VIII. BIOGRAPHIES
the resulting drop in voltage forces the SVC to increase its
Sharma Kolluri (SM’ 86) received his BSEE degree from Vikram University,
reactive output, thereby meeting its reactive power schedule. India in 1973, MSEE from West Virginia University, Morgantown in 1978 and
This coordinated external capacitor bank control will be MBA from University of Dayton in 1984. He worked for AEP Service
implemented using the SCADA system. The SCADA system Corporation in Columbus, Ohio from 1977 through 1984 in Bulk Transmission
will connect the RTUs at the SVC substation and at each of 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
the capacitor banks substations to the host computer residing committees and working groups and is a member of CIGRE. Sharma’s areas of
at the Transmission Operations Center in Texas. By polling interest are Power System Planning and Operations, Stability, Reactive Power
the signals at the various RTUs at the capacitor bank and the Planning and Reliability of Power Systems.
SVC stations, the host computer facilitates the SVC control Sujit Mandal (S’97, M’99) received the B.Tech degree in Electrical
system to switch the desired capacitor banks. Engineering from the Indian Institute of Technology (IIT), Kanpur, India and the
When the coordinated capacitor bank control is disabled or M.S. degree in Electrical Engineering from Kansas State University, Manhattan,
KS in 1997 and 1999, respectively. He worked as a consultant at Power
when there are no more external capacitor banks in the area to Technologies, Inc., Schenectady, NY, from 1999 to 2000. Presently, he is with
maintain the desired reactive power output of the SVC, the Technical System Planning, Entergy Services, Inc., New Orleans, LA.
reactive power set point will be realized using the Q-
controller. This integral type controller slowly biases the 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
reference voltage set-point in order to change the output of 2003. He is currently with Technical System Planning, Entergy Services, Inc.,
the SVC. The time constant of this Q-controller is set several New Orleans, LA.
times higher than that of the voltage controller in order to
avoid improper interactions between the two controllers. 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
V. SUMMARY subsidiary of Nova Scotia Power in 1997 as Vice President, Engineering. He
moved to Entergy Transmission Business in 1998 and is currently Director of
In this paper the results of the Voltage Stability Assessment Technology Delivery Group. He is a member of the IEEE WG on simulation of
for the Western Region of the Entergy System are discussed. electromagnetic transients using digital programs. Mr. Mader is the author of
The study results indicated that with generation out-of-service number of papers in the field of insulation coordination, power system studies,
and under certain single contingency conditions the region and static VAR compensation.
can be subjected to serious voltage stability problems. Several
Raymon D. Powell is currently the manager of Technical System Planning
Flexible Alternating Current Transmission System (FACTS) group at Entergy Services Inc. He has over 20 years of experience in the Electric
devices such as SVC, STATCOM and DVAR were evaluated Power Industry and has held several key positions involving
to mitigate the problem and a 300 MVAR SVC at Porter 138 Transmission/Distribution substation design, relaying, planning and operations.
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.You can also read
