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Transactions on Power
Systems,
Vol
7
No I , February
1992
VOLTAGE CONTROL IMPROVEMENT THROUGH CAPACITOR AND
TRANSFORMER TAP OPTIMIZATION
C.J. Bridenbaugh D.A. DiMascio
Ohio Edison Company
Akron, Ohio 44308-1890
Advanced Engineering Planning Department
Abstract
-
A PCB ubstation capacitor replacement program provides
an opportunity to review a system's overall reactive compensation
requirements. These requirements can be coordinated with other
voltage control elements, such as transformer ap settings, n order to
improve overall transmission operating conditions. A voltage
improvement and var allocation study utilizing an Optimal Power
Flow program provides an effective means of coordinating these
voltage control elements. The control movement required
to
improve
voltage control is minimized while active and reactive system losses
and reactive importsare reduced.
Key wor ds Optimal Power Flow, Voltage Control, Reactive
Allocation, Transformer Tap Optimization.
INTRODUCTION
Ohio Edison (OE) is completing a program which eliminates all
PCB
substation capacitors
on
the transmission and subtransmission
system. One approach to implementing such a program would be to
replace existing
PCB
apacitor
banks
on a one-for-one basis with new
non-PCB banks [l] A potentid disadvantage in this approach is that it
presupposes that all the existing banks are still required in the
locations and at the MVAr ratings that were determined under different
system conditions than exist today. The early planning for the
replacement program recognized an opportunity to review and more
optimally locate and size the reactive compensation needs of the
system. This planning also recognized that capacitive correction
should be coordinated with other voltage control elements, such as
transformer tap settings, n order to improve the overall operation of
the transmission system.
The primary objectives of this study were to improve the voltage
regulation between light load and on-peak load periods and minimize
losses while determining an appropriate level of reactive
compensation. The voltage regulation problem generally consists of
limiting high voltages during light load periods and low voltages
during on-peak periods. Voltage variation between light load and on-
peak periods should be minimized. On-peak and light load system
models were established as the basis for the studies. Considerable
attention was placed on verifying that these base models were realistic
representationsof system performance.
A voltage control evaluation can be accomplished using a
conventional power flow program. However, for a major system
evaluation this method requires the running of numerous trial and
error cases and engineering judgment to find the "optimal" solution.
This type of evaluation can be performed more efficiently and
effectively
with
the use of an Optimal Power Flow (OPF) program.
An OPF will help determine t h e minimum amount of control
movement and capital cost necessary to optimize power system
quantitiesby optimizing specified control variables.
The work described in this paper involved the study of all existing
and currently planned voltage control devices on the
OE
transmission
and subtransmission system. These devices included 104
91
SM
4 3 6 6
PWRS A
paper recommended and approved
by the IEEE Power System Engineering Committee
of the IEEE Power Engineering Society
for
presentat-
ion at the IEEE/PES 1991 Summer Meeting, San Diego,
California, July 28 August 1, 1991. Manuscript
submitted January
30
1991; made available
for
printing May 29, 1991.
R D'Aquila
GE Industrial 8i Power Systems
Power Systems Engineering Department
Schenectady, New York 12345
transformers, most of which are fixed tap, and over 100 sites for new
or additional capacitor bank installations. The intent of this work was
to determine the transformer tap settings and reactive allocation to
provide the best possible voltage profile for all foreseeable system
conditions while minimizing losses and reactive iniports. Due to the
large number of voltage control devices being studied, an optimal
power flow (OPF) was used for most of the analysis. The use of an
OPF eliminated a significant amount of the trial and error work
normally associated with this type of study. This study demonstrates
the benefit of an OPF or transmission planning studies in addition to
previously demonstrated system operation benefits.
ANALYTICAL APPROACH
A. Optimal Power Flow
A conventional power flow solves a set of equations representing
the elements of the power system and yields the voltage magnitude
and angle at each node
in
the system.[2] From the voltage and angle,
other system conditions such as power flows and reactive generation
can
be
calculated. The starting point
is
a set of data representing the
physical values of the transmission system, generation system and the
customer demand. The system of equations
are
solved for one
specific set of equipment settings.
If the solution does not yield acceptable results, the equipment
settings must be adjusted and the equations e-solved. For example,
if
the solution shows an unacceptablevoltage at a bus, transformer taps
or shunt compensation can be adjusted to relieve the problem.
Through experience and skill, the power flow can be
an
effective tool
in determining equipment settings for localized control. However,
when a large number of control adjustments must be made to satisfy
several desirable system wide criteria this becomes an enormous trial
and error process.
This is where the value of an OPF can be realized. An OPF is a
power flow program which not only solves the power flow equations
but optimally adjusts system control variables to achieve desired
results. Its input data requirements are essentially the same as for a
conventional power flow. The same generation, transmission and
load data are used. Additional data is required
to
specify an
optimization objective, controls which can be adjusted, equipment
limits and system constraints. The OPF will adjust the available
control devices to minimize the objective function and satisfy the
system constraints.
The optimization objective is a function which the OPF minimizes.
It can include active or reactive power losses, fuel costs and added
reactive compensation. It can be calculated for the entire modeled
system or, more commonly, for a portion of the modeled system
representing a utility's operating region.
The control variables are transformer tap positions, phase shifter
angles, allocation of reactive compensation, generator terminal
voltages and power generation. Depending
on
the optimization
objective and the user's intent, any of these control variables can be
fixed (not available for adjustment). The available controls are then
adjusted to minimize the objective function and satisfyalllimits.
Equipment limits such
as
generator reactive limits and transformer
tap ranges are actual physical constraints and are strictly enforced
during the optimization process. System limits can include upper and
lower bus voltage limits, line
flow
limits, and area interchange imits.
In cases where the system limits cannot be satisfied with the available
controls the OPF will find the solution which minimizes the
violations. In this instance, minimizing the violations will drive the
control adjustment and the optimization objective will force a solution
as
close to optimal as feasible.
0885-8950/92 03.0001992
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Many of the power system control variables are discrete devices.
For
example, there are a limited number of discrete tap positions
available for a transformer. Similarly, a capacitor bank must be
switched in or out as one unit. To represent this discrete operation
with an optimal power flow, control variables are first optimized as if
they were continuous elements. When the optimal solution is found
the discrete elements
are
reset to their nearest actual setting and the
remaining continuous controls
are
re-optimized. The results from
both the continuous and discrete portions of the optimization can be
reported by the OPF.
This discretization of transformer tap settings and capacitor bank
sizes
can
result in a suboptimal solution with the established voltage
constraints being violated. To avoid this problem, both the discrete
and continuous solution should be carefully reviewed. If the specified
voltage constraints are violated through the discretization process,
more restrictive voltage constraints should be established to ensure the
required voltage constraints
are
met.
An OPF, like a conventional power flow, solves the system
equations for a single set of conditions. The user must simulate
various system conditions and determine the final control settings
based on all results. Nevertheless, the engineering time is
economized.
For a description of the OPF package and methodology used for
this study. refer
to
[3],
141
and [SI
B. Constraints
Two key constraints were utilized in defining the optimization
function for th is study. These constraints were the upper and ower
bus voltage limitsand the elative capacitor installation cost ratios.
The original specified voltage constraints were
a
maximum of
1.05p.u. for
345
kV,
138
kV,
69
kV and
34.5
kV networks and
1.07 U
for
23
kV networks. The minimum voltage level specified
was 0.95 p.u. for all voltage classes. The upper voltage level
corresponds to the maximum steady-state design voltage currently
considered for each voltage class. The lower voltage was chosen to
limit the variation
in
voltageon the transmiSsion and subtransmission
systems between light load and peak loading periods. Some specific
bus voltage limits were specified during the study to avoid extensive
voltage control adjustments for an isolated area.
Voltage limits had
the
single largest impact on the results of both
the transformer tap and capacitor optimization. An increase of as little
as
0.01
p.u. in the low voltage limit would cause a substantial increase
in the required capacitor additions. Correspondingly, a decrease of
0.01
p.u. for the upper voltage limit on the
23
kV system required
transformer tap setting adjustments which caused a substantial
increase
in
the requ redcapacitive additions.
When bus voltages could not be held within the specified
constraints for the given system conditions and available voltage
control elements, the magnitude of all voltage violations was
minimized
General comparative inslallation and replacement costs were
specified for capacitor additions. The relative costs used reflect higher
installation costs at higher voltage classes. The cost for replacement
installations represents nstallingnew capacitors at
sites
where existing
banks will
be
removed.
This
cost was set to
75
of the cost for new
installations to account for utilization of existing controls, structural
steel, and switching devices. Capacitor bank increment additions for
the various voltage classes were also defined.
The size of the
increment additions were larger for the higher voltage classes. These
relative cost ratios and increment addition sizes are indicated in
Table
1.
Table 1
General Installation Sizes and Costs
sizeWVArS) Relative Cost (P.u.)
B u s I k y l M u L n B l p E k m I i s z h m a
138
12.6
2.0
1S O
69
84 8.4 1.0
.75
34.5
80 8.0
1.0
.75
23
45 4.5 1.0 .75
Data was also input to reflect limitations and cost differences at
specific stations. For example, some stations were excluded from
capacitor additions due to site specific limitations.
Generator voltage schedules were specified as fixed for the
purpose of
this
study. These schedulesrepresent the current operating
practice for each generator base on unit and system loading. A
separatestudy is currently in progress to verify the active and reactive
power capabilities of each generator in the system. Therefore, it was
decided to defer detailed study of generator voltage schedules to a
future date. Since most of the native generating capacity is remote
from the transmission system load centers, it was concluded that the
impact of deferring optimization of these voltage schedules would
have a minimal impact on the transformer tap setting and capacitor
recommendations necessary to meet the primary objective of improved
voltage control.
C Study Procedure
All existing and planned substation capacitors are switched either
by automatic voltage control or by operator control voltage ovemde
via SCADA. They are switched on and off as system requirements
change. However, most of the transformers on the system are fmed
tap. Although some fned taps are changed seasonally, the desired
operation is
to
set the taps at a position which would be acceptable
year round while using capacitors for daily and seasonal voltage
control. To achieve this desired mode of voltage control the
transformer aps were fr st optimizedto satisfy voltage constraints for
the light load system conditions. The new tap settings were then
incorporated in the peak load case, where the capacitor optimization
was performed.
The light load system case represents the maximum expected
voltage levels on the system while the peak load case represents the
minimum expected voltage levels. For light load conditions it is
assumed that the generators will
be
at their current light loadoperating
level and that all shunt capacitors will be switched off. Therefore,
transformer tap setting changes are the most economic and effective
means for reducing the light load voltage levels. For peak load
conditions the generators are assumed to
be
at their current peak load
operating leveland all shunt capacitor banks are available for voltage
control. The transformer tap settings are also assumed available for
voltage control for the peak load case, but are limited by the maximum
setting
permitted
to ensure voltage constraints are met for the light load
system case.
The transformer and capacitor optimizationswere
performed
in an
iterative process, requiring passes between the peak and light load
cases. An iterative process was required to ensure a practical
implementation of the transformer tap and capacitor optimization
results. If extensive transformer tap setting changes or capacitive
additions were required to correct isolated voltage violations, the
voltage constraints at these buses were modified. Figure
1
shows a
flow chart of the study process.
The first step is to prepare the on-peak and light load data sets.
h i s
involves specifying he initial load and generation schedules and
initial voltage constraintsfor both load levels. Major system additions
currently planned are
also
included in
the
study data sets.
Transformer tap settings are optimized for light load conditions.
The objective of
each
optimization is to determine tap settings for all
fne
tap transformers which keep bus voltages within their limits and
minimize system losses. Bus voltages are reviewed after each
optimization. If the results
are
not acceptable or practical, voltage
limits can be changed and the process repeated. For each transformer
tap optimization
run
a preliminary capacitor optimization is p e r f o d
for the on-peak load case. This ensures the feasibility of the
transformer tap recommendations or on-peak capacitor optimization.
This process continues until all tap settings are determined and
acceptable voltages are achieved. These tap settings
are then
set in the
on-peak case.
When a tentative transforiner tap schedule has been established,
the optimum substation capacitor bank allocationis determined using
the on-peak load model. All existing PCB capacitor banks are
removed from the data base and the associated buses are identified as
possible replacement locations. All non-PCB capacitor banks
normally used for voltage control under peak load conditions are left
on. Existing non-PCB capacitors used for contingency voltage
suppor~re
assumed
available at a zero nstallation cost All Company
substations are initially designated as candidate buses for either new or
additional capacitors. At each candidate bus the maximum bank size,
switching block size and relative cost per installed MVAr are specified
as input to the OPF.
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Initial Data
Set Preparation
1
Set Voltage Limits
Light Load
Optimize Taps
Set Voltage Limits
and Cap Data -
Peak
Load
Optimize Caps
Figure
1 . Flow
chart
of
stu y process.
The objective of each optimization is to find the minimum added
compensation required to satisfy the voltage constraints while
minimizing active power losses. The
OPF
recommended capacitor
additions and resulting
area
voltage profiles
are
reviewed to evaluate
the feasibility of implementing the recommendations. If the results are
found to be unacceptable, changes can be made to modify the
solution. Depending on the required changes, iterations between the
light load and on-peak load case may be necessary.
For example, if a capacitor is assigned by the
OPF
o a bus which
physically can not accommodate the bank, that bus is removed from
the candidate bus list and the capacitor optimization was repeated.
Other problems include proposed tap changes from
the
light load case
which cause too arge a voltage reduction in the
peak
oad case. This
would cause a significant increase in the amount of compensation
required in the affected
area
solely for voltage control minimal impact
on
losses). In
these instances, the proposed tap changes addressed
isolated bus voltage violations. Therefore, a compromise ap setting
was specified and
the
capacitor optimization
repeated.
This process is repeated until the voltage criteria is satisfied for
both the on-peak and light load cases with a reasonable amount of
added compensation and transformer tap changes.
RESULTS
A. Transformer Tap Optimization
The transformer tap optimization was performed for a light load
system case. The active system load was 1,740 MW, or 42% of the
peak load. The actual generator operating levels for light load
conditions were used and all shunt reactive compensation was
assumed off. The reactive
load
was varied to model the actual
maximum voltage levels which had been experienced for light load
system conditions.
During these projected light load conditions some bus voltages
exceeded 1.05 P U on the subtransmission system. Voltages on the
345 kV and 138 kV transmission system were within the specified
acceptable range. The main objective of the fixed tap transformer
optimization was to bring the subtransmission voltages below the
maximum acceptable voltage level
of
1.05 p.u. (1.07 p.u. for
the
23 kV system) while minimizing the voltage reduction on the 138 kV
transmission system.
A total of 104 transmission and subtransmission transformers
were included in the optimization. The number, voltage rating and
type
of tap changing were:
18 345-138 kV transformers no LTC's
48 138-69 kV transformers no LTC's
11
138-34.5 kV transformers
-
all LTC's
2
138-23kVtransformers
-
l L T C
104 Total
Most of the 138-69 kV and 138-23 kV transformen were already
set at their highest tap positionin the base case all taps
are
on the high
side). Therefore, the most effective way to reduce the
subtransmission voltages was to adjust the 345-138 kV transformers.
Since all 138-34.5 kV transformers are equipped with LTC's, the
34.5
kV bus voltages were not affected.
In
the
first iteration through the tr ansfmer tap optimization
all
the
345-138 kV taps were adjusted to their highest settings. While these
changes brought the subtransmission voltages to within their upper
limits,
hey also lowered the 138 kV bus voltages to levels just above
their lower limits. Although
this
was acceptable for the light load
condition, it was anticipated hat it would require significantcapacitor
additions for on-peakload conditions. The first iteration through the
capacitor optimization confimKd this. A large number of capacitor
additions were required to bring the 138 kV voltages within their
lower limits.
After several iterations between the transformer and capacitor
optimization a final tap schedule was selected. The resulting tap
settings provided reduced voltages for the light load system case while
limiting the amount of added compensation required for the on-peak
load case. This schedule included adjusting several 345-138 kV
transformer tap settings up one tap position to reduce the 138 kV
system voltage. Some 138-23 kV and 138-69 kV transformers were
also adjusted to correct local
area
high voltage concems. While t h i s
did not reduce the high voltage problems during light load conditions
to the extent of the first iteration (a two step adjustment on the 345
138 kV transformers), it kept most subtransmission voltages below
the upper limits for the light load case without requiring excessive
capacitor
bank
additions
to
raise
voltages for the on-peak case. A total
of 25 ransformer taps were changed, with only three aps adjusted to
increase suhs mi ss io nvoltages.
Examples of the voltage reduction achieved through transformer
tap optimization for the light load case are shown in Figures 2, 3 and
4. These are graphical comparisons for the light load case showing
the original transformer settings compared with the new
settings.
Figure 2 is a ranked voltage profile for 69 kV buses in one
operating division. This type of plot provides a statistical picture
of
the bus voltages.
For each curve, bus voltages were sorted i n
descending order, with each case being sorted independently. The top
solid curve labeled "ORIG TAPS" represents the bus voltages
associated with the original transformer tap settings. The curve
labeled "NEWTAPS hows the voltage reduction achieved through
the tap optimization. The original system had approximately
90
uses
with voltages above the 1.05 p.u. limit in this division. With the
recommended tap settings nearly all bus voltages were below this
limit.
Figure 3 shows a similar plot for all 138 kV buses. These graphs
demonstrate that high subtransmission voltages were reduced by
lowering the 138 kV bus voltages via 345-138 kV transformer tap
adjustments.
Figure 4 is a plot of the 345 kV bus voltages. The voltages in this
plot are plotted against individual buses, not sorted as in the previous
ranked profile plot. While the. previous figures showed the reduction
in voltages on the 138 kV and 69 kV systems, this figure shows that
most 345 kV bus voltages were increased by 345-138 kV
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, ORl G
TAPS
1 1
-
n
1
-05
2I
?
1 -
225
...........................................................................................
3
.........................
I L
------ -A-- j
.............. ;. ............
.:.
..... .-.-p--.--
w
a 1
...................
. . . .
. .
.
. . .
. . .
. .
..
....
, ..
..
.........................
. . .
. . . . . . .
. .
. . .
; ....... ....... ; ........................................
. . . . . . .
. . . . .
............... _
........................................................................
. .
. . .
. . . . .
. . .
. . .
. . . . . . .
. . . . . . .
. . . . . . . .
. . .
. . .
, .
. .
0
20
40 60 80
100
N U M B E R O F B U S E S
Figure 2. 69
kV
division light
lo d
voltage profile.
ORl G
TAPS
NEWTAPS-
0.95 1
0 20
40 60 80 100 120
N U M B E R O F B U S E S
Figure 3. 138
kV
light
lo d
voltage profile.
1.06 O R l G TAPS
1.04
2
1.02
n
-
-1
a 1
=-
0.98
0.96
0.94
A B C O E F G H I J K L
BUS NAME
Figure 4 . 345
kV
light
lo d bus
voltages.
transformer tap changes. The buses with increased voltages
correspond to the high side buses of the adjusted transformers. The
increase in high side voltage can be best understood by looking at a pi
equivalent model of the transformer.
Figure
5
shows the pi equivalent circuit for a typical fixed tap
transformerwith high side taps.[3,4] VH and VL are the high and low
side voltages, respectively.YT s the transformer admittance and n is
the off nominal tums ratio. The shunt elements, BH and BL. will
t
B
= ( ) Y T 1
L
Y T
w i l l h a v e t h e f o r m
- j B T ,
w h e r e
BT>O
Figure
5.
Pi eq uivalent transformer circuit.
always be of opposite sign. When one is positive, representing a
capacitor, the other will be negative, representing an inductor. In the
case of the 345-138 kV transformer, where the tap positions were
moved up one step, BH will be moxecapacitivethanoriginally
and
the
345 kV voltage wll rise
The transformer tap changes had a positive impact on the total
reactive imports into the OE system in that the net import was reduced.
The imports were reduced by 238 MVAr (38 ) on the 345 kV tie
lines and increased by 84 MVAr (31 ) on the 138 kV ties, for a net
reduction of 164 MVAr (20 ). The reduced imports on the 345 kV
ties was due to the increased voltage level on the
345 kV
system,
while the increased impor ts on the 138 kV ties is a consequenceof the
reduced voltage levels on the 138 kV system.
B. Capacitor Optimization
The substation capacitor replacement needs were studied using a
load case with 4140 M W of load in the OE system. A total of
587 MVAr of capacitors were in this case, representing the existing
reactive compensation. One hundred sixty-five (165) MVAr of this
total represented PCB banks to
be
removed.
The first task in determining a capacitor replacement plan is to
implement the previously determined fixed tap transformer changes.
Initially the original capacitor banks are left in place to simulate the
results of a one-for-one or
MVAr-for-MVAr
type eplacement scheme
with the new tap settings.
This
un is not an optimization,but rather a
conventional power flow solution intended to serve as a reference for
later comparison.
The results of t h i s simulation
confii
hat with the present reactive
allocation and the proposed transformer tap changes, a large number
of bus voltages will fall below their lower limits of
.95
p.u. during
on-peak load conditions. There was an increase in the voltage levels
on the
345 kV
system, but nearly all other bus voltages were reduced.
The cause of the voltage level increase on the 345 kV system was
discussed in the transformer tap optimization section. These results
clearly demonstrated that some change in the shunt compensation on
the system wouldbe needed to accommodate the new transformer ap
settings during on-peak load conditions.
A new replacement schedule was formulated which would
improve upon a one-for-one replacement of capacitors. This schedule
represents the optimum shunt compensation scheme for the base
system satisfying all voltage requirements and minimizingOE system
losses. It is a practical and attainable plan which accounts for the
specific costs and physical limitations of adding compensation at
particular substations.
The finalcapacitorreplacement schedule consisted of replacing the
165 MVArs of capacitorbanks at 26 locations planned for removal
with 388 MVArs at 35 locations. This increases the total shunt
compensation for this study system from 587
MVArs
o 810 MVArs.
As an example of the voltage changes attained for the on-peak
case, Figure 6 shows bus voltages for one operating division
(69 kV of the system. This is a ranked voltage p f d e plot (similar
to that of Figure 3). By implementing the tap changes without my
changes in shunt compensation (curve NEW APS"), the voltages
were reduced by approximately0.03 p.u. throughout this
area.
This
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1 1
1.05
n
U
5
l
0.95
0.9
3000.-
2000-
1000
B A S E
N E W T A P S
0-
-
1 1
0
10
20 30 40
NUMBER
OF
B U S E S
-.._
,
----*
-- -
,
A
---+--
............................................
.,....
.....................................
Figure 6 . 69 kV division peak lo d voltage
profile
voltage reduction was expected, since the main intent of the
transformer optimization was to lower subtransmission voltages for
light load conditions. After implementing he capacitor optimization
the bus voltages in
th i s
area were brought back o their original on-
peak voltage levels (curve “FINAL“). Therefore, the effect of the
capacitor optimization in
t h i s
area was to offset the transformer tap
changesrequired o lower light load voltage levels.
C. Summary
Figure 7
summarizes the supply of reactive compensation on the
OE system comparing the components for the original study system
with the study recommendations. The MVArs supplied from
generation. line charging and distribution line capacitors remains
essentially unchanged. The MVArs supplied from substation
capacitors increased by approximately
38%
while the system net
MVAr ipterchangedemead by appmximately34%.
Although net reactive import reduction could not be specified
as
a
constraint in the optimization, t was a study objective and monitored
for all cases in the study. The net reduction in reactive imports was
viewed
as
a positive benefit resulting from the optimized transformer
tap settings and reactive allocation.
The above reactive additions combined with the recommended tap
setting changes results in a transmission system voltage profile within
the specified criteria. Figure 8 globally demonstrates the tighter
operating voltage band achieved by implementing the study
recommendations. The horizontal axis ndicates the operating division
and voltage class while the vertical axis indicates the per unit voltage
level based on nominal voltage for each area. The maximum light load
and minimum on-peak voltage in each
area
are
shown with the
“0‘s”
corresponding to the levels without the study recommendations and
the “x’s’’ corresponding o the evels with the study recommendations.
In general, light load voltages were reduced while on-peak voltages
wereraised
to
establish the desired tighter operating voltage band.
The sensitivity of the study objectives to increasing the reactive
compensation beyond the recommended level was also evaluated.
Figure 9 summarizes he effect of the transformer tap setting changes
and various levels of reactive additions on losses and reactive imports.
The horizontal axis ndicates the specific study case with respect to tap
changes and amount of reactive compensation on the system. The
verticalaxis on the left indicates the percent change
in
losses from the
original base case while the vertical axis on the right indicates the
percent change in reactive imports. Along the horizontal axis, the
second “0”point demonstrates the effect of no change
in
the amount
or placement of reactive compensation with the recommended
transformer tap changes. Active and reactive losses changed slightly
and reactive
imports
were reduced. However, the voltage profile for
this case does not meet the specified criteria. The next point (-57)
represents a reduced level of reactive compensation
-57 MVAr ,
although the compensation was optimally sized and located. The
active and reactive losses. reactive imports and voltage profile were all
essentially unchanged from the previous case. These two simulations
confirmed the need for
additional
eactive compensation o meet the
voltage requirements for the peak oad system.
4 0 0 0 ~
RECOMMENDED
Figure 7 Component of MVArs.
AREA VOLTAGE RANGES
BEFORE AND AFTER STUDY RECOMMENDATIONS
H I G H E S T A N D L O W E ST
OFF
AND ON-PEAK VOLTAGES
l T-------
A23 B23 C23 A69 869 C69 D69
E69
F69 G69 H69
69 J69
D I V I S I O N A ND V O LT A GE L E V E L
,g
______~
+-O r i g i n a l R a n g e +-
x N e w R a n g e *
Figure
8 .
Area voltage ranges.
ON-PEAK SYSTEM CASE SUMMARY
D E V I A T I O N
FROM
O R I G I N A L
I
I
-8J ‘ 50
0 0
-57
1
NEW
TAPS
RIGINAL
TAPS
A P P R O X I M A T E A D D E D C O M P E N S A T IO N M V A R S )
Figure 9. On peak system case
summary
-
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6/6
227
The next point (223) represents the effect of the recommended
reactive allocations. The active and reactive losses and reactive
imports were all reduced and the voltage profile was within the
specifed
criteria.
The last point (388) represents anincreased evel of
optimally located capacitors. Active andreactive losses and reactive
imports
are
further reduced whilethe voltage profile r e d s imilar
to
the recommended
case
Thewresults indicate hat
additional
increases
in reactive compensation would have little effect on voltage control,
however active and reactive losses and reactive imports would
be
redUCed.
The final study recommendations for transformer tap setting
changes and capacitor bank additions result in
a
number of
improvements to overall system performance including:
The transmission system voltage profile has generally been
Improvement in quality of service to transmission and
ultimately distribution customers because of improved voltage
control and reduced range.
Active power losses reduced by 1.3% (approximately
8Ooo
M w h annually).
Reactive power losses reduced by 4.3%.
Reactive power imports reduced by 34.3%.
impr~ved a n p e a koadingand light loadperiods
The estimated capital equiyalent savings of the reduction in active
power losses represents approximately 80%
of
the capital cost of
implementing the shdy recommendati ons
The study also identified several issues for further review and an
additionalfollow
on
study:
A review of voltage
limits s
to be made for
three
isolated 23 kV
systems in order to finalize he associated ransformer tap
settings
and
capacitor bank recommendations. Optimization of the voltage
schedules for localized generation and synchronous condenser
facilities may enhance voltage control in
some
areas of the
23
kV
system. This could eiiminate the need for some of the associated
preliminary transformer tap setting and capacitor bank
recommendations.
Some of the 69 kV capacitor bank recommendations at
distribution substations exclusively serving radial load may be
implemented more cost effectivelywith distribution line capacitorson
the distribution circuits. Equivalent levels of compensation can be
installed more economically at the distribution level because of the
lower voltage rating and the lower distribution substation ransformer
losses.
When generator operating capabilities have been finalized, the
system voltage schedules can then be reviewedwthrespect to further
optimization and loss reduction.
C O N C L U S I O N S
This
study has effectively denNied ms fo rmer tap changes and a
capacitor replacement and addition program whichwill improve the
overall transmission and subtransmission voltage profile, reduce
system losses and reduce the net reactive system imports. The
recommendations have been limited to the
areas
of transformer taps
and capacitors, which can readily be implemented for improving
system performance.
The recommendations include several areas that require fur ther
review to ensure the most effective and economic implementation or
the needed system improvement in this area. Some distribution
substation capacitor banks are under review to determine if a
comparable level of compensation
to
the transmission system can be
more economically and effectively implemented by applying the
compensation on the distribution lines. Several of the 138-23 kV
transformer tap and 23 kV capacitor bank recommendationsare also
being studied further.
The study was conducted in such a way that later optimization of
the generator terminal voltage schedule may be an effective option for
further controlling voltage and reducing the net reactive system
imports. When the capabilities of the generating units have been
verified k u g h ield tests,
their
voltage schedules will bereviewed to
determine if further improvements
in
voltage control, system losses
and net reactive mports can be achieved.
REFER
ENC
S.A. Miske, Jr., W. Neugebauer, D.J. Ward, “A Systems
Approach
t
the Replacement of Older Substation Capacitors,”
mesented at the 1988 American Power Conference, Chicago
r ~
Illinois, April 1
R.C. Degeneff, W. Neugebauer, C.H. Saylor, S.L. Corey,
“Security-Constrained Optimization: An Added Dimension in
Utility Systems Optimal Power Flow,” IEEE Computer
Applications n Power, October 1988.
R.C. Burchett, H.H. Happ, R.E. Palmer, D.R. Vierath,
“Quadratically Convergent Optimal Power Flow,” IEEE
Transactions Power Amaratus and Systems, Volume 103, NO.
.~~
11,
1984, pp. 3267-3f3 .
W.C. Merritt, C.H. Saylor, R.C. Burchett , H.H. Happ,
“Security Constrained Optimization A Case Study,” IEEE
Transactions on Power Systems, Volume 3, No. 3, 1988, pp.
970-977.
P.E: Gil , W. Murray, and M.H. Wright,
h W . i d
- Academic Press, 1981.
P.M. Anderson, ted Power S y w n s , The Iowa
State University-73 pp. 262-264.
W.D. Stevenson, Jr., Elements of Power S u e m s hdYdS
McGraw-Hill, Inc., 1982, pp. 216-218.
Robert D’Aquilo was bom in Queens, New York in 1962. He
received his B.S. and
M S
degrees from Clarkson University in
Electrical Engineering in 1984 and 1985, respectively.
In
1986Mr D’Aquila joined the GE Power Systems E n g h d g
Department in Schenectady, N.Y. He has been involved in
transmission planning and design projects and the development of
power system analysis software. He is currently involved in the
analysis of reactive power control and voltage stability. Before
joining GE, he was employed by Consolidated Edison Company,
New York, N.Y. where he worked in the areas of transmission
planning and system operation.
Dennis A. DiMascio is a Senior Transmission Planning Engineer
in the Transmission Planning Section of the Advanced Engineering
and Planning Department at Ohio Edison Company. He received
his
BSEE
and BA in Mathematics rom the University of Akron n 1965.
He is also a 1972 graduateof the WestinghouseAdvanced School of
Power System Engineering. Before his present job assignment, he
worked
as
a substation design engineer and in equipment application
engineering of power circuit preakers and synchronous motors. He
has been a member of IEEE since 1966 and served as Chairman of
Akron Section Power Group and as a member of the Synchronous
Machinery Subcommittee. He is a registeredProfessional Engineer n
the Stateof Ohio.
Carl Bridenbaugh was bom in Port Huron, Michigan
in
1960. He
received his BSEE from the University of Derroit in 1983and his MS
in Electrical Engineering from Union College
in
1985. He also
graduatedfirom the GE Power Systems EngineeringCourse n 1985.
In 1983,Mr.Bridenbaugh joined the GE Systems Development
and Engineering Departmentin Schenectady,N.Y. as an Engineer on
Rotation involved in all aspects of power system engineering and
economic studies.
In
1986 he became
an
Application Engineer,
performing power system dynamic studies and developing computer
models of power system components for
use
in dynamic performance
analysis. In 1989 he joined the Ohio Edison Companyin Akron,
Ohio as a Planning Engineer in the Transmission Planning Section
of
the Advanced Engineering and Planning Department. He is currently
involved in both long and short range studies of the transmission and
subtransmission system.
Mr Bridenbaugh is a member of I and is Treasurer of the
Akron
Chapter of the
I
Power Engineering Society. He holds a
ProfessionalEngineering Licehse in the states of New York and Ohio.