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Power Factor Correction – A Fresh Look Into Today’s Electrical Systems
Christopher Heger
P.K. Sen
Anthony Morroni
Member, IEEE
Carollo Engineers, Inc.
10822 W. Toller Drive, Suite 200
Littleton, CO 80127
[email protected]
Fellow, IEEE
Colorado School of Mines
1610 Illinois Street
Golden, CO. 80401
[email protected]
Member, IEEE
Carollo Engineers, Inc.
10822 W. Toller Drive, Suite 200
Littleton, CO 80127
[email protected]

Abstract -- Poor power factor in an industrial plant can lead
to low energy efficiency, unacceptable voltage regulation, larger
equipment size, and potential damage to plant equipment when
not corrected properly. The most common and inexpensive way
to correct power factor in an industrial application is by
supplying reactive power with a capacitor bank. However, other
application issues must be considered when capacitance is added
to the system. This paper takes a fresh look at an old
application, focusing on the potential issues with power factor
improvement capacitors, available power factor correction
methods, and design considerations for implementing these
technologies in today’s modern power systems.
Index Terms—Active filter, apparent power, de-tuned
capacitor, harmonic resonance, power factor, power factor
correction capacitor, power quality, reactive power.
I.
INTRODUCTION
Power quality has always been a major concern in any
electrical power system design. Power Factor (PF) is one of
the measures of the overall power quality and must be
considered in a system that has a large amount of capacitance
or inductance. Poor PF can lead to excessive current
requirements and may also cause operating issues with
electric generators, transformers and the distribution system.
It makes the electrical system less efficient, and has the
potential to damage the machines. To accommodate these
issues, various devices are used to balance the reactive power
being provided or absorbed.
To date, the most common way to improve a poor
“lagging” PF in any plant is to install “PF improvement
capacitors”. This method is a time proven means for
correction provided at a reasonable cost and with typically
good reliability when there were not many non-linear loads.
However, modern electrical systems design concepts as well
as advancements in power electronic technologies may shift
the design philosophy for implementing PF correction.
II.
POWER FACTOR CORRECTION
There are different forms of PF that must be considered,
displacement PF and total PF. Displacement PF (cosθ), as
shown by the power triangle and equation in Figure 1 is the
relationship between the real power (P), in Watts (W), and
the apparent power (S), in Volt-Amp (VA), of the
fundamental wave. The remaining side of the right-angle
triangle is the reactive power (Q), in Volt-Amp-Reactive
(VAR). Total PF is the relationship between real power and
apparent power when including the distortion affects of
harmonics. Because total PF is always changing based on the
harmonics in the system, it is difficult to track at all operating
conditions, and basic metering equipment cannot accurately
measure it. As such, the PF generally referred to in electrical
discussions as well as this paper is displacement PF.
However, it will be noted throughout the paper when total PF
may be applied.
In an ideal electrical system where the PF is 1.0 (i.e.,
θ = 0), the apparent power is equal to real power (no reactive
power) so the system is providing the minimum current to
produce the same amount of work and operate the load. At
this point, the system is at its peak performance. In the
situation where the PF is other than 1.0, the apparent power is
greater than the real power and the current required to
perform the same amount of real work (W) is higher than if
the PF is 1.0. This increase in current results in increased
sizing of the power system (transformers, cable, overcurrent
protection, etc.) as well as increased copper losses (I 2R) in the
system.
Fig. 1. Power triangle
The copper losses increase by the square of the current;
therefore, an increase in current results in significantly more
power loss.
Two common equations for calculating the loss in a
3-phase system (for a given resistance R) are:
𝑃𝑙𝑜𝑠𝑠 (𝑊𝑎𝑡𝑡𝑠) = (
𝑃 (𝑊𝑎𝑡𝑡)
√3×𝑉1 ×𝑃𝐹
2
) × 𝑅 (𝑂ℎ𝑚)
(1)
And
𝑃𝑙𝑜𝑠𝑠 (𝑊𝑎𝑡𝑡𝑠) = (
𝑆 (𝑉𝐴) 2
√3×𝑉1
) × 𝑅 (𝑂ℎ𝑚)
(2)
Where, V1 is the line voltage (V).
The copper power loss increase in percent at any leading
or lagging power factor compared to 1.0 PF is given by
equation (3). The function of the copper loss equation is
depicted in Figure 2:
1
2
∆𝑃𝑙𝑜𝑠𝑠 (%) = ( ) − 1
𝑃𝐹
(3)
Fig. 3. Power factor penalties at 0.90 or 0.95 PF limit
In this example the cost of the power losses due to system
resistance were calculated based on $0.10 per kWh. The
analysis shows that the cost associated with a poor PF may
not always be substantial in regards to an electric bill.
However, the case study presented later in this paper shows
that a PF correction system often presents the ability to pay
for itself within a few years of the installation. Therefore, the
added benefits of operating at a higher efficiency and the
slight cost reduction in the electric bill may justify the means
for adding PF correction to an electrical system.
III. POWER FACTOR CORRECTION TECHNIQUES
Fig. 2. % Copper loss vs. power factor
Due to the costs associated with energy, today’s power
systems must be designed to maximize energy efficiency.
Applying the values from Figure 2 above, a PF of 0.9
increases the energy costs associated with losses by a factor
of approximately 1.23, whereas a PF of 0.7 more than
doubles the cost associated with the system copper losses.
Another cost associated with poor PF is the penalties
imposed by the utilities as part of their demand side energy
management. If a consumer’s meter ever reads outside of the
acceptable PF (typically 0.95), the electric utility assesses a
penalty consistent with the utility’s rate structure. Not all
utilities are charging for poor PF, but for those that are not
yet enforcing PF penalties; they do have plans to begin
implementing penalties in the near future.
An example of a PF penalty that one utility has adopted
increases the customer’s demand charge by 1% for every 1%
the customer is outside of the predetermined PF limit. The
following calculations, applied to a hypothetical facility,
demonstrate the costs of the PF penalty and the additional
system losses. Applying the demand charges of
approximately $5 per kW and efficiency losses to a facility
with an average operating load of 750 kW, the potential costs
associated with a poor PF are displayed in Figure 3.
There are three commonly used techniques employed in
industrial plants. The following section provides a
comprehensive discussion and addresses the application
issues.
A.
Shunt Capacitors
Shunt capacitors have been and continue to be the most
cost effective way for correcting displacement PF. The best
way to visualize how capacitors correct PF is by using the
(self-explanatory) power triangle shown in Figure 4 below.
Fig. 4. Addition of capacitance to correct a 0.8 PF to a 0.95 PF
The advantages of this form of PF correction include the
relatively low cost, small footprint, and ease of application.
This form of PF correction is typically viable for linear power
systems.
The disadvantages of this form of PF correction surface
when the power system has many non-linear (harmonic
generating) loads that when combined with the PF correction
capacitors may result in a periodically destructive issue,
resonance. Electrical resonance occurs at some multiples of
the natural frequency when the reactance between a parallel
capacitance and an inductance, or a series capacitive
reactance and the inductive reactance are equal. When this
condition is reached, excessive current will flow throughout
the system thereby increasing the voltage to a higher level.
Two potential resonance conditions can occur; 1. When
motors are started or stopped, 2. when the power system
contains harmonics with a frequency that is a multiple of the
natural frequency resulting from the capacitance and
inductance in the power system.
1) Motor Over Excitation Caused by Capacitors
PF improvement capacitors are often placed at or near the
motor terminals to maximize the effect. If the capacitance is
too large, there is a potential for the capacitor current to be
equal to the magnetizing current drawn by the induction
motor either during operation or during the starting or
stopping of the motor. This creates a resonant condition and
an excessive voltage at the terminals of the motor [1].
This is illustrated in Figure 5 where capacitor currents are
overlaid with the motor magnetizing curve. This Figure
demonstrates the effects of a properly sized capacitor versus
an oversized capacitor that may cause damaging overvoltages on the conductor insulation or excessive currents.
When the voltage is at a nominal level of 460 V, the
oversized capacitor is drawing more reactive current than the
motor magnetizing current. When the motor is turned off, the
motor reactance decreases to the reactance of the oversized
capacitor, and a resonant point will exist. At this resonance
point, a potential current and voltage results at the point
where the capacitor curve crosses the magnetizing line of the
motor. Therefore this Figure helps to illustrate how the
oversized capacitor may cause damaging over-voltages on the
conductor insulation or excessive currents.
To resolve this issue, the motor manufacturer must be
consulted to determine maximum allowable PF correction
capacitor size. As long as the installed capacitor is less than
the maximum permitted kVAR, there should not be any
issues, as demonstrated by the smaller capacitance where the
capacitor curve does not exceed the rated motor voltage on
the motor magnetizing current curve.
2) Harmonic Resonance
Harmonic currents and voltages are generated at multiples
of the fundamental frequency (60 Hz). Non-linear loads such
as variable frequency drives (VFDs), computers with
switching power supplies, lighting ballasts, and other power
electronic circuits are typically sources of harmonics. In
today’s power systems, non-linear loads are more prevalent
as power electronics become smaller, less expensive, and
offer higher reliability. As a result, today’s power systems
must support a significant amount of harmonics.
Harmonics are associated with the additional heating they
cause leading to premature failure of equipment and reduced
system reliability. However, they also cause resonance issues
within a power system that has the unfortunate match of
capacitance and inductance.
The following equations demonstrate that the reactance of
a capacitor (Equation 5) and an inductor (Equation 4) are
frequency dependent. At the fundamental operating
frequency, there may not be a resonance issue. But when
currents are produced at other frequencies, i.e. harmonics, the
impedance of the inductors and capacitors will change. When
the inductive reactance and the capacitive reactance are equal
at a particular frequency, an excessive current may flow
through the capacitor and inductor.
𝑋𝐿(𝑂ℎ𝑚) = 𝑗2𝜋𝐿𝑓
𝑋𝐶 (𝑂ℎ𝑚) =
−𝑗
2𝜋𝐶𝑓
(4)
(5)
Where L is the inductance in Henry and C is the
capacitance in Farad.
There are several ways to determine if there is a potential
resonance issue in an electrical power system. Equation (6)
calculates the harmonic resonance frequency (hr) at a given
point based on the short circuit (fault) MVA and the 3-phase
capacitor bank MVAR rating.
𝑀𝑉𝐴
𝑆𝐶
ℎ𝑟 = √
𝑀𝑉𝐴𝑅
(6)
𝐶𝐴𝑃
Fig. 5. Motor magnetizing curve [6]
If the power system has harmonic frequencies that are on
the order of the 5th, 7th, etc., then modifications are needed
to avoid a resonance condition. This is because of the
typically high magnitudes of voltage and current that is
experienced at these lower order harmonics. The
disadvantage to this quick calculation is that it will not
always detect a resonance issue because the system
characteristics determining the short circuit MVA are always
changing.
An alternative means to determine a resonance condition
is through computer modeling. Using a computer-based
model can sometimes be a relatively quick way to evaluate a
power system, and it offers the ability to easily change the
system operating parameters. In many cases, the model is
often readily available because the system parameters and
base model is used for other evaluations such as fault
calculations, load flow, and arc flash studies. The model
generates a frequency scan which determines the system’s
equivalent impedance at each frequency. Using this
information, the potential resonant frequencies can be
determined.
One caution in designing PF correction for an electrical
system is how the capacitors are utilized. If the capacitors are
distributed (located at each motor), it becomes extremely
difficult to determine a potential resonance condition through
modeling, because as motors turn on and off, the system
parameters are changing. When looking at a system with
three motors of different sizes, there are potentially 7
different operating scenarios. If this concept is applied an
entire facility with many loads, the number of operating
conditions is only limited by the number of individual loads.
So it quickly becomes unrealistic to model all potential
operating conditions.
For a system that contains varying harmonics, the more
practical means for providing PF correction capacitance is by
adding an automatic switching capacitor bank at one point in
the system. To prevent too much or too little capacitance, the
VAR rating of the automatic switching capacitance is varied.
This is accomplished by opening and closing contactors
based on continuous metering of the system PF.
One disadvantage to harmonics is that they are sometimes
said to be self-correcting. If an operating system experiences
a resonant condition, the system will self-correct by blowing
a fuse, or worse, by destroying the equipment. To correct a
resonant condition by other means than destruction, the
system inductance or capacitance characteristics must be
changed. This correction can be done by reducing or
increasing the capacitance or by de-tuning the resonant
frequency with a passive filter. Adding a tuned filter
(consisting of an inductor and capacitor circuit), can shift the
resonant point to a slightly different frequency than the
resonant harmonic. For example, if the correct PF correction
capacitor resulted in a system resonance point at the 11th
harmonic, and the power system had 11th harmonics present,
then a filter could be designed to provide the required
capacitance but detuned to the 10.7th harmonic. Thus
avoiding the resonant condition by shifting it to a harmonic
that does not naturally occur.
To effectively apply the detuned filter to the system for PF
correction, it will need to be applied to all capacitors within
the system. If the capacitors are distributed, then this
continues to lead to the complication of accurately designing
filters and capacitors for all operating scenarios. If there is a
single automatic switching capacitor bank, then it too will
need a detuned filter to avoid resonance issues. If the lumped
bank is actively controlled, then the detuning filter will also
need to be actively controlled so it can ensure that the system
resonance point is not at an integer multiplier of the
fundamental frequency. This process effectively detunes the
filter throughout the operating range of the actively varying
capacitor bank.
Caution must be taken when detuning a capacitor because
by removing a resonant condition at one frequency, it may
cause a resonant condition at another frequency. To avoid
this, it is recommended to always detune at high magnitude
low harmonic orders such as the 5th or the 7th harmonic.
These are common harmonics that create a relatively large
magnitude of current, so even if the resonant condition isn’t
at the 5th or the 7th harmonic, the reduction in current can
reduce the stress in the system [3].
B.
Active Filter
An advanced method of improving the power quality of a
system is by using an active filter. An active filter uses the
same components and general theory of a VFD, but rather
than providing a clean sine wave to the system, and active
filter purposely injects harmonics and/or reactive power into
the system as required to meet the desired power quality.
Because the active filter is continuously monitoring the
system power quality and actively injects reactive power, it
not only corrects displacement PF, but it can also correct total
PF for a complete system PF improvement. An example of a
typical system design is shown in Figure 6 below.
Fig. 6. Active filter wiring diagram [2]
The active filter is installed in parallel with the electrical
system and injects current based on an algorithm where the
process variable is the current measurement downstream of
the active filter. A diagram of this arrangement is shown in
Figure 7 where the active harmonic filter shown in Figure 6 is
represented by the shape labeled “AHF”. This closed loop
control offers the highest level of accuracy because the
control is based on net current measurements after the current
is injected by the active filter.
a complete system. That advantage is the natural effect that
harmonics have of cancelation. Because of this effect, the
relationship between active filter sizing and the number of
VFDs is not linear. Table 1 demonstrates this concept when
applied to a system with multiple motors. In this example, an
active filter is applied to a 125 HP motor, powered by a 6
pulse VFD with 3% line reactors. The same active filter is
then applied to 6 motors. This non-linear relationship
demonstrates why it can be more cost effective to apply an
active filter solution to the entire system as opposed to
individual loads.
TABLE I
ACTIVE FILTER SIZING [5]
Fig. 7. Active filter closed loop control [2]
A typical active filter offers three modes of programmable
control. The three modes are Harmonic Mitigation, Reactive
Power Control, and Load Balancing. Operating in any of
these modes of control requires the active filter to supply
energy into the system. Therefore, the sizing of the active
filter will depend on which operating modes will be utilized.
The filter has the ability to operate in any single mode of
operation, or it can be programmed to allocate specific
percentages of its output to the desired mode of control. For
example, 50% of the power output can be applied to PF
correction through reactive power injection, and the
remaining 50% may be applied to harmonic mitigation
through harmonic current injection.
The allocated requirements often vary based on the
amount of correction that is needed. If the harmonics are
fairly large in magnitude, but the PF is close to the desired set
point, more energy may be allocated to the harmonic
correction.
Common active filter sizes are 50 A, 100 A, or 300 A, The
value represents the amount of current the filter is capable of
injecting. Because the filters are manufactured in the standard
sizes, the applied filter is often oversized for the specific
application. The advantage of this over sizing is that if the
filter is provided specifically for harmonic mitigation, then
there is typically excess capacity for PF correction. Equation
(7) can be used to determine the amount of capacity
remaining for power quality improvement.
𝑃𝐹 𝐶𝑜𝑟𝑟𝑒𝑐𝑡𝑖𝑜𝑛 𝐼 = √(𝐴𝑐𝑡𝑖𝑣𝑒 𝐹𝑖𝑙𝑡𝑒𝑟 𝐼2 − 𝐻𝑎𝑟𝑚𝑜𝑛𝑖𝑐 𝐼2 ) (7)
When determining if an active filter should be applied to a
system, the footprint, cost, and cooling requirements must be
considered. When comparing PF correction capacitors to an
active filter, the size difference is minimal. However, the cost
of the filter and cooling requirements are quite different. The
power electronics of the active filter release a significant
amount of heat which typically requires a conditioned air
space. A further cost analysis is provided in the case study
below.
There is an inherent advantage to installing active filters to
Quantity (125
HP, VFD, 3%
Line Reactor)
Active Filter
Size if Harmonics
Are Additive
(Amps)
Actual Active
Filter Size
Required (Amps)
1
47.5
47.5
2
95
88.5
3
142.5
123.3
6
285
198.3
Caution must be taken when applying both an active filter
and a passive filter to the same system. As shown in Figure 6,
the particular system is equipped with a passive filter
containing capacitors. Because the active filter is injecting
current and essentially removing the harmonic, there will be
no harmonic currents to create a resonance issue while
operating. However, when the active filter is not operating,
the harmonic currents can resonate with the capacitance. As a
result, there is a chance that a resonant condition may exist
when the active filter is not operating.
Solutions to this potential issue is disconnecting the entire
active filter when it is not operating, or detuning the
capacitance as described earlier in the paper.
C. Combined Power Factor Correction (Active Filter and
Capacitors)
In cases where the PF is poor in large systems, a
combination of PF correction capacitors and an active filter
may yield the best results. In this hybrid system, the
capacitors becomes a base VAR support, while the active
filter plays the role of either adding VAR or absorbing VAR
to achieve a desirable PF.
A theoretical example outlining a few scenarios of how an
electrical system would function with a combination of an
active filter and a capacitor bank is outlined in the following
bullets:
• During operating periods when the load is absorbing more
VAR then the capacitor bank can provide, the active filter
would provide the necessary VAR to reach the desired PF.
• As the operating load absorbs less VAR, the active filter
would reduce the amount of VAR it provides to meet the
desired PF.
• If the load ever reached an operating point where the load
requires less VAR than the capacitor bank provides, the
active filter would absorb the excess VAR to achieve the
desired PF.
Using this hybrid system provides a significant amount of
flexibility with consistently accurate results. It also reduces
the chances of resonant conditions because the active filter is
also filtering the harmonics. However, there is a significant
cost as well as large footprint associated with using two types
of PF correction equipment. The justification for this type of
system is typically for large systems, with an extremely poor
PF to justify the high cost.
IV. A CASE STUDY – WATER RECLAMATION FACILITY
In this case study, three methods of PF correction are
reviewed.
1) Distributed PF Correction Capacitors
2) Lumped PF Correction Capacitor, and
3) Active Harmonic Filter (Utilizing the reactive power
compensation mode)
The water reclamation facility receives power from the
utility at 13.2 kV with approximately 4,467 A of available
fault current, and is stepped down to a 480 V distribution
voltage via a 1500 kVA transformer. The distribution system
consists of main switchgear that provides power for 4 motor
control centers. The combined connected load of the facility
consists of 1,090 HP on 6 pulse VFDs, 200 HP across the line
starting capability, and approximately 500 kVA of
miscellaneous building loads.
A.
Distributed Power Factor Correction Capacitors
The original design for PF correction was to apply PF
correction capacitors at each motor greater than or equal to 5
HP. This is the standard that has been in effect at other
facilities and has proved to offer an acceptable PF. The total
purchase cost of the capacitors was $3,800 to provide
55 kVAR to 18 motors. The required footprint is negligible
since the capacitors are installed above the MCCs. While this
appeared to be a reasonable means for PF correction that can
pay for itself within a few years, the plant encountered issues
with the fuses blowing on certain capacitors during facility
start-up.
Initial investigation suggested the possibility of oversized
capacitors as well as harmonic resonance. A simple field test
was performed. In this test, all of the large non-linear loads
were turned off (all VFDs), and the loads that had issues with
their PF correction capacitors were started. Under these
conditions with the non-linear loads not operating, the PF
correction capacitor fuses did not fail. Subsequently, after the
non-linear loads were turned on, the fuses failed quickly. The
conclusion was that fuse failures were due to harmonic
resonance triggered by the VFDs and not from oversized
capacitors.
The next step was to determine if the resonant condition
could be corrected without the capacitor fuses blowing and
disconnecting the capacitors. Using the fault current and
connected capacitance in Equation (6) predicted harmonic
resonance between the 70th and 115th harmonics. This did
not prove the case for harmonic resonance because at these
high harmonic frequencies, the current magnitudes are
extremely small.
The next attempt to prove the harmonic resonance was to
model the electrical system with the assistance of a
commercially available distribution software package.
Utilizing the frequency scan feature using the same operating
conditions utilized under the field test provided the graph
shown in Figure 8 below.
Fig. 8. Frequency scan
The frequency scan suggested a potential resonant
condition at approximately the 26th harmonic, which
indicates a potential resonant condition. However, the
resulting resonant current through the capacitor did not justify
the blown fuses. What this analysis revealed is that even
though the system was modeled, and harmonic resonant
conditions were calculated, the calculation cannot effectively
show every condition where resonance may exists. The
reason is that there are too many operating conditions that
must be modeled to determine the condition that caused
resonance.
It was concluded that the solution to this particular case
was to disconnect all the system capacitors to ensure that the
stresses caused by the system resonance did not lead to any
damage from overstressing the equipment. The plant then
must measure their facility PF at different operating points
and determine if any of the following technologies are
desired to correct their PF.
B. Automatically Switched Power Factor Correction
Capacitor
The solution of adding a single automatically controlled
capacitor bank at the main switchgear location to compensate
for the facility’s PF was considered. Because this solution
utilizes capacitors, system harmonic resonance must be
evaluated. When applying the short circuit calculation, the
VAR rating of a capacitor bank turned out to be much larger
than when capacitors applied to the individual motor loads.
This is because the added capacitors will also be correcting
the PF for the small motor loads and other miscellaneous
loads throughout the facility. With an average operating load
of 750 kVA, the resultant KVAR required to meet the desired
overall PF of 0.95 is 125 kVAR.
The initial model revealed various harmonic resonance
potentials depending on the size of the actively connected
capacitors. Since the capacitor bank varies in the amount of
connected capacitance in 25 kVAR steps to achieve the
desired PF, any type of detuning that is applied to the bank
will also require the capability of varying the filter
components to properly detune.
For this example, a specific random snapshot operating
condition of the facility is used. The expected resonant
condition is modeled at the 17th harmonic. The detuning
filter (series inductor to the PF correction capacitor) can be
properly sized using the computer program. As discussed
earlier, even though the resonant condition may exist around
the 17th harmonic, the targeted frequency for detuning is
often at a lower harmonic so that another resonant condition
is not created. In this case, the targeted harmonic is the 11th.
As shown in the frequency scan graph shown in Figure 9, the
detuned filter frequency created a resonant condition just
below the 11th harmonic. In the electrical system, there are
not any natural voltages or currents at this frequency, so the
resonant concerns are reduced.
The cost of the lumped, de-tuned capacitor bank is roughly
$12,500. Compared to the distributed capacitor installation,
the lumped capacitor is around 3 times more expensive, but
can more effectively reach the desired PF for the facility than
the distributed capacitors. This is because the distributed
capacitors do not account for the poor PF of approximately
500 kVA of miscellaneous building loads. The de-tuned
lumped capacitor further protects the system from potential
resonance problems.
Fig. 9. Detuned frequency response
The large capacitor bank cannot be placed above the MCC
similar to the distributed capacitors. For this example, the
dimensions of the capacitor bank are approximately
30”Wx36”Dx90”H. Therefore, additional square footage and
cabling must be considered when making an economic
comparison.
C.
Active Filter Reactive Power Compensation
To apply the active filter, it is recommended that to get the
most benefit, they be placed as close to the load as possible.
However, this approach proves to be very costly since
multiple active filters would be required. Therefore, two
installation methods were considered, (i) one filter at the
switchgear, and (ii) one filter at each of the four MCCs.
To size the active filter a software package was utilized.
The software looked at many system parameters including the
number of loads on VFDs, the harmonics produced by VFDs,
and the amount of motor load not on VFDs. The software
determines the amount of harmonic distortion, as well as the
system PF in order to determine the amount of correction the
system requires.
In this case study, there are passive harmonic filters for
each of the large 250 HP motor loads, so the system
harmonics meet the recommendations of IEEE519.
Therefore, the software concluded that none of the active
filter’s capacity needs to be reserved for harmonic mitigation.
The software also concluded that because a majority of the
motor load is on VFDs, the system PF requires minimal
compensation to meet the facilities set point of 0.95.
Therefore, the recommended unit size when either applied at
the switchgear, or when applied at each individual MCC is
the smallest unit commonly offered at 50A.
Applying one filter at each MCC would quadruple the cost
for this particular installation. The main purpose for the
active filter is PF correction opposed to harmonic mitigation.
Because the proximity is not as important for PF correction,
and the smallest available unit is sufficient for either
application, applying one active filter at the switchgear was
recommended.
A single 50A active filter is approximately $30,000. This
solution offers the most control, the possibility of harmonic
mitigation, the possibility of correcting PF for future loads,
and possibly better results for the overall electrical system
performance.
The final consideration for this installation is the footprint.
The dimensions for unit is approximately 31.5”W x 23.8”D x
75”H. When comparing the automatically switched capacitor
approach to an installation of a single active filter, they are
approximately equal in size.
D. Case Study Conclusion
Because a large portion of motor load is on VFDs, the
original overall PF for the system was relatively good (at 0.89
lagging). The economic analysis presented in Table 2 shows
that the pay-back for implementing either the lumped
capacitor or the active filter is difficult to justify when the PF
limit is at a 0.9. However, when the utility PF correction
requirements become more stringent (a 0.95 limit opposed to
the current 0.9 limit), the economic payback is significantly
reduced. At that time, the evaluation shows that both the
lumped capacitor solution as well as the active filter solution
may be viable.
TABLE II
CASE STUDY COST ANALYSIS
Power
Factor
Correction
Option
Distributed
Capacitors
Lumped
Capacitor
Bank
Single
Active Filter
Multiple
Active
Filters
$3,800.00
Payback
with a 0.9
Limit
(Years)
8.4
Payback
with a 0.95
Limit
(Years)
1.1
$12,500.00
27.8
3.6
$30,000.00
66.7
8.7
$120,000.00
266.7
34.6
Equipment
Cost
V.
CONCLUSION
Poor PF in any power system operation is not only
undesirable, but it can cause serious issues that lead to
additional consumer costs when not corrected properly. In
today’s power systems, common and more traditional
methods of applying PF correction by using shunt capacitors
must be reconsidered. More harmonic generating devices are
present in modern electrical systems and special
consideration should be taken into account when designing
PF correction systems. Factors such as system resonance, PF
penalties in the utility billing, and the flexibility of the PF
correction systems greatly influence the justification of the
type of PF correction and must be applied in a case by case
basis.
REFERENCES
[1] “Self-Excitation Concerns with PF Correction on Induction Motors,”
Northeast Power System, Inc., 1999-2009, www.nepsi.com. [Accessed:
September 25, 2011]
[2] “Energy Efficiency and PQ Solutions – Americas EE Consultants
Training”. Presentation, Schneider Electric, Denver, Colorado, 2010.
[3] IEEE Recommended Practice for Industrial and Commercial Power
Systems Analysis, IEEE Std. 399 (Brown Book), IEEE, Piscataway, NJ,
1997.
[4] IEEE Recommended Practices and Requirements for Harmonic
Control in Electrical Power Systems, IEEE Std. 519, IEEE, Piscataway, NJ,
1992.
[5] Personal Communication, Jim Johnson, July 2011.
[6] IEEE Recommended Practice for Electrical Power Distribution for
Industrial Plants, IEEE Std.141 (Read Book), IEEE, Piscataway, NJ, 1993.