Harmonic Issues Related to Power Factor Correction

Published by Electrotek Concepts, Inc., PQSoft Case Study: Harmonic Issues Related to Power Factor Correction, Document ID: PQS0604, Date: April 1, 2006.

Abstract: Power factor correction is an important facet of power quality. Capacitors may be installed on customer systems to minimize charges for poor power factor on their electric bill. These installations may create problems by altering the harmonic frequency response of the network or introducing transient disturbances during their energization. This case study presents an overview of the impact of power factor correction on harmonics issues, such as resonance.

INTRODUCTION

Electric utilities and their customers have long been concerned with power quality. The need for constant voltage and frequency has always been recognized. However, recent trends toward energy conservation, the increasing utilization of power electronic loads, and the proliferation of sensitive electronic equipment are changing the definition of what is meant by “constant voltage.” The primary reasons for the growing concern include:

− Load equipment is more sensitive to power quality variations than equipment applied in the past. Many new load devices contain microprocessor-based controls and power electronic devices that are sensitive to many types of disturbances.

− The increasing emphasis on overall power system efficiency has resulted in a continued growth in the application of devices such as high-efficiency adjustable-speed motor drives and shunt capacitors for power factor correction to reduce losses. This is resulting in increasing harmonic levels on power systems and has many people concerned about the future impact on system capabilities.

− Increased awareness of power quality issues by the end users. Utility customers are becoming better informed about such issues as interruptions, sags, and switching transients and are challenging the utilities to improve the quality of power delivered.

− Many things are now interconnected in a network. Integrated processes mean that the failure of any component has much more important consequences.

HARMONIC RELATED ISSUES

Harmonics can cause equipment to misoperate, capacitor banks to fail, breakers to trip mysteriously, but in general, the electric power system has the ability to absorb substantial amounts of harmonic current with surprisingly little or no impact on connected equipment. Real problems from harmonics are usually confined to locations with high amounts of nonlinear, harmonic current-producing loads or power factor correction capacitors. Examples of this include a wastewater treatment plant where the entire load may be comprised of adjustable-speed motor drives powering pumps, or situations where power factor correction capacitors on the customer system or at the utility distribution level create resonances that amplify the effects of nonlinear loads.

Figure 1 shows how a distorted harmonic waveform can be represented by a series of sine waves. In the figure, only the fundamental frequency, the fifth harmonic and the eleventh harmonic sine waves are shown along with the resultant waveform. This resultant is starting to look like the distorted wave at the left. If all the frequency components are added in, the resultant will be the same as the waveform at the left.

Figure 1 – Example of a Harmonic Representation of a Distorted Waveform

Almost all harmonic distortion problems occur when a resonant frequency exists near the 5th or 7th harmonics (11th or 13th harmonics can also be a problem if a large percentage of the load is nonlinear). Simple calculations can be used to estimate the system resonant frequencies. Existence of resonances near characteristic harmonic frequencies of loads that have been identified as harmonic sources is an early indication of potential trouble.

Distorted currents, and the distorted voltages they create as they flow through system impedances, can reduce equipment operating reliability and service life. Potential problems include the following:

− Failure of power factor correction capacitors. The presence of power factor correction capacitors in a facility greatly increases the potential for harmonic problems. A capacitor can cause the system to resonate near a harmonic frequency resulting in high voltage and/or current distortion that can destroy the capacitor or cause nuisance capacitor fuse/breaker operations.

− Equipment misoperation. Circuit breakers, adjustable-speed drives, programmable logic controllers, and other equipment employ control circuits that may not operate correctly in a distorted environment. Distortion of the equipment supply voltage may cause inaccurate measurement of control input signals. It can produce multiple zero crossings per cycle of the input signal waveform, causing crossing detectors to malfunction. Typical problems include clocks running fast, hunting and oscillation in motor speed control systems, and circuit breaker failure to trip or nuisance trips.

− Overheating of transformers. Transformer core losses and other stray losses vary roughly with the square of the frequency of the load current. Therefore, harmonic load currents significantly increase transformer heating. This problem is most severe in dry-type transformers.

− Overloading of neutral conductors in three-phase four-wire circuits serving single-phase electronic power supply loads. As with transformers, harmonic currents increase conductor heating. However, the neutral conductor is of special concern due to the triplen harmonic currents from each phase adding in the neutral. Though balancing loads among the phases will eliminate fundamental current in the neutral, this is not true for the triplens (triplen harmonics are odd multiples of the third harmonic, e.g., 3, 9, 15, 21…). Neutral current can be approximately 70% higher than phase conductor current for circuits serving balanced computer loads.

Harmonic Resonance

The application of nonlinear loads results in harmonic currents flowing on the power system. The interaction of these currents with the system impedance determines the voltage distortion levels throughout the system. This case study presents important concepts for determining the system frequency response characteristics. Simple systems can be analyzed with hand calculations or spreadsheets. Systems that are more complicated require computer programs that can solve for the system characteristics at multiple frequencies.

Harmonic voltage distortion is a result of the voltage drop created across the equivalent power system impedance by harmonic currents from nonlinear loads. Once the characteristics of the harmonic sources have been identified, the response of the power system at each harmonic frequency must be developed to determine the impact of the nonlinear load on harmonic voltage distortion.

At any point within a power system, the equivalent impedance at fundamental frequency can be determined from short-circuit current information. At the fundamental frequency (60 Hz), power systems are primarily inductive, and the equivalent impedance is sometimes called the short-circuit reactance. The equivalent inductance may be determined using:

where:
kVφφ = system rms phase-to-phase voltage (kV)
MVA3φ = three-phase short circuit capacity (MVA)
XSC = system short circuit reactance (Ω)
LSC = system short circuit inductance (H)
ω = system frequency (rad/sec = 2*π*fsystem)

At harmonic frequencies, the impedance of the equivalent inductance may be determined using:

where:
XSCh = system reactance at harmonic h (Ω)
LSC = system short circuit inductance (H)
fh = power system fundamental frequency (Hz)
h = harmonic number

A graph of impedance versus frequency for this simple system representation would look similar to Figure 2. Real power systems are not as linear. As frequency increases, the effect of elements not included in the 60 Hz short circuit calculation, such as line and transformer capacitance and load, becomes more significant. At the lower-order harmonic frequencies, however, useful calculations can still be performed with this simple representation. With an estimate of the harmonic spectrum for the nonlinear load current, the impedance characteristic can be used to estimate the impact of the load on the voltage distortion at the point of connection.

Figure 2 – Example of a Frequency Response of a Simple Inductive System

At utilization voltages, the equivalent system reactance is usually dominated by local impedance. A good approximation for Xsc may be based on the impedance of the local step-down transformer (Xtx):

Xsc ≈ Xtx

While not precise (ignores the system impedance on the high side of the transformer), this relationship is usually sufficient to evaluate whether or not significant harmonic distortion can be expected. Transformer impedance (Ztx(%) – nameplate impedance in percent at rating) may be approximated using:

where:
kVφφ = system rms phase-to-phase voltage (kV)
MVA3φ = three-phase transformer rating (MVA)
XSC = system short circuit reactance (Ω)
Xtx = transformer reactance (Ω)

For example, for a 1500 kVA, 6% impedance transformer, the equivalent impedance on the low side (480 volt) may be approximated using:

Impact of Capacitors – Parallel Resonance

Shunt capacitors in the power system dramatically alter the system impedance variation with frequency. Capacitors are one of the most linear elements of the power system and do not create harmonics themselves. However, severe harmonic distortion can sometimes be attributed to their presence. While the reactance of inductive components increases proportionately to frequency, capacitive reactance, XC, decreases proportionately:

where:
XC = capacitor bank reactance (Ω)
C = capacitor bank capacitance (F)
kVφφ = system rms phase-to-phase voltage (kV)
MVAr3φ = three-phase capacitor bank rating (MVAr)
ω = system frequency (rad/sec = 2*π*fsystem)

For example, the capacitive reactance for a 1200 kVAr, 13.8 kV capacitor bank may be determining using:

and the reactance for a 600 kVAr, 480 volt capacitor bank may be determined using:

At harmonic frequencies, shunt capacitors appear to nonlinear loads as being in parallel with the equivalent system inductance. At the frequency where XC and XSC are equal, the parallel impedance (combination of inductance and capacitance), as seen by the nonlinear load, becomes very high. This frequency (fr) is known as the resonant frequency for that particular circuit configuration, and it may be determined using:

where:
fr = parallel resonant frequency (Hz)
LSC = system short circuit inductance (H)
C = capacitor bank capacitance (F)

An example illustration of system impedance as a function of frequency (see Figure 3) clearly shows the effect of the capacitor bank.

Figure 3 – Illustration of the Effect of Capacitors on Frequency Response

Because the inductance and capacitance are connected in parallel, this condition is known as parallel resonance. Other, perhaps more convenient, forms of this equation include:

where:
hr = parallel resonant frequency (x fundamental)
XC = capacitor bank reactance (Ω)
XSC = system short circuit reactance (Ω)
MVA3φ = three-phase short circuit capacity (MVA)
MVAr3φ = three-phase capacitor bank rating (MVAr)
kVAtx = three-phase transformer rating (kVA)
kVAr3φ = three-phase capacitor bank rating (kVAr)
Ztx% = transformer reactance (%)

For example, the resonant frequency for a 1500 kVA, 6% impedance transformer and a 500 kVAr capacitor bank may be approximated using:

where:
hr = resonant frequency (x fundamental)
Xc = capacitor reactance
Xsc = system short circuit reactance
MVAsc = system short circuit MVA (200)
MVArcap = MVAr rating of capacitor bank (0.500)
kVAtx = kVA rating of step-down transformer (1500)
Ztx = step-down transformer impedance in percent (6)
kVArcap = kVAr rating of capacitor bank (500)

A more accurate calculation would include the source impedance (200 MVA):

Xsc = Xtx + Xs

where:

Therefore, for this example, including the source impedance reduced the estimated harmonic resonance from 7.07 to 6.67. The simulation result for this case is shown in Figure 4. The impact of the source impedance will be dependent on the source strength (available fault current, also referred to as a stiff or weak system) and the size and impedance of the customer’s step-down transformer. Generally, ignoring the source impedance for an approximation of the resonant frequency is a reasonable assumption.

The high impedance at the parallel resonant frequency may result in high voltage harmonic magnitudes (and magnified current harmonic magnitudes in the resonant circuit) if the resonance corresponds to one of the harmonic components associated with the nonlinear load. It is usually a problem if the parallel resonance is close to one of the lower order characteristic harmonics (e.g., 5th or 7th harmonic). Problems have also occurred with higher frequency resonances (e.g., 11th, 13th) but they are less common.

Figure 4 – Illustration of the Frequency Response with a 500kVAr Capacitor

Impact of Capacitors – Series Resonance

Another possible system/capacitor interaction, known as series resonance, may also be a concern. The series combination of an inductor and a capacitor appears as a very small (theoretically zero) impedance at its resonant frequency. There are certain instances where a shunt capacitor and the inductance of a transformer or distribution line may appear as a series LC circuit to a source of harmonic currents. If the resonant frequency corresponds to a characteristic harmonic frequency of the nonlinear load, the LC circuit will attract a large portion of the harmonic current that is generated. For example, a customer not having any nonlinear load, but utilizing power factor correction capacitors, may in this way experience high harmonic voltage distortion due to neighboring harmonic sources.

The series resonance circuit is used to an advantage when designing harmonic filters. In this case, the series resonance is designed to occur near a characteristic harmonic of the nonlinear loads and the elements of the filter are specified to withstand the required level of harmonic current and voltage.

As indicated in the simulated frequency response characteristic, shown in Figure 5, for the series resonant circuit, a parallel resonance is also introduced at a value below the harmonic frequency of the series resonance (see previous example for a 1500 kVA, 6% impedance transformer and a 500 kVAr, 4.7th filter). The harmonic number for the new parallel resonance may be approximated using:

where:
hrnew = resulting (new) parallel resonant frequency (x fundamental)
XSC = system short circuit reactance (Ω)
Xfilter = reactance of series filter reactor (Ω)

Figure 5 – Illustration of the frequency response with a 4.7th harmonic filter

This frequency should be checked when designing filters to make sure that the parallel resonance is not introduced at a lower order characteristic harmonic. For example, installing a 7th harmonic filter may retune the system to the 5th harmonic and increase the voltage distortion level. It is generally good practice to apply filters starting at the lowest characteristic harmonic to avoid this problem.

Benefit of Applying Power Factor Correction Capacitors as Harmonic Filters

When mitigation of harmonic distortion is required, one of the options is to apply a filter at the source of harmonics, or at a location where the harmonic currents can be effectively removed from the system. The most cost effective filter is generally a single-tuned passive filter and this will be applicable for the majority of cases. Filters must be carefully designed to avoid unexpected interactions with the system.

The need for filters is often precipitated by an adverse system response due to the addition of power factor correction capacitors, resulting in resonance. These adverse system responses to harmonics can be modified by changing the capacitance or the reactance. Two methods that require the addition of intentional reactance are:

− Adding a shunt filter. Not only does this shunt troublesome harmonic currents off the system, but also it completely changes the system response, often, but not always, for the better. This is the most common type of filtering applied because of economics and that it tends to smooth the load voltage as well as remove the current.

− Adding a reactor to the system to simply tune the system away from resonances. Harmful resonances are generally between the system inductance and shunt power factor correction capacitors. The reactor must be added between the capacitor and the power source. One method is to simply put a reactor in series with the capacitor to move the system resonance without actually tuning the capacitor to create a filter.

Passive filters are made of inductive, capacitive and resistive elements. They are relatively inexpensive compared with other means for eliminating harmonic distortion, but they have the disadvantage of potentially adverse interactions with the power system. They are employed either to shunt the harmonic currents off the line or to block their flow between parts of the system by tuning the elements to create a resonance at a selected harmonic frequency. Figure 6 shows several types of common filter arrangements.

Figure 6 – Illustration of Common Passive Filter Configurations

The most common type of passive filter is the single-tuned notch filter. This is the most economical type and is frequently sufficient for the application. An example of a common 480 volt filter arrangement is illustrated in Figure 7. The notch filter is series-tuned to present low impedance (see Figure 5) to a particular harmonic current. It is connected in shunt with the power system. Thus, harmonic currents are diverted from their normal flow path on the line into the filter. Notch filters can provide power factor correction in addition to harmonic suppression. Figure 7 shows a common delta-connected low-voltage capacitor bank converted into a filter by adding an inductance in series (note that higher rated voltage capacitor units should be used in filter applications, e.g., 600 volt capacitors on a 480 volt bus). In this case, the notch harmonic, hnotch, may be determined using:

where:
XCY = equivalent wye capacitive reactance (Ω)
Xf = inductive reactance of filter reactor (Ω)
kVφφ = system rms phase-to-phase voltage (kV)
MVAr3φ = three-phase capacitor bank rating (MVAr)

Figure 7 – Example of a Low Voltage Single-Tuned Notch Filter

One important side effect of adding a filter is that it creates a sharp parallel resonance point at a frequency below the notch frequency (see Figure 5). This resonant frequency must be placed safely away from any significant harmonic. Filters are commonly tuned slightly lower than the harmonic to be filtered to provide a margin of safety in case there is some change in system parameters. If they were tuned exactly to the harmonic, changes in either capacitance or inductance with temperature or failure might shift the parallel resonance higher into the harmonic. This could present a situation worse than no filter because the resonance is generally very sharp. For this reason, filters are added to the system starting with the lowest problem harmonic. For example, installing a 7th harmonic filter usually requires that a 5th harmonic filter to have been installed first. The new parallel resonance with a 7th harmonic filter only would have been near the 5th harmonic. When the two are operated side-by-side, the 5th harmonic filter must be energized first and de-energized last.

A delta-connected (capacitor) filter (see Figure 7) does not admit zero-sequence currents because the capacitor is connected in delta. This makes it largely ineffective for filtering zero-sequence triplen harmonics. Other solutions must be employed when it becomes necessary to control zero-sequence 3rd harmonic currents. For capacitors connected in wye, the designer has the option of altering the path for the zero-sequence triplen harmonics simply by changing the neutral connection. Placing a reactor in the neutral of a capacitor is a common way to force the bank to filter only zero-sequence harmonics. This technique is often employed to eliminate telephone interference.

Passive filters should always be placed on a bus where the short circuit impedance (XSC) can be expected to remain relatively constant. While the notch frequency is determined by the filter tuning, and will remain fixed, the parallel resonance will move as the system short circuit impedance varies. For example, one common problem occurs in factories that have standby generation for emergencies. The parallel resonant frequency for running with standby generation alone is generally much lower than when interconnected with the utility. This may shift the parallel resonance down into a harmonic where successful operation is impossible. Filters often have to be removed for standby operation because of this. Filters must also be designed with the capacity of the bus in mind. The temptation is to size the current-carrying capability based solely on the load that is producing the harmonic. However, even a small amount of background voltage distortion on a very strong bus may impose severe duty on the filter.

SUMMARY

Power factor correction is an important facet of power quality. Capacitors may be installed on customer systems to minimize charges for poor power factor on their electric bill. These installations may create problems by altering the harmonic frequency response of the network or introducing transient disturbances during their energization. This case study presented an overview of the impact of power factor correction on harmonics issues, such as parallel and series resonance and the effect of configuring capacitors as harmonic filters.

REFERENCES

IEEE Recommended Practice for Electric Power Distribution for Industrial Plants (IEEE Red Book, Std 141-1986), October 1986, IEEE, ISBN: 0471856878

IEEE Recommended Practice for Industrial and Commercial Power Systems Analysis (IEEE Brown Book, Std 399-1990), December 1990, IEEE, ISBN: 1559370440

IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems, March 1988, IEEE, ISBN: 0471853925

RELATED STANDARDS
IEEE Std. 519

GLOSSARY AND ACRONYMS
ASD: Adjustable-Speed Drive
DPF: Displacement Power Factor
PWM: Pulse Width Modulation
THD: Total Harmonic Distortion
TPF: True Power Factor

Power Factor Correction – Estimating Financial Savings

Published by Electrotek Concepts, Inc., PQSoft Case Study: Power Factor Correction – Estimating Financial Savings, Document ID: PQS0601, Date: January 1, 2006.

Abstract: Low power factor means that you are using a facility’s electrical system inefficiently. It can also cause equipment overloads, low voltage conditions, and greater line losses. Most importantly, low power factor can increase total demand charges and cost per kWh, resulting in higher monthly electric bills. This case study provides a summary of interrupting electric utility rates and billing, and estimating financial savings when applying low voltage power factor correction capacitors.

REVIEW OF UTILITY RATES AND PENALTIES

Each electric utility has their own unique method and related rates for determining power factor penalties (if they have a penalty), and it is not within the scope of this case study to summarize all of the possible rates and penalties. In addition, there is no one single industry standard that provides a summary of this information.

Therefore, this case provides some general background information and examples for related power factor penalties and economic evaluations for determining the financial benefits when applying power factor correction capacitors.
There are a number of methods for charging for poor power factor:

  • Charges for kVArh
  • Charges for kVAr demand
  • Charges for kVA demand
  • Charges for adjusted kW demand
  • Charges based on a percentage of the demand or base charge

Utilities charge for energy and demand. Energy is produced by burning fuel to drive turbines to produce electricity. The energy charges are in cents/kWh and are used to pay for energy production (e.g., fuel). The demand charges are a charge for the rate at which you demand the energy (also known as a demand penalty). The demand charges are in $/kW and are used to pay for energy transmission (e.g., transmission lines).

Interpreting Utility Bills

Utility monthly billing must be analyzed before it can be determined if capacitors are economically justified. Preferably, all bills for the previous year should be collected in order to establish seasonal variations and long term trends in electric consumption. If these are not available, the key data to request from the utility are maximum demand, power factor, typical energy usage, and power factor penalty or demand charge. Industrial consumer bills generally have two main parts, including the energy charges and the demand charges. There are also taxes and other miscellaneous charges, but these typically do not have a significant impact on the economic justification for power factor correction capacitors.

The energy charge is determined by multiplying the number of kWh of energy consumed in the month times the energy rate ($/kWh). The demand charge is more complicated. It is typically based on the peak kW demand over a given 15-, 30-, or 60-minute interval during the month. This is nominally multiplied by the demand charge rate ($/kW). However, many utilities assess a penalty to the demand if the power factor is lower than a predetermined value. There are two common formulae in use for determining the billed demand when the actual power factor is lower than power factor penalty value (lagging):

Both of these are applied only when the actual power factor is less than power factor penalty value (lagging). Otherwise, the billed demand is the same as the actual demand.

The difference between the amount paid for the billed demand and the amount for the actual demand is often termed the power factor penalty. This quantity is generally responsible for the bulk of the justification for capacitors:

The power factor (PF) used in billing is generally an average power factor determined over the entire month, although a few utilities may bill interval-by-interval. The usual procedure for determining the power factor is to meter the kVArh as well as the kWh. This may be done by two separate meters or may be contained within one electronic meter. The kVArh are then combined with the kWh to obtain an equivalent kVAh:

The average power factor is then:

The kVArh meter is usually “detented” so that it only records lagging VArs; that is, the VArs drawn by motors. No credit is given for leading VArs (a meter which is detented will record power flow in only one direction).

It should be noted that some utilities have considered billing for kVArh similarly to kWh. Existing meter technology can separately track leading and lagging kVArh. This provides the opportunity to have flexible rate structures to create incentives for customers to control var consumption and production.

Determining Financial Savings when Applying Power Factor Capacitors

This section provides several examples illustrating power factor penalties and economic evaluations for determining the financial benefits when applying power factor correction capacitors. It should be noted that the examples are only intended for general illustration purposes and in no way imply that the quoted rate structures and tariffs are indicative of the actual rate design methodologies and typical rates used by utilities.

Three-Phase Induction Motor Example

A small machine tool plant has an induction motor load that uses an average of 100 kW with an existing power factor of 80%. The desired power factor is 95%. Existing power factor, desired power factor, and kW are the three quantities that are required to properly select the amount of kVAr required to correct the lagging power factor of a three-phase induction motor. The required kVAr may be determined by either using the data provided in Table 1 (kVAr = kW * multiplier) or the following expression:

where:
kVAr = required compensation in kVAr
kW = real power in kW
tanφoriginal = original power factor phase angle
tanφdesired = desired power factor phase angle

kVAr = kW * (tanφoriginal – tanφdesired)

= 100 kW * (tan(cos-1 0.80) – tan(cos-1 0.95)) = 42.2kVAr

Table 1 – kW Multiplier for Determining kVAr Requirement

kVAr Demand Charge Example

A facility with a demand of 1800 kVA, 1350 kW, and 1200 kVAr has a contract for power factor that includes an energy charge for kWh, a demand charge based on kW, and other demand charge based on kVAr. The kVAr charge is $1.50 per month for each kVAr of demand in excess of 1/3 of the kW demand.

The first step is to determine the kVAr demand in excess of 1/3 of the kW demand

1200 kVAr – (1350 kW/3) = 750 kVAr

The second step is to estimate the annual savings if the 750 kVAr demand charge is eliminated by the addition of 750 kVAr of power factor correction capacitors.

$1.50 demand charge * 750 kVAr * 12 months = $13,500

The third step is to determine the cost to purchase and install 750 kVAr of capacitors. It is assumed that on a 480 volt system, the installed capacitor cost is $30/kVAr.

750 kVAr * $30/kVAr = $22,500

The final step is to determine the payback period for the capacitor installation.

$22,500/$13,500 = 1.67 years (20 months)

Therefore the low voltage capacitor installation will pay for itself in about 20 months.

kW Demand Charge Example

A facility with a demand of 1,000 kW has a power factor of 80%. The utility has a demand charge of $9.00/kW for customers with power factors below 85%.

The first step is to determine the monthly kW billing.

1000 kW * (0.85 target power factor / 0.80 existing power factor) = 1063 kW
1063 kW * $9.00 = $9,567

The second step is to determine the amount of power factor correction capacitors that are required to improve the power factor to 85%.

kVAr = kW * (tanφoriginal – tanφdesired)

= 1000 kW * (tan(cos-1 0.80) – tan(cos-1 0.85)) = 130 kVAr

The third step is to determine the cost to purchase and install 130 kVAr of capacitors. It is assumed that on a 480 volt system, the installed capacitor cost is $45/kVAr.

130 kVAr * $45/kVAr = $5,580

The fourth step is to determine the monthly kW billing with the new power factor.

1000 kW * (0.85 target power factor / 0.85 existing power factor) = 1000 kW
1000 kW * $9.00 = $9,000

The final step is to compare both monthly billing values and determine the payback period for the capacitor installation.

$9,56780% power factor billing
$9,00085% power factor billing
$567 monthly savings

$5,580/$567 = 10.32

Therefore the low voltage capacitor installation will pay for itself in approximately 10½ months.

kVA Demand Charge Example

A facility with a 400 kW load has a demand of 520 kVA. The utility has a demand charge of $3.00/kVA for customers with power factors below 95%.

The first step is to determine the present power factor.

power factor = kW/kVA = 400kW/520kVA = 0.769 or 77%

The second step is to determine the amount of power factor correction capacitors that are required to improve the power factor to 95%.

kVAr = kW * (tanφoriginal – tanφdesired)

= 400 kW * (tan(cos-1 0.77) – tan(cos-1 0.95)) = 200 kVAr

The third step is to determine the new kVA demand after the capacitors have been installed.

kVA = kW/ power factor = 400/0.95 = 421 kVA

The fourth step is to determine the cost to purchase and install 200 kVAr of capacitors. It is assumed that on a 480 volt system, the installed capacitor cost is $35/kVAr.

200 kVAr * $35/kVAr = $7,000

The final step is to compare both monthly billing values and determine the payback period for the capacitor installation.

(520 kVA – 421 kVA) * $3.00/kVA = $297/month
$7,000/$297 = 23.57

Therefore the low voltage capacitor installation will pay for itself in approximately 2 years.

Increase in System Capacity Example

A facility with a demand of 400 kW and 520 kVA has a power factor of 77%. The facility manager would like to add power factor correction capacitors to increase the facility’s capacity by 20%.

The first step is to determine the power factor required to release the desired amount of system kVA:

where:
PFnew = corrected power factor
PFold = existing power factor
kVArelease = amount of kVA to be released (in per-unit of existing kVA)

PFnew ≈ PFold / 1 – kVArelease = 0.77 / 1 – 0.20 = 0.9625 = 96%

The second step is to determine the amount of power factor correction capacitors that are required to improve the power factor to 96%.

kVAr = kW * (tanφoriginal – tanφdesired)

= 400 kW * (tan(cos-1 0.77) – tan(cos-1 0.96)) = 215 kVAr

The third step is to determine the cost to purchase and install 215 kVAr of capacitors. It is assumed that on a 480 volt system, the installed capacitor cost is $45/kVAr.

215 kVAr * $45/kVAr = $9,675

Therefore the facility manager will be able to increate the plant’s capacity by 20% by spending $9,675 to add 215 kVAr of power factor correction capacitors. The additional capacitor will be available for new motor and lighting loads without having to add new transformers or other distribution equipment.

Power Factor Penalty Example

A facility has the following electrical usage data:

163 kW load, 480 volt, three-phase service
730 hours per month operation
65% power factor
Power Factor Penalty – $0.0015 per kVArh (below unity)

The first step is to determine the facility kVA and kVAr.

kVA = kW/ power factor = 163/0.65 = 251 kVA

kVAr = √(kVA2 – kW2) = √(2512 – 1632) ≈ 190 kVAr

Adding 190 kVAr of power factor correction will correct the power factor to unity (100%) and eliminate the power factor penalty.

The second step is to determine the monthly power factor penalty.

190 kVAr * $0.0015/kVArh * 730 hrs = $208.05

The third step is to determine the cost of 190 kVAr of compensation. It is assumed that on a 480 volt system, the installed capacitor cost is $30/kVAr.

190 kVAr * $30/kVAr = $5,700

The final step is to determine the payback period for the capacitor installation.

$5,700/$208.05 = 27.397

Therefore, the low voltage capacitor installation will pay for itself in approximately 27 months.

SUMMARY

Power factor is a measurement of how efficiently a facility uses electrical energy. A high power factor means that electrical power is being utilized effectively, while a low power factor indicates poor utilization of electric power. Low power factor can cause equipment overloads, low voltage conditions, and greater line losses. Most importantly, low power factor can increase total demand charges and cost per kWh, resulting in higher monthly electric bills. Low power factor is generally solved by adding power factor correction capacitors to a facility’s electrical distribution system. Power factor correction capacitors supply the necessary reactive portion of power (kVAr) for inductive devices. The principle benefit is lower monthly electric bills.

REFERENCES

IEEE Recommended Practice for Electric Power Distribution for Industrial Plants (IEEE Red Book, Std 141-1986), October 1986, IEEE, ISBN: 0471856878

IEEE Recommended Practice for Industrial and Commercial Power Systems Analysis (IEEE Brown Book, Std 399-1990), December 1990, IEEE, ISBN: 1559370440

IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems, March 1988, IEEE, ISBN: 0471853925

GLOSSARY AND ACRONYMS
ASD: Adjustable-Speed Drive
DPF: Displacement Power Factor
PWM: Pulse Width Modulation
THD: Total Harmonic Distortion
TPF: True Power Factor

Transient Issues Related to Power Factor Correction

Published by Electrotek Concepts, Inc., PQSoft Case Study: Transient Issues Related to Power Factor Correction, Document ID: PQS0605, Date: April 1, 2006.

Abstract: Power factor correction is an important facet of power quality. Capacitors may be installed on customer systems to minimize charges for poor power factor on their electric bill. These installations may create problems by altering the harmonic frequency response of the network or introducing transient disturbances during their energization. This case study presents an overview of the impact of power factor correction on transient issues, such as voltage magnification and nuisance tripping of customer equipment (e.g., adjustable-speed drives).

INTRODUCTION

Electric utilities and their customers have long been concerned with power quality. The need for constant voltage and frequency has always been recognized. However, recent trends toward energy conservation, the increasing utilization of power electronic loads, and the proliferation of sensitive electronic equipment are changing the definition of what is meant by “constant voltage.” The primary reasons for the growing concern include:

− Load equipment is more sensitive to power quality variations than equipment applied in the past. Many new load devices contain microprocessor-based controls and power electronic devices that are sensitive to many types of disturbances.

− The increasing emphasis on overall power system efficiency has resulted in a continued growth in the application of devices such as high-efficiency adjustable-speed motor drives and shunt capacitors for power factor correction to reduce losses. This is resulting in increasing harmonic levels on power systems and has many people concerned about the future impact on system capabilities.

− Increased awareness of power quality issues by the end users. Utility customers are becoming better informed about such issues as interruptions, sags, and switching transients and are challenging the utilities to improve the quality of power delivered.

− Many things are now interconnected in a network. Integrated processes mean that the failure of any component has much more important consequences.

TRANSIENT RELATED ISSUES

Transient voltages and currents are a result of sudden changes within the electric power system. Opening or closing of a switch or circuit breaker causes a change in circuit configuration and the associated voltages and currents. A finite amount of time is required before a new stable operating point is reached. Lightning strokes to exposed distribution circuits inject a large amount of energy into the power system in a very short time, causing deviations in voltages and currents which persist until the excess energy is absorbed by dissipative elements (surge arresters, load resistance, conductor resistance, grounding system, etc.). A principal effect of both these events is a temporary departure of power system voltage and current from the normal steady-state sinusoidal waveforms. All transients are caused by one of two actions:

  • connection or disconnection of elements within the electric circuit
  • injection of energy due to a direct or indirect lightning stroke or static discharge.

Opening or closing of switches is a very common occurrence, whether it is normal cycling of loads at the utilization level, or utility operations on the transmission and distribution system. Lightning and static discharge are less common, but the potential effects are obvious. The mechanism may also be unintentional, as with initiation of a short circuit.

Transient overvoltages and overcurrents are classified by peak magnitude, frequency, and duration. These parameters are useful indices for evaluating potential impacts of transients on power system equipment. The absolute peak voltage, which is dependent on the transient magnitude and the point on the fundamental frequency voltage waveform at which the event occurs, is important for dielectric breakdown evaluation (e.g., equipment insulation strength). Some equipment and types of insulation, however, may also be sensitive to rates of change in voltage or current. The transient frequency, combined with the peak magnitude, can be used to estimate the rate of change.

Utility Capacitor Switching

The application of utility capacitor banks has long been accepted as a necessary step in the efficient design of utility power systems. In addition, capacitor switching is generally considered a normal operation for a utility system and the transients associated with these operations are generally not a problem for utility equipment. These low frequency transients, however, can be magnified in a customer facility (if the customer has low voltage power factor correction capacitors) or result in nuisance tripping of power electronic-based devices, such as adjustable-speed drives. Capacitor energizing is just one of the many switching events that can cause transients on a utility system. However, due to their regularity and impact on power system equipment, they quite often receive special consideration.

Power quality problems related to utility capacitor switching include customer equipment damage or failure, nuisance tripping of adjustable-speed drives or other process equipment, transient voltage surge suppressors failure, and computer network problems.
Energizing a shunt capacitor bank from a predominantly inductive source creates an oscillatory transient that can approach twice the normal system peak voltage (Vpk). The characteristic frequency (fs) of this transient is given by:

fs

where:
fs = characteristic frequency (Hz)
Ls = positive sequence source inductance (H)
C = capacitance of bank (F)
fsystem = system frequency (50 or 60 Hz)
Xs = positive sequence source impedance (Ω)
Xc = capacitive reactance of bank (Ω)
MVAsc = three-phase short circuit capacity (MVA)
MVAr = three-phase capacitor bank rating (MVAr)
ΔV = steady-state voltage rise (per-unit)

Relating the characteristic frequency of the capacitor energizing transient (fs) to a steady-state voltage rise (ΔV) design range provides a simple way of quickly determining the expected frequency range for utility capacitor switching. For example, a 60 Hz system with a design range of 1.0% to 2.5% would correspond to characteristic frequency range of 380 to 600 Hz. For a shunt capacitor bank on a high voltage bus, transmission line capacitance and other nearby capacitor banks cause the energizing transient to have more than one natural frequency. However, for the first order approximation, this equation can still be used to determine the dominant frequency.

Because capacitor voltage cannot change instantaneously (remembering that i(t)=Cdv/dt), energization of a capacitor bank results in an immediate drop in system voltage toward zero, followed by an oscillating transient voltage superimposed on the 60 Hz fundamental waveform. The peak voltage magnitude depends on the instantaneous system voltage at the instant of energization, and can reach 2.0 times the normal system voltage (Vpk – in per-unit) under worst-case conditions.

For a practical capacitor energization without trapped charge, system losses, loads, and other system capacitances cause the transient magnitude to be less than the theoretical 2.0 per-unit. Typical magnitude levels range from 1.3 to 1.5 per-unit and typical transient frequencies generally fall in the range from 300 to 1000 Hz. Figure 1 illustrates an example (measured) distribution system capacitor energizing transient.

Figure 1 – Example of a Distribution System Capacitor Switching Transient

Voltage Magnification

Voltage magnification occurs when the transient oscillation initiated by the energization of a utility capacitor bank excites a series resonance formed by a step-down transformer and power factor correction bank on a customer’s lower voltage system. The result is a higher overvoltage magnitude at the customer’s bus (higher than the overvoltage magnitude where the capacitor is switched). Previous analysis has indicated that the worst magnified transient occurs when the following conditions are met (refer to Figure 4):

  • The size of the switched capacitor bank is significantly larger (>10) than the low voltage power factor correction bank (e.g., C2 vs. C4).
  • The energizing frequency (e.g., f2) is close to the series resonant frequency formed by the step-down transformer and the power factor correction capacitor bank (f4) (refer to the equations provided with Figure 4).
  • There is relatively little damping (resistive) provided by the low voltage load (typical industrial plant configuration – primarily motor load).

Figure 2 shows an example secondary bus voltage during utility capacitor energizing. Previous computer simulations and onsite measurements have indicated that magnified transients between 2.0 and 4.0 per-unit are possible over a wide range of low voltage capacitor sizes. Typically, the transient overvoltages will simply damage low-energy protective devices (e.g., MOVs) or cause a nuisance trip of a power electronic device. Important system variables to consider when analyzing this phenomenon include:

  • Switched capacitor bank size / lower voltage capacitor bank size and location
  • System loading / transformer characteristics
  • Circuit breaker characteristics (closing resistors/inductors, closing control, etc.).
  • Arrester size(s), rating(s), and location(s)

Figure 3 illustrates an example simulated capacitor energizing transient and the resulting transient voltage at the lower voltage customer power factor correction capacitor bank. Solutions to the voltage magnification usually involve:

  • Using an overvoltage control method, such as pre-insertion resistors or synchronous closing control.
  • Detuning the circuit by changing capacitor bank sizes, moving banks, and/or removing banks from service.
  • Switching large banks in more than one section.
  • Applying surge arresters (MOVs) at the remote location.
  • Converting the customer’s power factor correction banks into harmonic filters.
Figure 2 – Example of a Secondary Bus Voltage during Utility Capacitor Energizing
Figure 3 – Example of a Computer Simulation Showing Voltage Magnification
Figure 4 – Illustration of Circuit for Evaluating Voltage Magnification

Nuisance Tripping of Customer Equipment

Nuisance tripping refers to the undesired shutdown of a customer’s adjustable-speed drive or other power-electronic-based process device due to the transient overvoltage on the device’s dc bus. Very often, this overvoltage is caused by utility transmission or distribution capacitor bank energization. Considering the fact that many distribution banks are time clock controlled, it is easy to see how this event can occur on a regular basis, thereby causing numerous process interruptions for the customer.

An adjustable-speed drive system consists of three basic components and a control system as illustrated in Figure 5. The rectifier converts the three-phase ac input to a dc voltage, and an inverter circuit utilizes the dc signal to produce a variable magnitude, variable frequency ac voltage, that is used to control the speed of an ac motor. A dc motor drive differs from this configuration in that the rectifier is used to control the motor directly.

Figure 5 – Illustration of Adjustable-Speed Drive Circuit Components

The nuisance tripping event consists of an overvoltage trip due to a dc bus overvoltage on voltage-source inverter drives (e.g., pulse-width modulated). Typically, for the protection of the dc capacitor and inverter components, the dc bus voltage is monitored and the drive tripped when it exceeds a preset level. This level is typically around 780 volts (for 480 volt applications), which is only 120% of the nominal dc voltage. The potential for nuisance tripping is primarily dependent on the switched capacitor bank size, overvoltage controls for the switched bank, the dc bus capacitor size, and the inductance between the two capacitors. It is important to note that nuisance tripping can occur even if the customer does not have power factor correction capacitors.

The most effective methods for eliminating nuisance tripping are to significantly reduce the energizing transient overvoltage, or to isolate the drives from the power system with series inductors, often referred to as chokes. The additional series inductance of the choke will reduce the transient magnitude at the input to the drive and the associated current surge into the dc link filter capacitor, thereby limiting the dc overvoltage.

While determining the precise inductor size for a particular application may require a detailed computer simulation study, a more common approach involves the widespread application of a standard 3% value. The 3% size is based upon the drive kVA rating and is usually sufficient for most applications where voltage magnification isn’t also a concern. Figure 6 illustrates an example of a computer simulation showing the dc overvoltage transient before-and-after the application of a 3% ac choke.

Figure 6 – Example of a Simulation Showing Effect of Choke on dc Voltage Level

Generally, the choke is specified in %X and hp. However, for simulation purposes, the inductance of the choke may be approximated using the following relationship. An example of a 3% choke being added to a 10 hp drive is provided for reference.

Lchoke

where:
fsystem = system frequency (50 or 60 Hz)
X = inductive reactance of ac choke (%)
kVφφ = system rms phase-to-phase voltage (kV)
hp = Horsepower rating of the drive (hp)

SUMMARY

Power factor correction is an important facet of power quality. Capacitors may be installed on customer systems to minimize charges for poor power factor on their electric bill. These installations may create problems by altering the harmonic frequency response of the network or introducing transient disturbances during their energization. This case study presented an overview of the impact of power factor correction on transient issues, such as voltage magnification and nuisance tripping of customer adjustable-speed drives.

REFERENCES

IEEE Recommended Practice for Electric Power Distribution for Industrial Plants (IEEE Red Book, Std 141-1986), October 1986, IEEE, ISBN: 0471856878

IEEE Recommended Practice for Industrial and Commercial Power Systems Analysis (IEEE Brown Book, Std 399-1990), December 1990, IEEE, ISBN: 1559370440

IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems, March 1988, IEEE, ISBN: 0471853925

RELATED STANDARDS
IEEE Std. 1036

GLOSSARY AND ACRONYMS
ASD: Adjustable-Speed Drive
DPF: Displacement Power Factor
PWM: Pulse Width Modulation
TPF: True Power Factor

Power Factor Correction and Harmonic Control for dc Drive Loads

Published by Electrotek Concepts, Inc., PQSoft Case Study: Power Factor Correction and Harmonic Control for dc Drive Loads, Document ID: PQS0410, Date: December 31, 2004.

Abstract: This case history describes the design of power factor correction and harmonic control equipment for loads at a plastic film manufacturing plant. Measurements were performed to characterize the harmonic generation and power factor requirements of the load. The electric utility supplying the new facility is requiring that the plant meet the harmonic current limits specified in IEEE Std. 519-1992

Harmonic filters that can meet the IEEE Std. 519 guidelines for the specific load characteristics were designed. General filter design guidelines for this type of application are presented.

INTRODUCTION

DC drives can be a significant percentage of plant load in many industrial facilities. They are commonly used in the plastics, rubber, paper, textile, printing, oil, chemical, metal, and mining industries. These drives are still the most common type of motor speed control for applications requiring very fine control over wide speed ranges with high torques.

Power factor correction is particularly important for dc drives because phasing back of the SCRs results in relatively poor power factor, especially when the motor is at reduced speeds. Additional transformer capacity is required to handle the poor power factor conditions (and the harmonics) and more utilities are charging a power factor penalty that can significantly impact the total bill for the facility.

Figure 1 – Example dc Drive Current Waveform and Harmonic Spectrum
SYSTEM DESCRIPTION

The customer manufactures heavy-duty plastic film. The process uses calenders that are driven by dc motor drives. As a result, there is significant harmonic current generation and the plant power factor without compensation is quite low. Shunt capacitors can be added to partially correct the power factor but this can cause harmonic problems due to resonance conditions and transient problems during capacitor switching by the utility.

The customer is planning to build a new facility that will include two calender lines similar to lines at their existing facility. Measurements performed at the existing facility are used to characterize these dc drive loads and additional analysis is described to determine power factor correction and filtering requirements for the new facility.

The customer would like to correct the power factor to 0.95 with power factor correction equipment (capacitors). However, the power factor correction must take into account the potential for resonance that could magnify the harmonic currents generated by the dc drive loads. This usually means that harmonic filters are required. In addition, the electric utility supplying the new facility has required that the customer meet the limits in IEEE 519-1992. This results in a need for harmonic filters to reduce the harmonic current components injected onto the utility system.

The plant electrical system consists of two sets of 480 volt switchgear fed from a common 480 volt bus. A 3750 kVA transformer steps down from a 34.5 kV distribution line for the entire facility. Figure 2 shows a oneline diagram of the facility.

Figure 2 – Oneline Diagram for Customer Facility
POWER FACTOR CORRECTION REQUIREMENTS

The calender lines at the new facility will be similar to existing lines at the existing facility. Therefore, measurements at the existing facility are used to estimate the power factor correction that will be needed at the new facility. Since all of the load will essentially be connected to the same 480 volt bus at the new facility, the important consideration is the total power factor for the two switchgear lines.

Measurement Results

Measurements were performed characterizing typical calender line conditions at the existing facility. There were two very important findings from these measurements:

  1. Displacement power factor for the calender line loads (almost exclusively dc drives) ranged from 0.65-0.70. This displacement power factor determines the capacitor/filter sizes required for the loads.
  2. There is significant cancellation of harmonic currents resulting from the different dc drives fed from the main bus. Whereas the total harmonic distortion in the current for a single drive is approximately 30% (see Figure 1), the total harmonic distortion for the total current at the bus was usually on the order of 15%, not including the effect of resonances caused by capacitor banks. This is an important consideration when determining the filter rating requirements and the ability to meet IEEE 519 harmonic current limits.

Power Factor Calculations for the New Facility

The power factor requirements for the new facility are calculated based on the total expected load. Table 1 shows the calculation of the power factor correction requirements at estimated minimum and maximum load levels. The estimated power factor of the loads is based on the measurement results. Based on these estimates of plant loading, a total compensation of 1800 kVAr should be sufficient to maintain a power factor exceeding 0.95 for all load conditions.

Table 1 – Calculation of Power Factor Correction for Total Plant Loading

ANALYSIS OF HARMONIC DISTORTION CONCERNS

For the purposes of harmonic analysis, the dc drive loads can be represented as sources of harmonic currents. The system looks stiff to these loads and the current waveform illustrated in Figure 1 is relatively independent of the voltage distortion at the drive location. This assumption of a harmonic current source permits the system response characteristics to be evaluated separately from the dc drive characteristics. The representation of the drives as harmonic current sources is shown in Figure 3.

Figure 3 – Representation of the dc Drives as Current Sources

Analysis of the system response is important because the system impedance vs. frequency characteristics determine the voltage distortion that will result from the dc drive harmonic currents. A simplified version of the situation is shown in Figure 4.

Figure 4 – Voltage Distortion Caused by Harmonic Currents and System Impedance

If the system is infinitely strong (no impedance), there will never be any voltage distortion. It is the harmonic currents generated by the dc drives passing through the system impedance that causes voltage distortion. Filters are the means used to control the system response.

Harmonic Distortion Levels at the Existing Facility

Initial power factor correction procedures for the existing facility involved installation of capacitor banks for each calender line. One or two 600 kVAr banks were used for each line. This resulted in problems with high voltage distortion levels in the plant and also caused transient voltage magnification when the utility company switched a higher voltage transmission system capacitor bank. To prevent these problems, the 600 kVAr capacitor banks are being configured as harmonic filters rather than just capacitors. The configuration is shown in Figure 5.

Figure 5 – Basic 480 Volt Filter Configuration

The filter is tuned below the fifth harmonic. This limits the additional harmonic current that must be absorbed from the utility system and also allows for tolerances in the filter components.

The addition of a single 600 kVAr filter significantly improved voltage distortion levels at the 480 Volt bus. Figure 6 compares the voltage harmonic spectrum with and without the filter in service.

Figure 6 – Impact of Filters on Bus Voltage Distortion

Filter Design for the New Facility

The switchgear lineups at the new facility are being configured with 1200 Amp switchgear. For this reason, the individual power factor correction steps are being limited to 600 kVAr. Based on the power factor correction estimates, two steps will be installed initially and a third step will be added in the future if it is warranted based on actual plant loading.

Each 600 kVAr step will be configured as a harmonic filter tuned to approximately 4.7 times the fundamental frequency (60 Hz). 600 volt capacitors will be used for these filters to prevent overloading due to voltage rise across the reactor and harmonics from the power system. In order to accomplish this, capacitors with a nominal rating of 900 kVAr at 600 Volts will be required. Figure 7 provides the specifications for the recommended filter configuration. The specifications are based on two filters sharing the maximum load at the new plant.

Figure 7 – 600 kVAr Filter Specification

Evaluation of Current Limits in IEEE 519

The IEEE 519-1992, “Recommended Practice for Harmonic Control in Electric Power Systems”, provides recommended harmonic current limits for individual customers at the point of common coupling with the electric utility. The utility supplying the new facility has specified these harmonic current limits in the contract with the customer. Therefore, it is important to make sure that the specified harmonic filters will adequately limit the harmonic currents injected onto the utility system.

A few assumptions are required to make this evaluation. A short circuit capacity at the transformer high side of 23 MVA is assumed. This is relatively low because the plant is supplied from a long 34.5 kV feeder circuit. Worst case harmonic generation levels are assumed which do not include significant cancellation from the different drives. The IEEE 519 evaluation is based on an “average maximum demand current” defined as the average of the monthly maximum demand values for twelve months. For a new plant this must be estimated. 3000 kVA was used for this evaluation.

Figure 8 evaluates the expected current distortion levels with respect to the IEEE 519 limits for the case without compensation or harmonic filters. The limits are exceeded at almost every individual harmonic frequency and for the total demand distortion (TDD).

Figure 8 – IEEE Std. 519 Evaluation without Harmonic Filters

Figure 9 illustrates the effect of the proposed 600 kVAr filters on the expected harmonic current levels being injected onto the utility system. These values were obtained from a simulation of the system response. The limits are not exceeded at any individual frequency or for the total demand distortion. There should be no problem with the IEEE 519 limits for the proposed filter configuration.

Figure 9 – IEEE Std. 519 Evaluation with Two 600 kVAr Harmonic Filters
SUMMARY

DC Drive loads can have a low displacement power factor, resulting in a need for power factor correction. The power factor correction can be sized based on the displacement power factor of the load but all of the compensation should be installed as harmonic filters to avoid harmonic resonance problems and excessive voltage distortion levels. Filters tuned below the fifth harmonic will usually be adequate to keep voltage distortion levels below 5% and current harmonics injected onto the utility system below the levels specified in IEEE 519.

REFERENCES

T.E. Grebe, M.F. McGranaghan, and M. Samotyj, “Solving Harmonic Problems in Industrial Plants and Harmonic Mitigation Techniques for Adjustable Speed Drives,” Electrotech 92 Proceedings, Montreal, June 14-18, 1992.
T. Grebe, “Why Power Factor Correction Capacitors May Upset Adjustable Speed Drives,” Power Quality, May/June, 1991.
M.F. McGranaghan, R.M. Zavadil, G. Hensley, T. Singh, M. Samotyj, “Impact of Utility Switched Capacitors on Customer Systems – Magnification at Low Voltage Capacitors,” Presented at the 1991 IEEE T&D Show, Dallas, TX, September, 1991.

GLOSSARY AND ACRONYMS
PCC: Point of Common Coupling
SCR: Short Circuit Ratio
TDD: Total Demand Distortion
THD: Total Harmonic Distort

Wind Turbine Operation in Power Systems & Grid Connection Requirements

Published by K. B. Mohd. Umar Ansari1, Manjeet Singh2, Sandeep Kumar3

B.E (EEE), M.Tech (Electrical Power & Energy Systems), Ex- Engineer – GET, Tata Motors Pvt. Ltd., Sector 11,
Udham Singh Nagar, Pantnagar, UK, India. 1
B.Tech (EN), Ex-Electrical Engineer, Flowmore Limited, Sahibabad, Ghaziabad, U.P., India2
B.Tech (EE), M.Tech (Power Systems*), Lecturer, Department of Electrical Engg, Sri RamSwaroop Memorial
University, Lucknow, U.P., India3

Published in International Journal of Advanced Research in Electrical, Electronics and Instrumentation Engineering (A High Impact Factor , Monthly, Peer Reviewed Journal)
Website: http://www.ijareeie.com
Vol. 7 , Issue 10, October 2018

ABSTRACT: Wind power industry is developing rapidly; more and more wind farms are being connected into power systems. Integration of large scale wind farms into power systems presents some challenges that must be addressed, such as system operation and control, system stability, and power quality. This paper discuss the impact of wind turbine generation systems operation connected to power systems, describes the main power quality parameters and requirements on such generations. Furthermore, it deals with the complexities of modelling wind turbine generation systems connected to the power grid, i.e. modelling of electrical, mechanical and aerodynamic components of the wind turbine system, including the active and reactive power control. In order to analyze power quality phenomena related to wind power generation, digital computer simulation is required to solve the complex differential equations.

KEYWORDS: Wind Turbines, Wind farms, Power quality, Wind power generation, Stability, Grid code, Connection requirements

I.INTRODUCTION

Wind turbine technology has undergone a revolution during the last century. A wind turbine is a machine for converting the kinetic energy in the wind into mechanical energy and mechanical energy is then converted into electricity. The machine which converts mechanical energy into electrical energy is called wind generator or aero generator. If the mechanical energy is used directly by machinery, such as a pump or grinding stones, the machine is called a windmill. A WECS (Wind Energy Conversion System) is a structure that transforms the kinetic energy of the incoming air stream into electrical energy. This conversion takes place in two steps, as follows. The extraction device, named wind turbine rotor turns under the wind stream action, thus harvesting a mechanical power. The rotor drives a rotating electrical machine, the generator, which outputs electrical power.

Fig.1.1 Horizontal axis wind turbine
Fig.1.2 Vertical axis wind turbine

Wind turbines are classified into two general types: horizontal axis and vertical axis. A horizontal axis machine has its blades rotating on an axis parallel to the ground as shown in Fig. 1.1. A vertical axis machine has its blades rotating on an axis perpendicular to the ground as shown in Fig. 1.2. Today, the vast majority of manufactured wind turbines are horizontal axis with two or three blades.

PARTS OF WIND TURBINE
Fig. 1.3. Main elements of a horizontal axis wind turbine

Fig. 1.3 illustrates the major components placement in horizontal axis wind turbine.
A typical wind turbine consists of the following components:

BLADE– An important part of a wind turbine that extracts wind energy.

HUB– Blades are fixed to a hub which is a central solid part of the turbine.

GEAR BOX– Two types of gear box are used in wind turbine- Parallel shaft-It is used in small turbines, design is simple, maintenance is easy, high mass material and offset shaft. Planetary shaft- It is used in large turbines, complex design, low mass material and in line arrangements.

BRAKES-Two independent brake sets are incorporated on the rotor low speed shaft and high speed shaft The low speed shaft brake is Hydraulic operated .The high speed shaft brake is self adjusted and spring loaded.

NACELLE– The nacelle houses the generator, the gearbox, the hydraulic system and yawing mechanism.

GENERATOR– The conversion of mechanical power of wind turbine into the electrical power can be accomplished by one of the following type of the electrical machine- Synchronous machine 2. Induction machine

TOWER– Towers are made from tubular steel, concrete or steel lattice. Because wind speed is getting higher with the height, taller towers enable turbines to capture more energy and this way generates more electricity.

II.A METHODOLOGY FOR COMPATIBILITY EVALUATION OF WIND GENERATION INTEGRATION IN POWER SYSTEMS

At the present time and in the near future, generators for wind turbines will be synchronous generators, permanent magnet synchronous generators, and induction generators, including the squirrel cage type and wound rotor type. For small to medium power wind turbines, permanent magnet generators and squirrel cage induction generators are often used because of their reliability and cost advantages. Induction generators, permanent magnet synchronous generators and wound field synchronous generators are currently used in various high power wind turbines. Interconnection apparatuses are devices to achieve power control, soft start and interconnection functions. Very often, power electronic converters are used as such devices. Most modern turbine inverters are forced commutated PWM inverters to provide a fixed voltage and fixed frequency output with a high power quality. Both voltage source voltage controlled inverters and voltage source current controlled inverters have been applied in wind turbines. For certain high power wind turbines, effective power control can be achieved with double PWM (pulse width modulation) converters which provide a bi-directional power flow between the turbine generator and the utility grid. In order to analyze wind generation compatibility in power systems four factors may be taken into account:

  • Electrical power system characteristics (GRID)
  • Wind turbine technology (WIND FARM)
  • Grid connection requirements
  • Simulation tools
Fig.9: Evaluation methodology of wind turbine generation and power system compatibility

POWER GENERATION SYSTEM

The electrical power generation structure contains both electromagnetic and electrical subsystems. Besides the electrical generator and power electronics converter it generally contains an electrical transformer to ensure the grid voltage compatibility.

FIXED-SPEED WECS

Fixed-speed WECS operate at constant speed. That means that, regardless of the wind speed, the wind turbine rotor speed is fixed and determined by the grid frequency. Fixed-speed WECS are typically equipped with squirrel-cage induction generators (SCIG), soft starter and capacitor bank and they are connected directly to the grid, as shown in Fig.1.4.

Fig. 1.4. General structure of a fixed-speed WECS

SCIG were preferred because they are mechanically simple and have low maintenance cost. SCIG-based WECS are designed to achieve maximum power efficiency at a unique wind speed. In order to increase the power efficiency Fixed-speed WECS have the advantage of being simple, robust and reliable, with simple and inexpensive electric systems and well proven operation. On the other hand, due to the fixed-speed operation, the mechanical stress is important and full wind power is not extracted.

An evolution of the fixed-speed SCIG-based WECS are the limited variable speed WECS. They are equipped with a wound-rotor induction generator (WRIG) with variable external rotor resistance as shown in Fig. 1.5. The unique feature of this WECS is that it has a variable additional rotor resistance, controlled by power electronics. Thus, the total (internal plus external) rotor resistance is adjustable, further controlling the slip of the generator and therefore the slope of the mechanical characteristic.

Fig. 1.5. General structure of a limited variable-speed WECS

VARIABLE SPEED WECS

Variable-speed wind turbines are currently the most used WECS. The variable speed operation is possible due to the power electronic converters interface, allowing a full (or partial) decoupling from the grid. The doubly-fed-induction-generator (DFIG) based WECS shown in Fig. 1.6, also known as improved variable-speed WECS, is presently the most used by the wind turbine industry.

Fig. 1.6. General structure of an improved variable-speed WECS

The DFIG is a WRIG with the stator windings connected directly to the three phase, constant-frequency grid and the rotor windings connected to a back-to-back (AC–AC) voltage source converter. Thus, the term “doubly-fed” comes from the fact that the stator voltage is applied from the grid and the rotor voltage is impressed by the power converter. The power electronics converter comprises of two IGBT converters, namely the rotor side and the grid side converter, connected with a direct current (DC) link. The rotor side converter controls the generator in terms of active and reactive power, while the grid side converter controls the DC-link voltage and ensures operation at a large power factor. The stator outputs power into the grid all the time. The rotor, depending on the operation point, is feeding power into the grid when the slip is negative (over synchronous operation) and it absorbs power from the grid when the slip is positive (sub-synchronous operation). In both cases, the power flow in the rotor is approximately proportional to the slip. DFIG-based WECS are highly controllable, allowing maximum power extraction over a large range of wind speeds.

Fig. 1.7. General structure of a full variable-speed WECS
III.GRID CONNECTION REQUIREMENTS

The connection of wind generation to electrical power systems influences the system operation point, the load flow of real and reactive power, nodal voltages and power losses. At the same time wind power generation has various characteristics with a wide spectrum of influence which are listed below [9]:

  • Location in the power system
  • Voltage variation of amplitude and frequency
  • Flicker
  • Harmonics
  • Short circuit currents and protection systems
  • Stability
  • Self-excitation of asynchronous generators
  • Real power losses

The rising impact of wind power generation in power systems cause system operators to extend grid connection requirements in order to ensure its correct operation. We can divide grid connection requirements into two categories:

  1. General grid code requirements
  2. Special requirements for wind generation

The first category represents requirements valid for every generator in the grid. These are general requirements regarding the system operation point. Some of the most important grid code requirements are:

  • Steady state voltage variation
  • Line capacity
  • Short circuit power at the connection point
  • Frequency variations
  • Protection
  • Contingency

Special requirements for wind generation were introduced to insert wind power generation in the power system without an impact on power quality or system stability.

There are two different types of requirements: requirements established by system operators and national or international standards.

The control of reactive power at the generators is used in order to keep the voltage within the required limits and avoid voltage stability problems. Wind generation should also contribute to voltage regulation in the system, the requirements either concern a certain voltage range that should be maintained at the point of connection or certain reactive power compensation that should be provided.

Until now in case of short-circuits or instability of the grid the wind parks disconnected immediately from the power system. Due to the high penetration of wind generation system operators observe a certain risk for the system stability during major disconnections. Therefore in the new regulations require that wind farms stay connected during a line voltage fault and participate in recovery from the fault.

National and international standards are applied to wind power generation regarding power quality issues for the emission of disturbances in the power system by wind generators.

IV. WIND FARMS OPERATION AND CONTROL, STABILITY IMPROVEMENT

In this section some possible methods of control options are discussed.

Fig. 1.8. Mechanical control & Load control

Mechanical Control of the turbine blade: As the wind speed changes the pitch of the blades or blade tip is adjusted to control the frequency of the turbine rotation.
The drawback of this method is that power in the wind is wasted and control method can be expensive and unreliable.

Load control: As the wind speed changes the electrical load is changed by rapid switching, so the turbine frequency is controlled. This method makes greater use of power in the wind because the blade pitch s kept at the optimum angle.

The advantages and disadvantages of WTIG are shown in table 1 below:

Generator ConceptAdvantagesDisadvantages
SCIGEasier to design, construct and control
Robust operation
Low cost		Low energy yield
No active/reactive power
controllability
High mechanical stress
High losses on gear
PMSGHighest energy yield
Higher active/reactive power controllability
Absence of brush/slip ring
Low mechanical stress
No copper loss on rotor		High cost of PM material
Demagnetization of PM
Complex construction process
Higher cost on PEC
Higher losses on PEC
Large size
DFIGHigh energy yield
High active/reactive power controllability
Lower cost on PEC
Lower losses by PEC
Less mechanical stress
Compact size		Existence of brush/slip ring
High losses on gear
Table 1 : Advantages & Disadvantages of WTIG

Stability support

System stability is largely associated with power system faults in a network such as tripping of transmission lines, loss of production capacity (generator unit failure) and short circuits. These failures disrupt the balance of power (active and reactive) and change the power flow. Though the capacity of the operating generators may be adequate, large voltage drops may occur suddenly. The unbalance and re-distribution of real and reactive power in the network may force the voltage to vary beyond the boundary of stability. A period of low voltage (brownout) may occur and possibly be followed by a complete loss of power (blackout).

In order to keep system stability, it is necessary to ensure that the wind turbine restores normal operation in an appropriate way and within appropriate time. This may include supporting the system voltage with reactive power compensation devices, such as interface power electronics, SVC, STATCOM and keeping the generator at appropriate speed by regulating the power etc.

V.WIND TURBINE SYSTEMS MODELLING

The first step is to state the problem and to define a set of parameters to be analyzed giving the grid connection requirements. After that the simulation tool suitable for analyzing the stated problem and to give the requested results must be chosen. After choosing the convenient simulation software modelling of the wind turbine and power grid components should be carried out.

Wind farms consist of many relatively small generation units. Two different models could be applied to the wind farm modelling: Separated modelling of all small generation units or aggregation of these many generators to one representative wind farm model.

Wind turbines use two different models: static models and dynamic models. Static models are needed to analyze all types of steady state analysis. Usually, these models are simple and easy to create. Dynamic models are needed for various types of analysis related to system dynamics, control analysis, optimization etc.

Two different types of dynamic models are used: functional and mathematical physical models. The difference between them is that the latter one includes a detailed power electronics model. Table II compares model and analysis type. To analyze variable speed wind turbines, the following points should be considered:

  • Power electronic converters and controls may be aggregated along with the generators electrical part.
  • Generator inertia, aerodynamics and pitch controllers should be modelled individually.

As always with modelling and simulation, results should be verified by available data and measurements.

TABLE II. – Model types & analysis types

ModelType of analysis
Steady state static modelsAnalysis of voltage variation
Analysis of load flow
Analysis of short-circuits
Transient state dynamic Models functional modelsAnalysis of transient stability
Analysis of small-signal stability
Analysis of transient response
Analysis of steady-state waveforms
Synthesis of control
Optimization
Transient state dynamic Models mathematical physical models (power electronics)Analysis of start-up transient effects
Analysis of load transient effects
Analysis of fault operation
Analysis of harmonics and sub harmonics
Detailed synthesis of control
Detailed optimization
VI.CONCLUSION

Since the penetration of wind power generation is growing system operators have an increasing interest in analyzing the impact of wind power on the connected power system. For this reason grid connection requirements are established. Integration of large scale wind power into power systems present many new challenges. This paper presents the impacts of wind power on power quality, the gird requirements for integration of wind turbines, and discusses the potential operation and control methods to meet the challenges.

REFERENCES

[1]. Sharpe, L. “Offshore generation looks set to take off”, IEE Review, Volume: 48, Issue: 3, May 2002, Page(s): 24 –25.
[2]. Grainger, B.; Thorogood, T., “Beyond the harbour wall”, IEE Review, Volume: 47, Issue: 2 , March 2001, Page(s): 13 –17.
[3]. English version of Technical Regulations TF 3.2.6, “Wind turbines connected to grids with voltage below 100 kV –Technical regulations for the properties and the control of wind turbines”, Eltra and Ekraft systems, 2004.
[4]. IEC 61400-21: Power quality requirements for wind whines. (2001).
[5]. DEFU Committee reports 111-E (2nd edition): Connection of windturbines to low and medium voltage networks 1998.
[6]. IEC 61400-12: Wind turbine generator systems. Power performance measurement techniques.
[7] http://windpower-monthly.com/windicator
[8] Blaabjerg, F., Wind Power – A Power Source Enabled by Power Electronics; 2004 CPES Power Electronics Seminar and Industry Research Review, April 18-20, Virginia Tech, Blacksburg, VA
[9] Z. Lubosny; Wind Turbine Operation in Electric Power Systems; Springer-Verlag Berlin, ISBN 3- 540 40340-X.

DOI:10.15662/IJAREEIE.2018.0710014

Flywheel Size Design Considerations and Experimental Verification Using a 50-kW System for Voltage Sag Compensator with Flywheel Induction Motor

Published by Shuhei Kato, Miao-miao Cheng, Hideo Sumitani and Ryuichi Shimada,
Integrated Research Institute, Tokyo Institute of Technology, Japan

SUMMARY

Flywheel energy storage systems can be used as an uninterrupted power supply system because they are environmentally friendly and have high durability. The use of a simple voltage sag compensator with a low-speed heavy flywheel and a low-cost squirrel-cage induction motor/generator is proposed. First, the ability of the proposed system to maintain the load voltage at 100% when the grid is experiencing voltage sag is validated experimentally. Next, design guidelines for the flywheel stored energy are dis- cussed. Experimental verification of a 50-kW-class system is carried out, and the results show good agreement with the developed design guidelines. © 2012 Wiley Periodicals, Inc. Electr Eng Jpn, 181(1): 36–44, 2012; Published online in Wiley Online Library (wileyonlinelibrary.com). DOI 10.1002/eej.21252

Key words: flywheel; voltage sag compensator; squirrel-cage induction motor; capacitor self-excitation; design guidelines.

1.Introduction

Voltage sag [1–3] is a phenomenon in which the grid voltage drops briefly (for about 0.1 second [4]), and in seven out of ten cases it is attributed to a lightning strike on a transmission line [5]. The frequency of occurrence of voltage sag is very high, approximately 10 to 50 times [5] that of power failures, and it causes significant losses in the form of autonomous robot failures and malfunctions in industry in general.

At present voltage sag compensators employing a parallel compensation method using an electric double layer capacitor (EDLC) [7], a NAS battery [8], or a super- conducting magnetic energy storage system (SMES) and a series compensation method known as a dynamic voltage restorer (DVR) [10], are gaining attention as voltage sag countermeasures [6]. However, in all of these semiconductor converters, harmonic filters and series transformers are required, and the equipment is complicated.

We have proposed [11, 12] a simple voltage sag compensator that can be linked directly to the grid without a semiconductor converter, that is built around a simple and inexpensive squirrel-cage induction motor with flywheel connected to the axis. It has the significant advantage of not requiring a semiconductor converter to generate a DC volt- age even though the stored energy utilization rate is low, with switching to the induction generator during induction motor sag by using capacitor self-excitation [13] in an induction motor during compensation.

In this paper we describe experiments with a simulated voltage sag (power source voltage drop) in order to confirm the effectiveness of a voltage sag compensator with a flywheel induction motor. We clarified the flywheel stored energy design guidelines for this method and tested a 50-kW-class system based on this design. The results show that the experimental results for the system agree well with the design values, confirming the effectiveness of the design method.

2.Configuration and Operation of the Voltage Sag Compensator without a Semiconductor Converter

Figure 1 shows the system configuration of the volt- age sag compensator described in this paper. This is a commercial power supply system during normal operation in which the induction motor with a flywheel is connected in series to the load, and power is supplied to the load via a thyristor switch from the grid during normal operation. The actions during operation are as follows.

(1) Flywheel startup and standby operation

The induction motor starting current is suppressed and the induction motor is started up by phase control of the interconnection thyristor switch from the grid without a connection to a capacitor or load. During standby, the thyristor switch is in a conductive state at all angles, and the induction motor is in standby under virtually no load.

Fig. 1. System configuration of the proposed voltage sag compensator without semiconductor power converters.

(2) Voltage sag occurs

When the grid voltage drops, an OFF signal is sent to SW1. When SW1 is OFF at the first current zero point after the voltage sag occurs, the induction motor automatically becomes an induction generator due to the capacitor self- excitation phenomenon, and power is supplied to the load. Because the frequency of the induction generator is lower than the grid frequency only for the “slip” portion, the load voltage vector rotates spatially at close to the slip frequency with respect to the grid voltage vector.

(3) Power restoration

When the grid voltage is restored and the voltage spatial phases on the grid side and the induction generator side (load side) agree (the voltage phase difference is zero), that is, when the voltage of the induction generator is rotated 360° in space and again matches the grid voltage, an ON signal is output to SW1. Reconnection in the state in which there is a voltage phase difference creates a disturbance in the grid and the interconnection switch faults due to the large current to the induction motor, and as a result, reconnection with the voltage phase difference near zero is always required. The process then returns to the standby state in step (1).

3.Simulated Voltage Sag Experiment (Power Source Voltage Drop Experiment)

In the experiment, we performed a simulated voltage sag test by switching an auto-transformer tap with an electromagnetic switch. Figure 1 shows the configuration of the test system.

3.1 Content of the voltage sag experiment and voltage sag determination

The flywheel system used in the voltage sag experiment was a system in which a 200-kJ flywheel was connected to an 11-kW-class squirrel-cage induction motor. Detection of the voltage drop involved calculating the three-phase instantaneous voltage by spatial vector computations, and monitoring the power flow to SW1 as well. A voltage sag was identified when the voltage shortfall detection threshold was 80% of the rated voltage (effective value: 160 V) and the power flow was reversed. The experimental conditions were set to a resistance load of 7.2 kW, and the self-excitation capacitor was set to 750 mF (reactive power: 9.3 kvar), which was optimal for 7.2 kW. A voltage drop width of 30% (residual current of 70%) was simulated.

Fig. 2. Experimental results of the voltage sag test in the case of a 7.2-kW load.

3.2 Results of the voltage sag experiment

Figure 2(a) shows the results of the experiment. A voltage sag was detected at virtually the same time as the simulated voltage sag started. Because the interconnection switch is a thyristor, there is a period of approximately one-fourth of a cycle in which OFF cannot be set. We confirmed that during this period, the load voltage wave- form is chaotic, but thereafter the induction motor acts as an induction generator due to capacitor self-excitation, and a suitable voltage is generated. We then confirmed that because power is also restored in the same phase during power restoration [Fig. 2(b)], reconnection to the system is accomplished smoothly. The present voltage sag compensator does not use a semiconductor power converter to generate an AC voltage, and thus a sinusoidal voltage greater than 97% of the fundamental is generated without a filter even during compensation.

4.Design Guidelines for the Flywheel Stored Energy Capacity

There are two points to be taken into consideration when the frequency drops and reconnection is performed during compensation in the present voltage sag compensator as described above.

(1) Reconnection to the grid cannot be performed at an arbitrary period. After the start of compensation, standby is essential until the voltage phase difference from the grid side reaches zero again.

(2) In the present method, the induction generator is reconnected directly to the grid without a semiconductor power converter. As a result, even when the instant of zero voltage phase is reached, if the frequency drops too much, excess current due to excess acceleration torque flows during reconnection, and consequently a frequency lower limit (90 to 95%) must be set. The lower limit to the frequency drop during compensation is set while taking the above two points (voltage phase zero and frequency lower limit) into consideration. The flywheel stored energy capacity leading to the same phase when the lower limit of the frequency is reached is the optimal flywheel stored energy capacity for the present voltage sag compensator. Design guidelines are given in detail below.

4.1 Derivation of the phase matching time

When the load power to be protected is Pload, the mechanical power input to the induction machine from the flywheel is Pme. The mechanical energy ΔE that the fly- wheel releases in the compensation time t is

Here ωn, ω(t), and I represent the standby rotational angular velocity of the flywheel, the rotational angular velocity function after the start of compensation, and the inertial moment. The rotational angular velocity function ω(t) can be rewritten as

On the other hand, the relation between the frequency F(t) of the induction generator and the rotational angular velocity is represented by

Here p is the number of pole pairs, S is the slip of the induction generator (although a negative value; S is a positive value due to inversion of the immediately preceding sign). With the slip at rated power denoted as sn and the rated power of the induction machine as Pn, we have

Therefore, if the rated frequency (grid frequency) is Fn, then the frequency difference ΔF(t) is

The time integral of this frequency difference is the phase angle θ, and the time t at which θ = 2π is the phase matching time Tmatch:

Here time integral (2), the rotational angular velocity function, is relatively complex. Further, Eq. (6) cannot be solved analytically in the form given. As a result, the rotational angular velocity function ω(t) is approximated linearly as

This is because when the compensation time is sufficiently small compared to the acceleration constant H = E/Pn for the rotating body, the drop in the rotational angular velocity is linear. Here k is a proportionality constant,

and is defined as the tangent slope of the rotational angular velocity function at t = 0. Hence, if Eq. (6) is rewritten using the voltage phase difference Θ of the grid side and the load side, the second-order constraint equation

is obtained. Solving this equation, we obtain

Thus, as shown in Eq. (11), after the start of compensation, the time Tmatch at which the voltage phase reaches zero again is θ = 2π, and is determined by the load power, the inertial moment, and the rated slip. Conversely, if the time Tmatch at which the same phase is reached is specified, then the required moment of inertia Imatch is determined by the time and load power, as shown in Eq. (12).

4.2 Flywheel design using the set frequency lower limit

The lower limit of the frequency must be given closer consideration when designing a flywheel using the constraint equation in the previous section. That is, the frequency drop up to the time at which the voltage phase difference again reaches zero must be at least ΔFlimit. Then the constraint equation for the frequency drop is represented by

Solving this equation, we can express the necessary mini- mum inertial moment Imin and stored energy Emin by means of the following equations (see Appendix):

The time at which the same phase is reached for the stored energy Emin is

based on Eq. (11), which determines the minimum period of the compensation time.

4.3 Design of a 50-kW-class system for the voltage sag compensator

We designed a 50-kW-class system for the voltage sag compensator based on the calculations in the previous section. Table 1 gives the design conditions. Specifying a lower frequency limit 5% below the grid frequency (ΔF = 0.05), calculations were performed with the rated slip sn = 0.019 (based on a list of results for a prototype 55-kW-class induction motor) for the 55-kW-class induction motor with four poles at ωn = 1500 rpm. The necessary minimum moment of inertia to compensate a load at a load power of Pload = 55 kW (based on 92.5% efficiency of the induction machine, Pme = 59.5 kW) is found from Eqs. (15) and (17):

Therefore, based on Eq. (16), the necessary minimum stored energy is

If design is performed as described above, then the compensation time when compensating a constant load at Pload = 55 kW is 583 ms

4.4 Reduction of flywheel capacity due to an improved interconnection switch

In order to restore power in the same phase when reconnecting to the grid as in the calculations in the preceding section, θ = 2π rad = 360° is assumed in Eq. (6). Thus, as shown in Fig. 3, if the interconnection switch is configured in a 9 TRIAC arrangement such as a matrix converter, then reconnection to the grid is possible in increments of θ = 2π/3 rad = 120°. In this case, the number of semiconductor switches increases, but as shown in Fig. 3, the TRIAC drive circuit has an extremely simple configuration with only a photocoupler and there is no need for an insulated power supply. Furthermore, because only three of the TRIACs have current passing through them at all times, the heat sink size (°C/W) and the constant loss in the switch do not change.

Fig. 3. Interconnection switch configuration with nine bidirectional thyristor switches.

Based on this idea, Fig. 4 shows the relationship between the compensation time and the frequency difference for compensation of the rated power. The horizontal axis represents time, and the vertical axis represents the difference ΔF(t) between the grid frequency Fn and the induction generator frequency. First, if the moment of inertia of the flywheel is infinitely large, then the frequency difference is constant at Fn – Fn/(1 + S). In this case, the time to reach the same phase is I = ∞. As a result, rearranging Eq. (10) and setting k = 0, we obtain

Fig. 4. Relationship between the compensation time and the frequency difference.

Next, when the moment of inertia is finite, the frequency difference ΔF(t) varies linearly with respect to time. If the frequency difference reaches a limit, then at the same time the moment of inertia at which the voltage phase difference changes to a constant curve with θ = 2π rad is Imin. That is, the area enclosed by the origin, point C, point A (point B when θ = 2π/3 rad), and Tmin is Θ = 1 (1/3 when θ = 2π/3 rad). The voltage phase differences q that can be selected depend on the number of phases: for three phases, there are three, namely, 2π, 4π/3, and 2π/3.

4.5 Flywheel guidelines based on an improved grid interconnection switch

Table 1. Design conditions of a 50-kW-class system

Using the improved grid interconnection switch de- scribed in the previous section, design was performed for the conditions listed in Table 1. The relationship between the compensation time and the stored energy when compensating rated power at 55 kW is shown in Fig. 5. If design is performed using region I (the dotted curve) in Fig. 5, then phase matching is reached at a given stored energy and the desired time, but the region is one in which the frequency drops below 95%. Conversely, if design is performed using region II (the dotted curve), the result is an overdesigned region in which there is still a margin for voltage drop when phase matching is reached in the desired time. Hence, the design point (optimal point) at which the frequency is 95% when phase matching is reached is the point at which the curves in Fig. 5 and the 5% frequency drop line intersect, so that

Fig. 5. Relationship between compensation time and stored energy for the 55-kW load case.

If the stored energy is greater than Emin, then the frequency drop is kept within 5% and reconnection to the grid is possible.

5.Experimental Evaluation of the Design Guidelines for a 50-kW-Class Test System

Based on the design guidelines in the previous section, we prototyped a 50-kW-class test system and con- firmed the validity of the design principles. The results are described below.

5.1 Specifications of the test system for the 50-kW-class voltage sag compensator

Because the majority of voltage sags are concentrated in the range of 100 to 200 ms [4], we created our test system using the test model point (reconnection to the grid at θ = 2π/3 rad) shown in Fig. 5. Table 2 lists the specifications for a 50-kW-class voltage sag compensator using the prototyped vertical-axis flywheel. Figures 6 and 7 show the external appearance.

Table 2. Test model specifications of the proposed 50-kW voltage sag compensator

5.2 Experiment to confirm the validity of the design guidelines

In order to confirm the validity of the design guide- lines for the proposed voltage sag compensator using the prototyped vertical-axis flywheel, we performed an experiment involving the opening of grid interconnection switch M1 rather than an experiment with a simulated voltage sag using the experimental configuration shown in Fig. 1. The capacitor value used for the self-excitation phenomenon was selected appropriately to the load [14], so that the induction generator produced approximately the rated volt- age Vn over a constant period during compensation. In practice, the load power often fluctuates, and countermeasures to automatically switch the capacitance as appropriate based on the fluctuations are extremely important. We performed our experiment by varying the compensation load from 10 kW to 55 kW. The total standby loss (iron loss, copper loss, wind loss, bearing loss) was approximately 1.77 kW.

Figure 8 shows the experimentally determined matching time Tmatch for the same phase with respect to the mechanical input power Pme (the measured load power Pload divided by the efficiency of the motor with that load = the value for the mechanical load of the flywheel). For the voltage phase difference, the output q of the phase- locked loop (PLL) where the d axis voltage of the induction generator voltage is zero is calculated, and the times at which the voltage phase difference is 120°, 240°, and 360° are measured. As can be seen in the figure, the experimental results and the values calculated using Eq. (11) agree well. When the calculated value is taken as the true value, the error is positive (approximately +7% at most), and the time until the phase again matches is slightly longer.

We also evaluated the induction generator frequency at phase match. Figure 9 shows the voltage phase difference and the frequency of the induction generator and the grid when the load power Pload is 10 kW. The frequency on the vertical axis was calculated from dθ/dt for the PLL. The figure confirms that the voltage phase difference expanded steadily from t = 0 s before compensation, and its time variation agreed well with the calculated values. The frequency dropped steadily, and at t = 0.613 s a voltage phase difference of 120° was obtained. The frequency at this time was 49.1 Hz. Figure 10 shows the voltage drop at phase match when varying the load power Pload as above. The experimental values for the voltage drop are more stable than the calculated values and the agreement is good. These results confirm the validity of the design guidelines in Section 4 for a system that compensates a 55-kW load for 0.22 second by reconnecting the test system to the grid at a voltage phase difference of 120°, using the grid interconnection switch in Fig. 3.

Fig. 6. Photograph of the test model, a proposed 50-kW voltage sag compensator.
Fig. 7. Photograph of the flywheel of the proposed 50-kW voltage sag compensator.
Fig. 8. Experimental results for the mechanical input power versus compensation duration.
Fig. 9. Time variations of the phase difference and IG frequency in the case of a 10-kW load power.
Fig. 10. Experimental results for the mechanical input power versus IG frequency at the end of the compensation period.
6.Conclusions

A flywheel stored energy of approximately 50 kJ is required for compensation of approximately 0.17 second when designing a 10-kW system (electrical output of 11 kW), as was the case in the previous section. If a two-pole system is used, then a voltage sag compensator with a simple horizontal axis can be created merely by having an approximately 65-kg flywheel overhang on the axis of the 11-kW-class squirrel-cage induction motor (horizontal axis). Thus, in this paper we proposed a simple voltage sag compensator using a flywheel to deal with the problem of voltage sag, and clarified the following three points.

(1) A voltage sag experiment simulating a 30% volt- age drop confirmed the effectiveness of the proposed method, which maintained approximately the rated load voltage even during reconnection immediately after the start of a voltage sag.

(2) We clarified flywheel design guidelines for our voltage sag compensator. We showed that a flywheel stored energy capacity of 180 kJ is optimal for a 50-kW system when the frequency drop during reconnection is 5%, and that the compensation time is approximately 0.20 second.

(3) We created a 50-kW-class test system (flywheel stored energy 220 kJ) based on the design guidelines. Experiments showed that the designed values and the experimental values agreed well, and demonstrated the validity of the design guidelines for a load power of 55 kW and an approximately 0.22-second compensation system.

REFERENCES
  1. Electric Technology Research Association. Countermeasures for instantaneous voltage sag. Electric Technol Res 1990;46(3).
  2. Niito T, Hayashi T. Current state and countermeasures for instantaneous voltage sag. Trans IEE Japan 2003;132:679–682.
  3. Sakamoto S, Abe M. Instantaneous voltage sag phenomenon. J IEE Japan 2008;128:598-601.
  4. Electric Technology Research Association. Current state and countermeasure technology for electric power quality in a distribution system. Electric Technol Res 2005;60(2).
  5. Committee on Technology for Industrial Power Electricity. Investigation into state of blackouts in factory electric equipment and trends in countermeasures. Tech Rep IEE Japan 2005;999.
  6. Matsuura T, Yoshino A. Countermeasures for instantaneous voltage sag. J IEE Japan 2008;128:603–605.
  7. Sakai Y. Device to compensate for instantaneous sag using an electric double layer capacitor. J IEE Japan 2008;128:610–613.
  8. Konishi Y. Device to compensate for instantaneous sag using a NAS battery. J IEE Japan 2008;128:606–609.
  9. Nagaya S, Hirano N, Shikimachi K. Device to compensate
    for instantaneous sag using SMES. J IEE
    Japan 2008;128:598–601.
  10. Nielsen JG, Blaabjerg F. A detailed comparison of system topologies for dynamic voltage restorers. IEEE Trans IA 2005;41:1272–1280.
  11. Kato S, Cheng M, Sumitani H, Shimada R. Semiconductor power converterless voltage sag compensator and UPS using a flywheel induction motor and an engine generator. PCC-Nagoya 2007, p 1680–1685.
  12. Kato S, Takaku T, Sumitani H, Shimada R. Development of voltage sag compensator and UPS using a flywheel induction motor and an engine generator. IEE Japan Trans IA 2007;127-D:844–850. (in Japanese)
  13. Murthy SS, Malik OP, Tandon AK. Analysis of selfexcited induction generators. IEE Proc-C Gener 1982;129:260–265.
  14. Chan TF. Analysis of self-excited induction generators using an iterative method. IEEE Trans Energy Conversion 1995;10:502–507.
APPENDIX

Derivation of Eq. (15)

On the left side of Eq. (14), the conditional equation for the frequency drop during reconnection can be converted to

by using Eqs. (8) and (11). Because pωn = 2πFn, the same equation can be represented as

using Eq. (13). Therefore, the inequality in Eq. (14) can be altered to

Because both sides of the inequalities are positive, the direction of the inequality sign does not change if both sides are squared. If Eq. (A.2) is rearranged by using Eq. (13) after squaring both sides, we obtain

which yields Eq. (15).

AUTHORS (from left to right)

Shuhei Kato, Miao-miao Cheng, Hideo Sumitani and Ryuichi Shimada

Shuhei Kato (member) completed the doctoral program in innovative energy at the Graduate School of Science and Engineering of Tokyo Institute of Technology in 2009. He is now engaged in research on energy storage using flywheels. He received a 2007 Institute of Electrical Engineers of Japan Excellent Presentation Award. He holds a D.Eng. degree.

Miao-miao Cheng (member) completed the M.E. program at Xi’an Jiaotong University in 2006 and entered the doctoral program in innovative energy at the Graduate School of Science and Engineering of Tokyo Institute of Technology. She is now engaged in research on flywheel energy storage for stabilizing distributed power source transients.

Hideo Sumitani (senior member) received a bachelor’s degree from the Department of Electrical Engineering of Tokyo Institute of Technology in 1959 and joined Toshiba, where he was engaged in the development, design, and production of AC electric motors for industry. In 1991 he joined Toshiba Techno Consulting. In 1998 he joined Tokyo Power Technical Services. In 2001 he joined Toshiba Technical Services International, and became a researcher at the Atomic Reactor Engineering Laboratory of Tokyo Institute of Technology, where he is also a visiting instructor.

Ryuichi Shimada (senior member) completed the doctoral program at the Graduate School of Tokyo Institute of Technology in 1975 and joined the Japan Atomic Energy Research Institute, where he worked on the development of the large-scale Tokamak JT-60 fusion reactor. In 1988 he became an associate professor in the Department of Electrical and Electronic Engineering in the Faculty of Engineering of Tokyo Institute of Technology. He was appointed a professor at the Atomic Reactor Engineering Laboratory there in 1990. In 2005 he became a professor at the Integrated Research Institute. He is primarily engaged in research on large-scale electric power systems, electric power engineering, electric power storage, power electronics, nuclear fusion reactor engineering, and plasma control. He has received the IEEJ Outstanding Paper Prize, Progress Prize, and Authorship Prize. He holds a D.Eng. degree.

Electrical Engineering in Japan, Vol. 181, No. 1, 2012
Translated from Denki Gakkai Ronbunshi, Vol. 129-D, No. 4, April 2011, pp. 446–452

Supraharmonics–The Next Big PQ Concern

Published by Mirus International Inc., Harmonic and Energy Saving Solutions: Supraharmonics–The Next Big PQ Concern, Sept. 2020

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Mirus International Inc., 31 Sun Pac Blvd., Brampton, Ontario, CanadaL6S 5P6, Tel: (905) 494-1120, Fax: (905) 494-1140, Toll Free: 1-888 TO MIRUS (1-888-866-4787), Website: www.mirusinternational.com, E-mail: mirus@mirusinternational.com



Power Factor Correction

Published by Electrotek Concepts, Inc., PQSoft Case Study: Power Factor Correction, Document ID: PQS0312, Date: April 16, 2003.

Abstract: Low power factor because it means that you are using the facility’s electrical system inefficiently. It can also cause equipment overloads, low voltage conditions, and greater line losses. Most importantly, low power factor can increase total demand charges and cost per kWh, resulting in higher monthly electric bills. This document provides an overview of the concept of power factor, including impacts on the electrical distribution system, effects on power quality, benefits of improvements, and estimating financial savings.

This case presents the applications of low voltage power factor correction capacitors to improve poor power factor.

PROBLEM STATEMENT

A large plastics plant is paying a significant power factor penalty each month. The utility has informed the plant that correcting the overall plant power factor to 95% will eliminate the penalty.

A summary of previous utility bills is provided in Table 1.

MonthkVAkWkVArPower Factor
Feb 19915880408042340.694
Mar 19915700390041570.684
etc.
Dec 19916120420044510.686
etc.
Average6079418544080.689
Table 1 – Previous Utility Bills
PRINCIPLES OF POWER FACTOR CORRECTION

Why Improve the Power Factor

The application of power factor correction capacitors is generally motivated by the desire to save money. Most often, this is a direct response to utility power factor penalties. However, there are several other reasons that a customer might decide to apply power factor correction capacitors.

  • Reduce electric utility bill
  • Release system capacity
  • Reduce current, (allowing additional load to be served)
  • Reduce I2R losses
  • Voltage control

While power factor correction alone is not a harmonic concern, it is nevertheless important to understand the relationship between capacitors and harmonic related problems.

Location for Power Factor Correction Capacitors

The benefits realized by installing power factor correction capacitors include the reduction of reactive power flow on the system. Therefore, for best results, power factor correction should be located as close to the load as possible. However, this may not be the most economical solution or event the best engineering solution, due to the interaction of harmonics and capacitors. Refer to Figure 1 for a oneline representation of possible placement options for power factor correction capacitors.

Often capacitors will be installed with large induction motors (C3). This allows the capacitor and motor to be switched as a unit. Large plants with extensive distribution systems often install capacitors at the primary voltage bus (C1) when utility billing encourages power factor correction. Many times however, power factor correction and harmonic distortion reduction must be accomplished with the same equipment. Location of larger harmonic filters on the distribution bus (C2) provides the required compensation and a low impedance path for harmonic currents to flow.

Figure 1 – Location of Power Factor Correction Capacitors

Evaluating the Effectiveness of a Capacitor Application

Several simple equations can be used to determine the effectiveness of power factor correction. The voltage improvement realized with the installation of capacitors is determined from:

where:

%ΔV = voltage rise (percent)
kVArcap = capacitor bank rating (kVAr)
kVAtx = step-down transformer rating (kVA)
Ztx = step-down transformer impedance (percent)

Although capacitors raise a circuit’s voltage, it is rarely economical to apply them in industrial plants for that reason alone. The reduction in power system losses is determined from:

where:

%lossreduction = reduction in losses (percent)
PForiginal = original power factor (per unit)
PFcorrected = corrected power factor (per unit)

Financial return from conductor loss reduction alone is seldom sufficient to justify the installation of capacitors. It is an added benefit, especially in older plants with long distribution feeders. The optimum location of the power factor correction capacitors can be determined from a load flow analysis. However, it is important to remember that harmonic considerations are often more important than correction. Finally, the percent line current reduction can be approximated from:

where:

%ΔV = current reduction (percent)
θbefore = power factor angle before correction (degrees)
θafter = power factor angle after correction (degrees)

Displacement Power Factor vs. True Power Factor

The traditional method of power factor correction, both on the power system and within customer facilities has been the applications of shunt capacitor banks. This is based on the fact that most loads on the system draw a lagging current (partially inductive) at the fundamental frequency. Capacitors draw a leading current at the fundamental frequency and, therefore, can compensate for the current drawn by inductive loads (motors are the most important).

These characteristics of leading and lagging current are based on the assumption that loads on the system have linear voltage-current characteristics and that harmonic distortion of the voltage and current is not significant. With these assumptions, the power factor is equal to the displacement power factor (DPF). Calculation of the displacement power factor is completed using the traditional power factor triangle, and is summarized with the following relationship (shown in Figure 2):

Figure 2 – Displacement Power Factor Triangle

Harmonic distortion in the voltage and/or current caused by nonlinear loads on the system changes the way power factor must be calculated. True power factor (TPF) is defined as the ratio of real power to the total volt-amperes in the circuit.

This is a measure of the efficiency with which the real power is being used. Since capacitors only provide reactive power (VArs) at the fundamental frequency, they cannot correct true power factor when there are harmonics present. In fact, capacitors can make true power factor worse by creating resonance conditions which magnify the harmonic distortion in the voltage and current.

Adjustable-speed drives (ASDs) using pulse-width modulation (PWM) technology are a particularly important example of the difference between true power factor and displacement power factor. These drives use a diode bridge rectifier to convert the ac power to dc. As a result, these drives have a displacement power factor very close to unity. However, the harmonic distortion of the input current can be very high. This low true power factor cannot be improved with capacitors. Harmonic filtering is the most common way of improving power factor for this type of load.

Displacement power factor is still very important to most industrial customers because utility billing for power factor penalties is almost universally based on displacement power factor. Metering used to measure power factor is based on VAr meters that are only responsive to the fundamental frequency components of the voltage and current. Therefore, utilities do not currently penalize customers for the inefficiencies introduced by harmonics in their loads.

Typical Equipment Power Factors

The typical displacement power factor for individual equipment types is summarized in Table 2.

Table 2 – Typical Equipment Power Factor

Motor Power Factor Correction Example

The following example illustrates the correction of a 500 HP induction motor with an assumed power factor of 85%. The customer desires correction to 95%. The assumption of HP = kVA is used to determine the following:

Figure 3 – Motor Power Factor Correction

kVArrequired = (425) ∗ (tan31.8 – tan18.1) ≈ 125kVAr

where:

Original power factor angle = cos-1(0.85) = 31.8°
Desired power factor angle = cos-1(0.95) = 18.1°

Displacement vs. True Power Factor Example

The impact of harmonic distortion on power factor is illustrated using the PWM ASD current waveform shown in Figure 4.

Figure 4 – Typical PWM ASD Current

The rms current, for the drive waveform, is determined from the following equation:

Note: Harmonic spectrum data obtained from Fast Fourier Transform (FFT) on measured waveform

The total harmonic distortion (THD), and crest factor (CF) for the current waveform are determined from:

Note: Ipk obtained from measurement data.
Note: Crest Factor for a single-frequency sinusoidal wave (no distortion) is 1.412

For the drive current illustrated, it is assumed that the fundamental components of the current and voltage are in phase – displacement power factor = 100%. Actual values for waveforms of this type range from 95-98%. If we assume that the voltage distortion is negligible, the real power consumed is:

P = V1 ∗ I1 * cosθ = (480 V) (1.63 A) (1.0) = 782.4 W

The true power factor can then be determined from:

TPF = P / (Vrms ∗ Irms) = 782.4 W / (480 V * 2.913 A) = 0.56 = 56%

INDUSTRIAL PLANT POWER FACTOR CORRCTION

Recalling, from Table 1, the plant’s previous utility bills. The average power factor is corrected to 95% using the following method:

MonthkVAkWkVArPower Factor
Feb 19915880408042340.694
Mar 19915700390041570.684
etc.
Dec 19916120420044510.686
etc.
Average6079418544080.689
Table 1 – Previous Utility Bills

kVArrequired = (kW) ∗ (tanθ1 – tanθ2)

kVArrequired = (4185) ∗ (tan46.4 – tan18.1) ≈ 3000kVAr

where:

θ1 = cos-1 (4185 / 6079) = 46.4°
θ2 = cos-2 (0.95) = 18.1°

After the installation of 3000kVAr of power factor correction, the average load is:

Average kW: 4185kW
Average kVAr: 1408kVAr (4408-3000)
Average kVA 4416kVA
Average PF: 95.0%

SUMMARY

Power factor is a measurement of how efficiently a facility uses electrical energy. A high power factor means that electrical power is being utilized effectively, while a low power factor indicates poor utilization of electric power. Low power factor can cause equipment overloads, low voltage conditions, and greater line losses. Most importantly, low power factor can increase total demand charges and cost per kWh, resulting in higher monthly electric bills.

Low power factor is generally solved by adding power factor correction capacitors to a facility’s electrical distribution system. Power factor correction capacitors supply the necessary reactive portion of power (kVAr) for inductive devices. The principle benefit is lower monthly electric bills.

REFERENCES

IEEE Recommended Practice for Electric Power Distribution for Industrial Plants (IEEE Red Book, Std 141-1986), October 1986, IEEE, ISBN: 0471856878

IEEE Recommended Practice for Industrial and Commercial Power Systems Analysis (IEEE Brown Book, Std 399-1990), December 1990, IEEE, ISBN: 1559370440

IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems, March 1988, IEEE, ISBN: 0471853925

RELATED STANDARDS
IEEE Standard 1036-1992

GLOSSARY AND ACRONYMS
ASD: Adjustable-Speed Drive
CF: Crest Factor
DPF: Displacement Power Factor
PWM: Pulse Width Modulation
THD: Total Harmonic Distortion
TPF: True Power Factor

Power Quality Issues in Smart Grid Environment – Serbian Case Studies

Published by

ALEKSANDAR JANJIĆ, Department of renewable energy sources, R&D Center “Alfatec” Ltd. Bul. Nikole Tesle 63/5,18000 Niš, SERBIA, aleksandar.janjic@alfatec.rs

ZORAN P. STAJIĆ, Faculty of Electronic Engineering, University of Niš, Aleksandra Medvedeva 14, 18000 Niš, SERBIA, zoran.stajic@alfatec.rs

IVAN RADOVIĆ, ED “Elektrošumadija” Kragujevac, ED “Centar” d.o.o. Kragujevac, Slobode 7, 34000 Kragujevac, SERBIA, ivan.radovic@eskg.rs

Abstract: – The paper discusses power and especially voltage quality issues in the smart grid environment. New demands that are facing the distribution network, by introducing the concept of intelligent networks (Smart Grids), are presented. Some examples of non compliance of laws and practices in Serbia are presented as well, as the illustration of lack of strategic planning in the field. Through several case studies, a few typical problems regarding power quality, occurring in the electrical utilities in Serbia, which have to be solved in a new environment are presented. In the end, the conclusion and specific suggestions in regard with the importance of strategic planning and preparation for the customization to the expected changes are given.

Key-Words: – power quality, smart grids, power quality monitoring, harmonics, volt var control

1 Introduction

European Smart grid concept – The EU Smart Grids Technology Platform vision and strategy for Europe’s Electricity Networks of the Future was launched in 2006 [1]. The Smart Grid vision is aiming for “new products, processes and services, improving industrial efficiency and use of cleaner energy resources, while providing a competitive edge for Europe in the global marketplace”. The Smart Grid vision is highly important as a mean for support of the EU environmental as well as economical ambitions. Many of new technologies are involved, such as renewables, electric cars, and power flow control equipment, while an increased use of digital communication and control, including smart metering and advanced grid wide area real-time monitoring, can also be expected.

Principal functionality characteristics of Smart Grids are [2, 3]:

  1. Active consumers participation;
  2. Seamless accommodation of all generation and storage options;
  3. Provision of new products and services, and opening of new markets;
  4. Power quality (PQ) for the digital economy;
  5. Optimization of asset utilization;
  6. Anticipation and response to system disturbances (self-heal);
  7. Resilience against attack and natural disaster (cyber security).

To fulfill these requirements, the evolution of existing grids is necessary, and it includes:

  • high use of renewables 20% – 35% by 2020,
  • bidirectional metering,
  • distributed storage,
  • smart meters that provide near-real time usage data, time of use and dynamic pricing,
  • smart appliances communicating with the grid, energy management systems in homes, and industrial facilities linked to the grid,
  • growing use of plug-in electric vehicles
  • networked sensors and automated controls throughout grid.

However, this evolution of existing grids will confront them with new challenges regarding power quality issues. Regarding distributed generation for instance, depending on applied technology (synchronous, single or doubly fed induction machines, or inverter technology) influence on power quality will be manifested through [4]:

  • magnitude of supply voltage,
  • increased unbalance,
  • transient overvoltages,
  • voltage sags, and
  • flickers.

Based on this facts, one can conclude that voltage quality is becoming increasingly important to customers for two reasons:

a) Voltage quality levels are affected by the increased use of distributed generation and different electronic devices (inverters, battery chargers, energy saving lamps).

b) Sensitive electronic devices are strongly affected by voltage quality.

Not only for consumers, but for all stakeholders involved in new, smart grid environment, power quality deserves particular attention. Thus, potential disturbance source may be found on both, generation and consumer side. From regulator point of view, it is important to asses what should be consider in establishing a regulatory framework for voltage quality in distribution networks.

The aim of this paper is to emphasize the need of improved and enhanced power quality monitoring, taking into account new requirements and new technologies of Smart grid. Finally, actions regarding power quality cannot be treated independently, without broad strategic planning frame.

In the following Section, the need for change of actual power quality policies and the need for integrated planning of all power aspects are presented through some examples of Serbian Power Industry.

In the Section 3, new smart grid functions addressing power quality aspects are presented. Through several study cases from Serbian Electrical Utilities, the need for integrated platform including power quality is presented.

Finally, conclusions are brought regarding the change in power quality treatment in the new environment.

2 Strategic planning regarding power quality in the new environment

Until now, the main focus of quality regulation has been on the reliability and commercial dimensions of quality. In contrast, there is far less experience with the issue of voltage quality regulation, especially in integrated, multi-functional and multicommunication platform like smart grid.

The proper approach to the smart grids and all matters related to this concept, and the issue of power quality, can be of a crucial importance for the countries that will be found in the way of its application.

If serious attention is not given to strategic planning and appropriate actions for preparing the system to move to a new concept are not taken, one can easily get into a situation that much greater financial resources are spent to remedy the consequences of damage, loss coverage, or on payment of fees and penalties. The only alternative is the timely planning and implementation of actions to predict and mitigate the occurrence of such losses and to optimize the adaptation to market conditions.

Disharmony between regulatory requirements and actual network level will be explained in the case of Serbian Electric Power Industry in the last decade. First example was the question of increasing the nominal voltage in low voltage distribution systems from 380 to 400 V.

Being aware of this change, many countries have made adequate preparations so the transition did not cause adverse effects. On the other hand, Serbia did not have an adequate attitude towards this issue, so the transition to a higher voltage level was carried out without any previous preparation. As a consequence, because motors in electrical drives were not replaced with new ones, designed for rated voltage of 400 V, a large increase of reactive power consumption appeared in the whole distribution system. This is especially contributed by the fact that, with the changes of rated power, the maximal allowed voltage in distribution networks in Serbia has increased even at 440 V. The second negative consequence was much larger number of failures in electrical drives.

Another example of poor strategic planning was the lack of high level incentives for customers to reduce their reactive power consumption. Without these incentives, consumers did not have any interest to invest in reactive power reduction. The problem could have been easily resolved by introduction of an appropriate tariff system. Since this was not done, after an increase of reactive power consumption in the system, Electric Power Industry of Serbia has invested in installation of reactive power compensation units in distribution networks, with the total installed capacity of 600 MVAr.

The previous examples show that due to lack of strategic planning and appropriate actions, the huge financial resources have been spent on unnecessary delays in manufacturing processes, repair of damaged equipment, insurance premiums, coverage of unnecessary energy losses and the investments in equipment that have not been necessary. All these actions have treated only the consequences, not the real causes of the problem.

By the introduction of the smart grid concept, the focus is changed, and new information and telecommunication infrastructure is required, as presented in figure 1. Power quality monitoring has to be included in this new infrastructure as well.

Figure 1. Smart grid overview
3 New Smart grid functions and power quality

The effective realization of smart grid concept is not possible without advanced distribution network automation. This automation introduces advanced distribution network operation as well, through the set of advanced distribution functions. The key aspect of electricity supply quality in a power system is the optimal application of voltage levels to all transmission and distribution networks. With significant penetration of distributed generation, the distribution network has become an active system with power flows and voltages determined by the generation as well as by the loads. Growing customer expectations and using of sophisticated electrical equipment are putting an additional responsibility upon the network operator to ensure that the delivered level and quality of supply are maintained within the parameters previously set by the regulatory bodies, while the maximal amount of distributed generation to be installed and operated is permitted at the same time. Some of innovative solution in that field are elaborated in [5, 6, 7, 8].

Integrated Volt/Var control is an important and one of the most desirable functions of a modern Distribution Automation (DA) system, as an integral part of Smart Grids. This function deals with the complexity of voltage and reactive power control in distribution systems. This complexity usually limits the capabilities of local automatic controllers which conventionally control Load Changing Transformers (LTCS) or Voltage Regulators (VRS) on the bases of local voltage measurements, and, Capacitor (CAP) banks on the bases of temperature or voltage changes.

Performing the Volt/Var control in an integrated manner provides a flat voltage profile over the feeder and at the same time minimizes the power loss in the system. In addition, a coordinated operation of VRS and CAP banks permits avoiding of an excessive and unnecessary tripping of these devices.

Centralized voltage and reactive power control is typically considered the most cost effective function of real-time DA. Rule based Centralized Capacitor Control with an objective of unity power factor has a relatively long history of real-time implementation. With development of a more reliable real-time Power Flow, the power flow based on Optimal Volt/VAr control attracts more and more attention.

Optimal Volt/VAr control allows a wider choice of objectives which can be achieved with higher mathematical accuracy. The objective of operating the distribution network within voltage and loading constraints serves as the primary objective, where other objectives – power losses, demand, etc. – serve as secondary. In addition, more and more distribution utilities are investing in remotely controlled capacitors and step voltage regulators as part of their distribution automation strategy. This offers the opportunity for periodic closed loop Volt/VAR control, which determines the optimal set of control actions and executes them immediately.

Fault Location, Isolation, and Restoration applications in a DA environment have also recently increased in importance. The trend for these applications is going towards more intelligent solutions that react to fault events and assist the operator in clearing and restoring the fault or taking action without any operator interaction at all. Fault location programs evaluate the SCADA information of breaker trip events and faults.

However, the proper introduction of these function is not possible without advanced monitoring of all important values in the power network, including the monitoring of voltage quality. In other words, power quality monitoring, together with the proper information and telecommunication techniques, is becoming the back bone of fully implemented smart grid.

A few of the case studies taken from authors experiences in Serbian power network will demonstrate the need of advanced and integrated measurement and data analysis.

3.1 Case Study 1

The first case study represents the common problem of voltage reduction in the transmission system. Due to some problem of unbalance between production and consumption, transmission network operators are commonly performing the short term (1 – 2h) voltage reduction (of the order of 5 – 10%). This reduction is leading to the short term demand reduction, but after few hours, the demand is continuing to grow, because of the „pay back effect“. Consequently, the problem is the drastic decrease of voltage quality for many customers, affected by this wide area voltage reduction.

Figure 2 is representing voltages measured in one TS 10/0,4 kV, at the low voltage bus bars. The voltage magnitude decrease is of order of 10%, registered after 10 a.m. in total duration of 1 hour and 30 minutes.

Figure 2. Voltages measured at the low voltage bus bars in TS 10/0.4 kV „Kadinjača“ 31.01.2011.

The distribution company has not been warned, so the situation represented in figure 1 had as the result, many customers complaints of the low voltage in their households.

Figure 3 represents diagrams of active and reactive power from the TS 400/110 kV „Petrovac“ at one 110 kV transformer bay, which supplies, through one intermediate TS 110/35 kV „Ilićevo“ and one TS 35/10 kV „21. oktobar“, the TS 10/0.4 kV „Kadinjača“, represented in figure 2.

The measurement information system (MIS) in the TS “Kadinjača”, recorded data with 12 s time resolution. The architecture of measurement information system installed in TS 10/0,4 kV to record the parameters of voltage quality in power distribution networks is presented in figure 4.

Figure 3. Active and reactive power in the supply TS station 400/110 kV „Petrovac“ 31.01.2011.

The measurement system which measured the active and reactive power at 400/110 kV “Petrovac” recorded the data at 900 s (15 min), and forms of change shown in the diagram would not faithfully convey.

Figure 4. MIS architecture

The presented example aims to demonstrate the need of measuring information system with adequately allocated measuring units, and analysis software that allows the analysis of recorded data (for instance, data recorded from other distribution utilities which are equipped with similar devices). Figures 5 and 6 show the diagrams of voltage changes in two other TS 10/0,4 kV in other areas supplied by the same TS 400/110 kV.

Figure 5. Voltages measured at the low voltage bus bars in TS 10/0.4 kV “Vranje” 31.01.2011.
Figure 6. Voltages measured at the low voltage bus bars in TS 10/0.4 kV “Pirot” 31.01.2011.

It is shown that without data recorded by measuring information systems and proper analysis software, many phenomena affecting the quality of voltage in electricity distribution network, when their causes are out of the site of measurement (and even outside the territory covered by the entire company for distribution) often can not be explain.

3.2 Case Study 2

Above was already stated that performing the Volt/Var control in an integrated manner provides a flat voltage profile over the feeder while minimizing the power loss on the system. In addition, a coordinated operation of VRS and CAP banks permits avoiding of an excessive and unnecessary tripping of these devices. The simplified layout of one distribution feeder is represented in figure 7.

Figure 7. Simplified model of distribution feeder

The load connected to the main bus bars, presented in figure 7, represents one wood processing facility. Voltage variation is represented in figure 8. The problem in this particular case was the excessive operation of On Line Tap Changer (OLTC) in distribution transformer station. Only after installation of power quality measurement device and, what is more important, introduction of these measurement in the central data warehouse, the problem is solved by proper settings of OLTC in supply transformer station.

Figure 8. Voltages measured at the low voltage bus bars in TS 10/0.4 kV at consumer side

The same problem was registered in another TS 110/10 kV station, which supplied one TS 10/0,4 kV with voltage variations represented on figure 9.

Figure 9. Voltages measured at the low voltage bus bars in TS 10/0.4 kV in ED Nis at consumer side

Only after detection of sources of voltage variations at the lower level, the proper setting of OLTC in supplying station were possible.

3.3 Case Study 3

The final case study is dedicated to the problem of harmonics. The following is the example of electricity customer who injected into the network a large content of higher harmonics and caused unauthorized voltage drops of other electricity customers in the region. Figure 10 represents the active, reactive, and apparent powers of the consumer.

Figure 10. Active, reactive, and apparent powers of the consumer
Figure 11. THD factors of the consumer’s phase voltages
Figure 12. Corresponding phase power factors

Fig. 11 presents the high level of THDu (greater than 12%), while Figure 12 presents the corresponding power factor. Checking the technical requirements for the connection, the conclusion was that are connected to the network without their fulfillment.

4 Conclusion

The paper points out that the problem of monitoring power quality parameters in Serbia should be given far more serious attention in order to adopt laws and standards in the EU, and to fulfill requirements regarding EU Smart Grid technology platform.

It is shown that solutions for problems described above should not be sought independently but as part of the development concept of intelligent networks (smart grids).

Moreover, power quality problem can be one of additional “driving factors” for the implementation of Intelligent network in Serbia.

Finally, it is shown that only the elaboration of an integrated information platform is required for resolving of power quality issues in a satisfactory manner.

Acknowledgement: The work presented here was supported by the Serbian Ministry of Education and Science (project III44006).

References:

[1] Toward Smart Power Networks, Lessons learned from European research FP5 projects, European Commission, 2005.
[2] Strategic Research Agenda for Europe Electricity Networks of the Future European Technology Platform, European Commission, April 2007.
[3] Strategic Deployment Document for Europe Electricity Networks of the Future European Technology Platform, European Commission, April 2010.
[4] T. Degner, J. Schmidt, P. Strauss, Dispower, Distributed Generation with High Penetration of Renewable Energy Sources, Final Public Report, iSET, Kassel, 2005.
[5] M. H. J. Bollen, J. Zhong et all. Power Quality aspects of Smart Grids International Conference on Renewable Energies and Power Quality (ICREPQ’10) Granada (Spain), 23th to 25th March, 2010.
[6] H. Spaack et all. Intelligent Transformer Substations in Modern Medium Voltage Networks as Part of “Smart Grid” 7th Mediterranean Conference and Exhibition on Power Generation, Transmission, Distribution and Energy Conversion7-10 November 2010, Agia Napa, Cyprus (Paper No. MED10/240).
[7] J. Kester et all. A smart MV/LV station that improves power quality, reliability and substation load profile, 20th International Conference on Electricity Distribution Prague, 8-11 June 2009.
[8] J. Heckel, Smart substation and feeder automation for a smart distribution grid, 20th International Conference on Electricity Distribution Prague, 8-11 June 2009.

ISBN: 978-1-61804-023-7
Source URL: http://media.alfatec.rs/2011/10/Power-Quality-in-Smart-Grid-Environment-Serbian-Case-Studies.pdf