Lagging PF is due mainly to the reactive power demands of large inductive loads such as induction motors. Reactive power does no useful work, but all plant power system elements must nevertheless be sized to accommodate it. A ‘high’ PF system is considered to have values between 0.9 to 1.0, and ‘low’ PF systems have values less than 0.8 for in-plant power supply. The disadvantages of low power factor are:
− Increased losses: the current that carries reactive power leads to losses in electrical devices such as transmissions, distributions and in transformers. These I2R losses are real power and reduce the overall efficiency of the system.
− Reduced capacity: generators, transformers and other power system equipment carrying reactive power have a consequently reduced capacity for carrying real power.
− Increased maintenance: The heat, which accompanies these losses, often leads to reliability and maintenance issues and decreased component lifetimes.
− Reduced voltage regulation: low PF worsens systems voltage regulation of a transformer (RMI-Competitek,1996)
Most industrial customers, with the possible exception of utilities themselves, are penalized by the electric utility for low plant PF. Industrial process plant PF typically ranges from 0.87 to 0.95, but best practice calls for a 0.95 total PF (including
harmonics) and a fundamental PF greater than 0.97. Another design goal is to maintain high PF over the entire normal operating range of the equipment.
For coal-fired steam power plants the power factor of aggregated plant auxiliary loads, at the auxiliary transformer, is typically around 0.80~0.85 (ABB EBoP 2008). Note that this PF is lower than the industry averages described above.
The power factor at the unit step-up transformer is a bit higher, typically at 0.85 to 0.90, but may vary considerably depending on the type of customer loads served.
Reactive Power Compensation Concepts
The first approach to PF correction is prevention, beginning with the selection of high-PF, high efficiency motors that are correctly sized and operated. PF correction can be implemented at the inductive source, centrally, or as a mix of these two methods. Central PF correction at a distribution panel or switchboard has been referred to as ‘bank compensation’ because large rows or ‘banks’ of capacitors were used.
Reactive Power Compensation Terminology
Devices used to control power parameters (such as voltage and reactive power) in transmission and distribution systems are generally known as Shunt Connected Controllers, of which there are two basic types: Static Synchronous Generators (SSG) and Static VAR Compensators (SVC):
− A Static Synchronous Generator (SSG) is defined by IEEE as a self-commutated switching power converter supplied from an appropriate electric energy source and operated to produce a set of adjustable multiphase voltages, which may be coupled to an ac power system for the purpose of exchanging independently controllable real and reactive power. If capacitors are used instead of an active energy source, then the SSG device is known as a Static Synchronous Compensator (STATCOM). When a STATCOM is used for harmonic filtering it is called Active Power Filter. High-power STATCOMs use the same PWM technology as found in a VFD.
− A Static VAR Compensator (SVC) is defined by the IEEE as a shunt connected static VAR generator or absorber whose output is adjusted to exchange
capacitive or inductive current so as to maintain or control specific parameters of the electrical power system. The term static refers to the lack of moving/rotating equipment. An SVC does provide dynamic VAR compensation/control.
Reactive Power Compensation
PF correction which is matched and installed at the inductive source (a motor, a transformer or other inductive elements) has distinct advantages over central compensation. Correction at the source generally avoids problems with over-compensation, and no special switchgear and sophisticated switching or control devices are required. The PF benefits are enjoyed by all equipment upstream from that point. Other considerations in approaching PF correction are listed below:
− PF control strategy should include power parameter monitoring at strategic, large equipment points in the network. Voltage transducers on all phases should be specified for these points, as these will also provide warning of voltage phase unbalance (See section on Phase Voltage Unbalance for details)
− PF control should be considered together with harmonics, unbalance and other power quality issues. Some compensation solutions that employ capacitor/
inductor combinations are susceptible to damaging resonance at certain harmonic frequencies.
− Modern active filtering technology offers solutions, which allow central compensation for these issues from a single package. (See section on Power Quality-Harmonics, for details on active filters)
The amount of extra reactive power needed to compensate for inductive loads and their PF can be calculated from the reactive power balance formula:
Qk = P (tanϕn−tanϕd)
Where:
Qk = reactive power necessary for compensation; (kVAR) P = the load active power (kW)
tanϕn = the non-compensated tangent value
tanϕd = the tangent value that should be achieved by the compensation.
Recall that ϕ is the phase angle and that PF = cos ϕ, so therefore ϕ = arcos (PF).
More detailed formulas and sample calculations for sizing of passive central compensation circuit elements are from www.leonardo-energy.org, under the subject of ‘Centralized Reactive Power Compensation’
Motor Soft-Starting
The power system is stressed by direct on-line (DOL) motor starts; large induction motor DOL startups draw 5 to 8 times the normal operating current for a sustained period and at low power factor. Soft-starters typically reduce individual startup currents to only 1.5 to 2 times the operating current, improving PF during startup, but without speed control capability during normal operation. The reduced inrush current reduces the heat load on the motor, allowing more frequent starts between
cool-down periods. Soft-starting also allow the engineer more flexibility in right-sizing the components of electrical power system by reducing the peak loading.
See the section Motor Starting Conditions for more requirements on motor starting, and their connections to the power system.
The term ‘soft starter’ usually refers to a class of power electronics devices capable of ramping up voltage to achieve a smooth motor startup. It is important to note that VFDs can also provide soft-starting capability, along with the added benefit of high and constant PF across the operating speed range. When operational speed control is not required, however, soft-starters may be the more economical choice.
Static Synchronous Compensators (STATCOMs, described in the previous section) also provide soft-start capability. Unlike most VFDs, however, compensators can be serviced while the motor is running.
Synchronous Motors for PF Compensation
The IEEE standard Std. 666-2007 suggests that synchronous motors used on continuous loads can be run with a leading power factor and thus compensate for lagging power factors from other, smaller motor loads that are running throughout the day. ‘Because of their separate source of excitation, the load of synchronous motors can be increased without requiring any additional reactive power (the unity power factor motor), or the load can be increased and the motors will supply reactive power as well (0.8 power factor or overexcited motor).’ This recommendation applies only to continuous, low-speed and high-power applications. Also, the corrective benefits are at the major bus level in the plant; so losses due to poor PF on lower-level busses are not avoided (Competitek, 1996).
VAR Compensators
Network users on the demand side of the step-up transformer pay for both real and reactive power. Real power is billed by actual megawatt-hours consumed, but reactive power is billed as a demand charge based on the maximum required within the period. Statistically aggregated maximum demand will help determine the individual unit’s generator capacity and PF excitation level. When more reactive power is demanded, then the excitation may deliver it (within the generator capability curve), but the capacity for productive real power (MW) from the generator will be reduced. Freeing the generator to supply more real power would increase the capacity of the unit and the transmission lines to their maximum, thermal limits.
The amount of reactive power that the network demands from the generator is not constant; these mega-VARS (MVAR) can vary considerably, in both leading and lagging modes, throughout the day. Activation of a large industrial load on the
network will change the VAR demand on the network, for example. To manage changing network power factor needs, utilities may install sets of capacitors and reactors which can be mechanically switched in or out of service. These devices are known as mechanically switched capacitance (MSC) and reactance (MSR), and can be operated in under a second.
Some dynamic network events, such as lightning strikes, short circuits, or other faults, require a much faster and more accurate compensation response by the utility. Static VAR Compensators (SVCs) use the same power electronics technologies found in VFDs to switch in (or out) VAR-compensating elements as fast as 2 times per cycle. The term ‘static’ refers to the solid-state electronics’ lack of moving parts in this device when compared to mechanical (MSC or MSR) or rotating devices. SVCs are more expensive than the mechanical compensators, but they are continuously controllable, offer much faster and more precise response, without regard for hysteresis in the load pattern. In practice, these two VAR compensation methods are complementary; mechanical devices can switch in large steps, and the SVC can be used for fast and fine tuning of the compensation.
Figure 3.3 – SVC switches for reactance (left) and capacitance (right), (ABB Grid Systems,2009)
VAR compensators can be placed at any point in the electrical power system;
near the generator source, in the grid, or near the large consumer loads. VAR compensators can increase the net real power output of the generator, but they are not without small losses. These small losses can be further minimized by specifying more, smaller increments of capacitive and reactive elements, based on an LCC analysis.
The following case material was provided by Brian Scott of ABB Grid Systems.
A generator with rated output of 695MVA is currently producing 625.5 MW. The utility operator wishes to increase the real power output to 693 MW, an increase of 67.5 or almost 11%. The PF requirements are from 0.9 leading to 0.95 lagging.
The generator capability (P-AQ) curves in the figure below show the amount of reactive power required for each of these limits, without (left) and with (right) SVC compensation. Before starting an SVC design, it is recommended that power flow and voltage stability studies be performed. As with other compensation technologies, a harmonics analysis of the entire system is also necessary. And, as with all large equipment in the power system, a detailed understanding of the load pattern is important for engineering an optimal solution and for determining the desired operation points that minimize losses.
Figure 3.4 – Generator capability curves before (left) and after (right) SVC Var compensation, (ABB Grid Systems, 2009)
In a power plant unit, it is important to determine the combined capability of the turbine-generator system. The target may be to increase MW output by 10% by providing SVC compensation, but this can only be achieved if the turbine can indeed provide the extra power. If the turbine is not the bottleneck, then the extra power can be achieved. This extra power is produced with extra fuel, at the same heatrate as before, but the cost of increasing capacity through SVC compensation is less than one-third of new coal plant capacity.
For example; an SVC system sized to provide +300/-170 MVA compensation would cost over $US20M, not including installation or civil works. If the plant unit happens to be baseloaded, then the extra power freed up by the SVC can be sold at a rate higher than the rate earned by the generator capacity on standby to provide MVARs
In one case where PF was increased from 0.8 to 0.95, the efficiency of the GSU transformer increased by 0.06% due to PF improvement alone. For stable operation and other practical reasons, the PF at the generator cannot be increased much past 0.95.
Active Rectifier Units on Motor Drives
VFDs with an active front end (active rectifier unit - ARUs) can play an important role in improving industrial plant active power generation capability and leading phase operation improvement. A VFD with active front end design gives the possibility to supply reactive power (lead or lag) to the auxiliary power system to compensate the reactive power needs of the remaining constant-speed motors and the reactive power losses of auxiliary transformers.
Induction Motor
M Cos
MV BUS L
ARU DC-Link INU
Figure 3.5 – Schematic of VFD with active rectifier unit circuit, (ABB USCRC, 2008)
The reactive power compensation from ARUs is free-of-charge as long as the converter operational point is within its P-Q circle diagram.
Figure 3.6 – P-Q diagram showing ARU capability, (ABB USCRC, 2008)
The benefits of ARU compensation functions are twofold 1) Full balancing the reactive power demand of all auxiliary loads and thus gives the possibility for the generator to produce more active power, 2~3% of rated capacity while still maintaining the required external reactive power capability 2) Reactive power compensation from ARUs can improve the plant leading phase operation capability and also plant auxiliary system operation performance under various disturbances such as suppressing transient over-voltage or under-voltage caused by generator load rejection.