Six simple ways to reduce costs with power quality analysers

There are literally hundreds of power quality measurements that can be taken on electrical systems and equipment. Predictive maintenance measurements and power consumption measurements can help electrical contractors uncover hidden costs for their end-user customers, protect their equipment from damaging conditions, reduce their unscheduled downtime and improve the system’s overall performance.

The quality of the electrical power that is consumed by any company in its buildings and facilities is an important metric that all companies need to be conscious of. Power quality not only impacts the actual cost of the power consumed (and hence its carbon footprint) but it can also have a significant effect on both the performance and longevity of the equipment connected to the electricity supply.

But power quality in any installation is not a static characteristic. It is dynamic, changing over the life of the installation - the changes brought on by a number of internal and external factors. And because of this constantly changing situation, it is equally important for companies to ensure their electrical installations are optimised for high quality and efficiency.

There are six key measurements that electrical contractors can make to assist their clients in optimising their electrical installation. These involve predictive maintenance (PdM) measurements and power consumption measurements; and they can help uncover potentially hidden areas within an installation that are unnecessarily consuming excessive power and exposing equipment to the potentially damaging effects of sub-standard power quality.

The PdM measurements are:

• Voltage unbalance
• Total harmonic distortion
• Increasing phase current
• Voltage sags

The power measurements are:

• Peak demand
• Power factor or reactive demand

PdM measurement #1: Voltage unbalance

In a balanced three-phase system, the phase voltages should be equal or very close to equal. Unbalance is a measurement of the inequality of the phase voltages.

Voltage unbalance can cause three-phase motors and other three-phase loads to experience poor performance or premature failure because of:

• Mechanical stresses in motors due to lower than normal torque output;
• Higher than normal current in motors and three-phase rectifiers; and
• Unbalance current will flow in neutral conductors in three-phase wye systems.

Major costs are associated with motor replacement and lost income due to circuit protection trips.

The EN50160 power quality standard requires voltage unbalance, as a ratio of negative to positive sequence components, to be less than 2% at the point of common coupling. The National Electrical Manufacturers Association (US) specifications call for less than 5% voltage unbalance for motor loads. It would be appropriate to consult user manuals for the voltage unbalance of other pieces of equipment.

PdM measurement #2: Total harmonic distortion

Total Harmonic Distortion (THD) is the sum of the contributions made by all of the harmonics on the system. Harmonic distortion is a normal consequence of an electrical power system supplying loads with electronic componentry, such as computers, business machines, electronic ballasts for fluorescent lighting and automation and control systems.

Harmonic distortion can cause:

• High current to flow in the neutral conductors;
• Motors and transformers to run hot, which can thereby shorten the operating life of the equipment;
• Increased susceptibility to voltage sags, which can potentially cause spurious resets;
• Reduced efficiency of transformers or having to install larger units than are initially required, simply to accommodate the added effects of the harmonics; and
• Audible noise.

There are major costs associated with the shortened life of motors and transformers that operations managers and business owners must be aware of in understanding the total cost of ownership of any electrical system. And, of course, an even more challenging side effect to shortened equipment life is if the motors and transformers are part of a company’s production systems, where replacing them will require operational shutdowns that will adversely affect a company’s income and delivery output.

Below is a sample calculation to illustrate the cost of downtime as a result of electrical equipment failure:

Let’s assume the cost to replace a 100 KVA transformer is $7000, including labour, which needs to be replaced each year. Let’s also assume that eight hours of downtime is incurred each year, with an income loss of $6000 per hour. The total cost would therefore be: $7000 + (8 x $6000) = $55,000 annually.

Voltage distortion (THD) should be investigated if it is more than 5% on any phase. Some current distortion (THD) is normal on any part of the system serving electronic loads, however, current and temperature levels at the transformers should be monitored to be sure that they are not being over stressed by the distortions. It is important to note that neutral current should not exceed the capacity of the neutral conductor.

The most important areas to check are motors, transformers and neutral conductors that are serving electronic loads.

PdM measurement #3: Increasing phase current

As the insulation on electrical conductors and components deteriorates over time, some of the current begins to leak. Loads will draw slightly higher currents as they age; and they may send some of this leakage current into the grounding system. Faults within the equipment may also cause high ground current.

It is highly recommended to have the insulation on conductors and equipment periodically checked; and the simplest and best way to do this is with an insulation tester. However, the quality of the insulation of equipment can also be checked, while it is in service, by monitoring all of the currents, phase, neutral and ground, to make sure none of them are increasing significantly over the course of time.

Another potential problem that can be caused by excessive phase currents is that they can further damage the insulation of the conductors and overheat the load, again resulting in a shortened life of the load.

Overcurrent situations will also cause protection devices to trip, which can threaten to cause costly and annoying unscheduled equipment and system downtime. Major costs then occur as a result of the subsequent premature motor failure and the lost income due to overcurrent protection devices tripping out at unscheduled (and unwelcome) times.

Furthermore, excessive ground current can create an unsafe environment in many parts of the workplace, with voltages present on metal chassis, cabinets and conduits.

The nameplate rating of the load should never be exceeded. If you track the phase current being drawn by a load over several months or even years, you should be able to get a sense of whether the current is changing or not.

PdM measurement #4: Voltage sags

Voltage sags are momentary reductions in root mean square (RMS) voltage for periods ranging from one cycle all the way up to two minutes. It is not uncommon for loads to be added onto the electrical system within a facility without plant management being notified; and these loads may draw down the overall system’s voltage level, especially if these new loads draw high inrush currents. On top of this, as electrical systems age over time, the impedance of the system may increase, which then makes the overall system more prone to voltage sags.

Voltage sags can cause spurious resets on electronic equipment such as computers or controllers, while voltage sags on one or two phases of a three-phase load can cause the other phase(s) to draw a higher current in an attempt to compensate for the difference, which may then trip the overcurrent protection.

The main cost factors that can be affected by voltage sags are lost income due to computer reset, control system reset, vacuum fluorescent display (VFD) trip and shortened life span of the backup power system’s uninterruptible power supply (UPS) due to frequent operational cycling.

Most loads will operate at 90% of their nominal voltage. The Information Technology Industry Curve (ITIC) suggests that a single-phase computer equipment load should be able to ride through drops to approximately 80% of the nominal voltage for periods of up to 10 seconds and down to 70% of nominal voltage for up to 0.5 seconds.

Power measurement #1: Peak demand

It is normal for utility companies to monitor the amount of power that is consumed by a facility. Several times an hour, the utilities calculate the average demand for that time interval, while peak demand is qualified as the highest average demand during all of the intervals in a nominated billing cycle.

Utilities typically charge their customers on the basis of peak demand because they have to maintain infrastructure large enough to supply power at peak levels. Commercial and industrial customers can manage the high cost of peak demand rates by staggering their load cycles to reduce the total draw at any one time.

It is advisable to find out what demand interval the utility uses on your clients, measure the demand over time at the service entrance and then look for significant loads that are operating concurrently and use ‘demand measurement’ to verify the readings for the individual loads.

Let’s walk through another example: Your factory or office complex has an average consumption of 570 kWh during the working day, but hits a peak of 710 kWh most days. The utility company charges you for each 10 kWh over a 600 kWh threshold for the whole month, at any time that you exceed 600 kWh during a 15-minute peak measurement window. If you were to correct for power factor, mitigate harmonics, correct for sags and install a load management system, you would see a different power usage picture - one that you can calculate for yourself.

Power measurement #2: Power factor or reactive demand

Power factor compares the real power (measured in watts) that is being consumed to the apparent power (measured in volts-amps) of the load. For example, a purely resistive load would have a power factor of 1.0.

The power that is available to perform actual work is called ‘real power’ (measured in kW). Inductive loads such as motors, transformers and high-intensity lighting fittings introduce reactive power (measured in kVARs) into a power system. The system’s capacity is therefore rated by the apparent power (measured in kVA), which must be large enough to accommodate both the real power (kW) and the reactive power (kVAR). Since reactive power requires system capacity but performs no work, utilities and plants try to keep net kVARs low. High reactive power translates into a low power factor.

It is recommended to check if your clients’ utility rate plans impose any charges for reactive demand or for power factor, or have them check it for themselves. You should find out how the utility company measures the power factor or VARs. For example, are they looking at peak intervals or are they looking at averages?

Also, it is advisable to identify the loads that are causing any lagging reactive power and then develop a strategy to provide adequate power factor correction to counter this problem.

Sample calculation:

Let’s assume that the utility company adds 1% of demand charge for each 0.01 below PF of 0.97 and assume that the PF averages 0.86 each month and the demand charge is $7000. Therefore the calculation is (0.97 - 0.86) x 100% = 11%, yielding an avoidable annual cost of (11% x $7000) x 12 months = $9240.

What to check

Check if the utility rate plan imposes a charge for reactive demand or power factor. You should also find out how the utility company measures power factor or VARs. For example, are they looking at peak intervals or at averages? You should also identify any loads that are causing lagging reactive power and develop a strategy for power factor correction.