Waste not, want not.
At every stage of the electric system – from the generator to the outlet – there are energy losses. When energy is lost, utilities must generate or purchase additional energy to meet demand. In other words, inefficiency costs money.
A simple way to calculate loss in terms of cost is by multiplying the average cost of energy per megawatt-hour times the total energy losses. Another way is to find out the utility’s loss percentage, which is the ratio of total energy losses to total sources of energy. The median loss percentage for public power is 4.07%. Losses of more than 6% for public power utilities may suggest excessive physical losses.
There is a strong incentive for utilities to be able to use the most of the electricity they have. Efficiency isn’t just about cost – it is also a good gauge of system performance and health, and monitoring various items, such as excess heat from transformers and other equipment, can support increased reliability. The importance of efficiency to utilities is why it is a component of both the Smart Energy Provider and Reliable Public Power Provider designations.
Where do losses come from?
Some system losses are inevitable, and loss cannot be eliminated altogether.
Almost two-thirds of energy is lost in the generation and transmission of electricity.
At the distribution level, which is what most utilities manage, most losses occur in lines (overhead or underground) and transformers.
- Primary lines and regulators can account for nearly half of distribution system losses
- Transformers account for about 27% of distribution system losses
Losses in other devices, such as switches and breakers, make up a lower portion of losses, but may be significant in system secondaries where currents tend to be high.
Here’s a brief refresher on ways that public power utilities can work to reduce losses in conductors and transformers.
Reducing Conductor losses
Conductors allow the flow of electrical current. Conductors also offer resistance to the flow of current, which results in power loss. The loss of power (in watts) is represented by the familiar relationship:
The current carried by the conductor in amperes (A) and the electrical resistance in ohms (Ω) are symbolized as I and R, respectively. Resistance increases with the length of the conductor and decreases with the cross-sectional area of the conductor. Just as more water will flow through a wide pipe than a narrow one, electrical charge is higher, and resistance is lower on wires with greater cross-sectional areas.
Resistance, R, for a conductor is determined by the following equation:
R = ρL / A
The resistivity of an object is represented by ρ (rho) and is measured in Ω m (ohmmeters). L represents the length, and A represents the cross-sectional area of the material. The relationships shown in the equations confirm that the conductor resistance increases with greater length and declines with larger cross-sectional areas.
Typical conductors used in new overhead distribution are 336.4 kcmil 26/7, which implies 26 strands of aluminum conductor surrounding 7 strands of steel. The area of the conducting aluminum is 336.4 kcmils, where one kcmil is one thousand circular mils and one circular mil is the area of a circle having a diameter of one mil (0.001 inches). Older conductors, such as #4 AWG copper line, have a cross-section of 41.7kcmils.
The following simplified example is used to show how reconductoring can reduce line losses. If a utility replaces #4 AWG solid copper wire with 336.4 kcmil stranded aluminum wire on its distribution, it can reduce power loss by a factor of nearly 5.
|Conductor||Stranding||Circular mils||Allowable ampacity||Resistance ohms/mile||Line losses for 100-amp load at the end of a 1-mile line|
|4 AWG||Solid||41,740||170||1.314||13.14 kW|
Refurbishing or replacing old conductors is an important loss reduction technique and can provide increased capacity on the system. While reconductoring is theoretically a great option for reducing losses, the process, including new hardware, is costly.
Reducing Transformer Losses
Transformers step down the high voltage electricity from a power line to a lower voltage on the distribution system. Transformer losses fall into two categories — load losses (winding losses) and no-load losses (core losses). No-load losses occur continuously while the transformer is energized and load losses vary as the load changes.
Most transformer losses are load losses, which makes the calculation of load losses an essential element of any transformer evaluation.
The transformer capacity, or electrical size of a transformer, is rated in kVA. Transformer kVA loading is the product of current and voltage. kV is the rated transformer voltage in kilovolts and I is the transformer current in amperes. The product is approximately the same on either the primary or the secondary side of the transformer.
Single-phase transformers kVA loading = kV * I
Three-phase transformers kVA loading = √3 kV * I
The voltage for three-phase circuits in the above expression is the line-to-line voltage and the current being referenced is the line current. The transformer load is rated in kVA and is three times the loading per phase, assuming the phases are approximately balanced. The expression is valid for both delta and wye-connected windings.
Voltage in a distribution system must be maintained at or near the rated value. Transformer load losses, which vary closely with the square of the current, also vary approximately with the square of the transformer kVA loading. Load losses and no-load losses at rated transformer load can be obtained from manufacturer's data or from tests conducted on the transformer.
Some examples of technology options that manufacturers use to improve efficiency include:
- Higher-grade electrical core steels
- Different conductor materials
- Adjustments to core and coil configuration
Utilities can also build in guarantees against transformer loss values to purchase agreements with manufacturers, such as by:
- Requiring expanded manufacturer testing for large lots of transformers with supporting test documentation.
- Requiring on-site visits by utility personnel during manufacturer testing.
- Using an independent lab to test samples of transformers.
- Requiring price adjustments for transformers not meeting the guaranteed loss performance.
Other strategies for reducing and monitoring transformer loss include:
- Purchasing new transformers (and voltage regulators) based on a life-cycle cost evaluation.
- Using the line drop compensation feature on voltage regulators to avoid exposing the transformers closest to the regulators to voltages over 5% above rated.
- Using the smallest capacity transformer feasible for each installation, considering factors such as ambient temperature during peak load, duration of expected peak load, and expected load growth; this may rule out the use of completely self-protected (CSP) transformers, whose overload capacity is limited by the automatic operation of the integral secondary circuit breaker.
- Maintain records of which customers are connected to each operating transformer, and monitor customer load on each transformer; ensure that all abandoned transformers have been disconnected from the primary line.
Other Ways to Reduce Loss
There are many more ways to measure and reduce distribution system loss – some which are easier to implement and others which are associated with higher expenses. The more costly steps will typically involve economic life-cycle cost and engineering analysis.
- Regularly examine system performance – and be sure to have an accurate picture of your load factor.
- Pinpoint problem areas with physical losses.
- Prioritize upgrades based on biggest cost of energy or demand loss.
- Maintain equal (balanced) currents on all three feeder circuit phases as much as is practical.
- Use largest economical conductor for new primary circuits and keep secondary circuits as short as possible.
- Use the largest economical size conductor for new primary circuits and evaluate the benefits of three-phase versus single-phase construction; avoid the application of voltage regulators downstream from the substation where possible.
- Analyze capacitor banks to verify that capacitor size and location are properly matched to feeder load.
- Install capacitors to correct power factor based on metered feeder characteristics, computer-aided modeling, and life-cycle cost economic analysis.
- Check every meter multiplier recorded on the billing system against the corresponding multipliers marked on the meters every two years.
- Perform meter testing and calibration regularly. Test single-phase customer meters every eight years, polyphase meters every six years, and high-use meters (which bring in more than 3% of total system revenue) annually.
- Install substation metering/supervisory equipment for each feeder to obtain, at minimum, profiles of voltage, current and power factor versus time.
- Convert long, substantially-loaded single-phase circuits to three-phase.
- Convert one or more feeders to a higher voltage level
- Re-conductor the trunks of existing heavily-loaded circuits, beginning at the source end.
Increasing efficiency helps to continue to keep public power’s edge in reliability and affordability compared to our peers. Join the energy services listserv to share additional tips and strategies for reducing loss.
PS – Utilities with outstanding energy efficiency efforts should consider applying for the Smart Energy Provider designation. Applications are due April 30.