Since beginning to control customer water-heater load in 1995, the Collingwood Public Utilities Commission (CPUC), Collingwood, Ontario, Canada, has been able to save more than CDN$155,000 (US$116,513) in power costs.
In 1994, the CPUC and other municipals in north central Ontario were faced with a potential overload on their supply substation, Stayner TS, connected with Ontario Hydro. One solution was to build a new substation and upgrade the 115-kV line feeding the area to a 230-kV tower line. The projected cost was about CDN$85 million (US$63.9 million).
Looking for alternatives, CPUC decided on an effort to reduce peak load, which would allow the utility to defer new construction. Early in 1995, CPUC and its neighbor utility, Wasaga Beach Hydro, each installed a load-management system using LMS 1050 software and SA-205 VHF controlled switches provided by Scientific-Atlanta, Inc. (SA), Norcross, Georgia, U.S. CPUC then went the extra mile and established a full-fledged SCADA system that allowed it to operate the switches as part of an overall distribution automation project.
In January 1996, a SCADA system along with the SA-205 Load Management Option was delivered by Ilex Systems Inc., Milpitas, California, U.S. It was fully operational by March. With this system, the CPUC could manage not only its own load and distribution system, but could offer the same level of sophistication to nearby utilities. In a short time, four of the nearby utilities obtained load management (LM) services by connecting to the system. The direct benefits of being able to react to real-time loads rather than attempting to predict load patterns for the next five years and operate on a timer-based method made the system more financially feasible in Collingwood.
Currently, the system is controlling and monitoring the following numbers of water heaters in the territory, with the farthest utility about 70 miles (112.63 km) from Collingwood: Collingwood-1300; Port Elgin-1200; Parry Sound-100; Southampton-300; and Thornbury-200.
If any of the connected utilities wish to purchase their own SCADA system, the infrastructure is already in place, and most of the system will already be paid for through savings from the load management practices. The existing load management switches, the RTUs and the communications links can be maintained and connected to a new headend computer system should a utility wish to operate on its own.
SCADA System Has 12 RTUs The Ilex real-time SCADA system is designed for distribution and substation automation. It provides a fully integrated SCADA and load management solution in a single source. Its sophisticated load control program is designed to save money and to optimize the utility load curve. The load control software includes peak-shaving automatic voltage reduction, residential load management, capacitor VAR control and emergency load shedding with restoration.
Figure 1 shows the system configuration serving the five utilities. The SCADA/LM master includes an IBM Pentium computer, four communications channels, 21-inch (53 cm) color CRT, two printers, keyboard, mouse and diagnostic access port. The system comes preloaded with all the software and configured with all the hardware. The software includes full graphics high resolution MMI, load management software interfaced to Paradox, a relational database, individual customer programmability for load management, alarm reporting, historical archiving and more.
The communications system to the field devices is via dedicated four-wire telephone lines to each RTU and RTC (remote transmitter controller). The field devices include 12 Ilex RTUs to monitor and control the substation (Fig. 3) and five SA-RTC encoders that broadcast the individual load-management commands over a VHF radio frequency (Fig. 2).
The load-management switch, a SA-Series DCU-S2000 digital control series switch connected to each controlled water heater, incorporates SA-205 protocol. The unit's distributed intelligence enables it to go into and out of control in a smooth manner. It receives the LM radio signal from the RTC and sheds the water heater load prior to the new load peak. Each switch can independently select its own start and/or stop time after receipt of a radio control signal.
Each switch is programmed remotely using FM radio signals. The CPUC can adjust its control strategy at will without costly return visits to each switch installation. The switches are equipped with a fail-safe timer, ensuring that the switch remains in the control state only for the time instructed by the last signal. If the radio system ceases functioning, the switches ramp back out of control upon completing the last command. The SCADA software monitors the system load, forecasts the slope of the load and shaves the load to the desired load curve.
To provide the most cost-effective solution, the CPUC asked ILEX to develop a common communications path so both the RTU and the LM RTC devices could operate over a single multi-drop telephone circuit. The simple, low-cost solution saved the CPUC thousands of dollars in monthly telephone fees.
Water Heaters Electric water heaters are a natural target for load management. From a utility's perspective, the tank requires a set amount of energy to reheat the water. Instituting a load management program allows the utility to manage exactly when the tank uses that required energy. By using the SA switches on a real-time control basis, a utility can ensure that the energy use is shifted to a time when it does not contribute to peak demands. A tank that needs to run for five minutes will still operate for the required five minutes, only it will do it half an hour or an hour later depending on the utility's needs. Thus, the load can be moved off peak.
The SA-205 switch on the CPUC's water heaters also increases safety because it picks up loads after an extended outage. For example, if 1000 tanks with 3000 W elements on a given feeder contribute on average 0.5 kW each at the time of the outage (500 kW), when the power is restored, there will be a call for 3 MW of load.
The SA-205 switches have a built-in programmable cold-load pickup feature that helps prevent the instantaneous draw on the system upon power restoration. This cold-load pickup feature automatically activates after sensing loss of power for 20 seconds or more. It is remotely programmable from 0 to 59 minutes in 0.5-minute intervals. Upon power restoration, each switch immediately opens the relay for a preprogrammed period of time.
In the above example, the CPUC would have 3 MW less load to pick up at the time of closing in a breaker. The tanks would then come back on line in stages as much as 59 minutes later. In some cases, this can remove the need for sectionalizing the line prior to restoring power, and, in effect, reduce the outage length.
The Load Control Process Automatic load control for the five utilities is as follows: The computer monitors each utility's total load and records the actual load minute by minute--the peak 15-minute average and the peak 60-minute average. It monitors the current level of load as compared to the monthly 15-minute peak as a relative percentage. All of these peaks and averages are calculated every minute. The system begins to shed load in steps as demand increases. The initial values used as peaks on the first day of each month are selected month by month based on the historical data gathered from past billings.
The characteristic peak for the particular month is reviewed to establish a target for that month. In the CPUC's case, that month may have a typical peak of 43 MW. The number of switches installed equal a load-management capability of approximately 1 MW depending on the time of day. We would therefore pick 40 MW as the initial target for that month.
The water heaters are broken down into five primary groups for load management: 60-gal low consumption, 40-gal low consumption, 60-gal high consumption, 40-gal high consumption and commercial applications.
The system goes into control as the current load reaches a certain percentage of the 15-minute peak. Because we can control about 1 MW out of a possible target of 40 MW (2.5%), the system is set up to begin controlling when the 15-minute average load reaches 97.5% of the 15-minute peak. The loads are shed sequentially, and only if the load continues to grow:
-60-gal low consumption at 97.5% of peak. -40-gal low consumption commercial at 98% of peak. -60-gal high consumption at 98.5% of peak. -40-gal high consumption at 99% of peak.
All tanks are allowed to come back on after the load drops 1% below the individual group set point. The control period is set for 15 minutes and will be repeated as long as the load remains above the restore points. Conceivably, the first group may go into and out of control on a number of occasions with the last group never actually being shut down.
Since the control period is for 15 minutes minimum, the tanks are effectively removed from contributing to the peak loading on the system while at the same time ensuring that the customer is almost guaranteed not to be inconvenienced. Currently, energy shifting for off-peak savings occurs from 8 p.m.-11 p.m. All the tanks, other than those registered as 40-gal high consumption, are shed for energy shifting. The 40-gal high consumption group is left out because of the complaints received from the high number of shift workers in Collingwood. These shift workers return from work shortly after 8 p.m. and do their laundry, wash their dishes and take their showers. They are now excluded from any energy shifting.
All the tanks are also coded in one of their six programmable registers for emergency shed. Should there be a problem on a particular station, we may be able to shed enough load to allow for another station to handle the remaining load while instituting repairs. The same can be said for each feeder. Should there be a problem on a particular feeder, the coding allows us to manage all of the sheddable loads on that feeder as well as on a second feeder. Given sufficient controllable loads on the feeders, the utility can limit the effects of an outage.
The Load Monitoring Process To calculate peaks, Ontario Hydro uses pulse recorders at the billing supply points of each utility. The recorders total the pulses every 15 minutes and record the values. At the end of each month, the various metering points for each utility are contacted via cellular phone and the information is downloaded. The values are added together to calculate the total demand and highest 60-minute rolled peak. (The highest four consecutive 15-minute recordings during peak periods become the peak demand for the utility.)
Through Colling-wood's system each utility's metering point has an Ilex 8110 RTU. The RTUs are fed with duplicate KYZ (form C) pulse outputs. These pulses are converted into demand every minute and totaled for each utility.
To ensure the capture of the truest total demand, the 15-minute demand is calculated and updated every minute. The 60-minute value is also calculated using the highest 60 consecutive readings to ensure that the load is monitored and controlled as outlined in the load control process (Fig. 4).
What Power Costs Four of the utilities purchase power from Ontario Hydro at wholesale time-of-use rates and one at wholesale standard rates. All demand and energy totals are reset at the beginning of each month.
The standard wholesale rate structure includes demand at CDN$10.88/kW (US$8.18/kW) and energy at CDN$0.0437/kWh (US$0.033/kWh). Time-of-use rates vary from on-peak demand: winter-CDN$12.05/kW (US$9.06/kW) to summer- CDN$9.02/kW (US$6.78/kW).
For on-peak energy: winter-CDN$0.0609/kWh (US$0.0457/kWh) to summer-CDN$0.0504/kWh (US$0.0378/kWh). For off-peak energy: winter-CDN$0.0335/kWh (US$0.0251/kWh) to summer- CDN$0.0230/kWh (US$0.0217/kWh).
Study Determines Savings To calculate the savings that can be derived from controlling water heating loads, every effort was made to simulate both the loads and the control of these loads as accurately as possible. Twelve months of billing profiles were used. Considered in the study were the water heater load, control simulation and duration.
In the study, with the normal load profiles of the existing tanks removed from the actual peak days, and the modeled profiles added back in, a new utility load was simulated. This was then rolled, using a sliding window of four 15-minute periods to calculate demand savings (old rolled peak minus new rolled peak). A comparison of energy consumption was made between normal operation and controlled operation, and the resulting difference was then calculated to show the reduction in energy costs related to shifting consumption into the off-peak period.
A 10-year cash flow analysis was prepared based on the results of the control simulation and the required equipment. The analysis showed a total cost of CDN $262,705 or US$197,475 (based on installing 2000 load management switches). The CPUC's incentive program provides for an additional CDN$600,000 (US$451,020) in rebates to its customers in 10 years. The 10-year savings will be CDN$1,576,532 (US$1,185,079) with a CDN$713,000 (US$535,962) profit (Because the CPUC is a not-for-profit utility, the money will be used to help expand the SCADA system and general infrastructure, reducing future rate increases).
After running the program for two years, the CPUC compared the actual savings to the estimates. Estimated savings were CDN$120,527 (US$90,600) and actual savings were CDN$155,905 (US$117,193).
Customer incentives are offered through the CPUC's "Hot Water Dollars" promotion. Customers who join the load-management program receive a CDN$5/month (US$3.76/month) rebate for five years (effectively bringing the cost of electric water heating equal to or below the cost of a rental gas system). To the average family, the rebate represents about a 25% reduction in water heating costs.
The Future While the current system is working very well, the CPUC is looking at the next generation of load management equipment that would enable two-way communications to each customer, as well as provide for real-time pricing and meter-reading options.
Darius Vaiciunas is the load management coordinator with the Collingwood Public Utilities Commission, Collingwood, Ontario, Canada. He is there on a contract between Ontario Hydro and the CPUC. Previous energy management experience includes sales, marketing, building energy audits and customer education. For the past three years he has been involved with the Collingwood project where, together with the engineering/operations staff, he has helped institute the "Hot Water Dollars" load management program, the setup of the SCADA system and the affiliation with the four other utilities.