2 3 4

(Hours/yrxlO3)

Fig. 23-12 Annual Steam Duration and Cogeneration System Fit. Source: United Technologies Turbo Power Division during peak-setting time, shifting entire operations to off-peak periods, the use of gas- or steam-driven cooling, thermal storage during off-peak periods, or battery electric storage.

On-site electric generation is another potentially cost-effective solution. This may be applied independently or in conjunction with other load shedding applications. Figure 23-14 shows an example of a peak-shaving generation load profile. In this case, electric power production represents a very small part of the facility's usage requirements, but about 40% of its billable peak demand.

Typically, with peak-shaving generation systems, low first-cost is emphasized more than thermal fuel efficiency. In most cases, heat recovery is impractical due to insufficient thermal load or because of limited hours of operation. In some cases, however, a minimal amount of heat recovery is driven by the need to satisfy QF requirements, thereby ensuring that the local electric utility must continue to provide non-discriminatory services.

In some cases, facilities may also be able to use the peak-shaving generation equipment as a backup power source for critical electric equipment. Figure 23-15 shows two skid-mounted 12-cylinder dual-fuel reciprocating engine-generator sets used to peak shave and provide emergency stand-by power for a hospital.

Many on-site power generation systems include, in addition to baseloaded electric cogeneration systems, low capital cost electric generator sets that do not use heat recovery and are not designed for continuous operation. These units may be used as backup capacity to the primary electric cogeneration systems and may also, in some cases, be used for electric peak-shaving.

Annual Load Duration & Cogen Plant Fit

Load Duration Curve gg Buy Pcrwsr

20 FTB Output '

Fig. 23-13 Annual Electric Load Duration and Cogeneration System Fit. Source: United Technologies Turbo Power Division

Fig. 23-14 Electric Peak-Shaving Generation Profile.

Standby Generator Applications

Many electric utilities have peak-shaving, or interruptible service, programs in which facilities are encouraged to install standby generators. This is usually done with an installation incentive or a flat annual fee based on capacity. Customers may generate power during utility-designated periods, or use other methods to reduce their own power requirements. Many utility programs have different levels of payment or compensation based on availability.

Fig. 23-15 Two Skidded Dual-Fuel Reciprocating Engine Generator Sets used to Peak Shave and Provide Emergency Stand-by Power for a Hospital. Source: Fairbanks Morse Engine Division

Utility-controlled peak-shaving can allow utilities to improve load factor and reduce capacity requirements with minimal loss of sales volumes. They also sometimes serve as competitive alternatives to strategies designed by customers to reduce peak demand charges at their own facilities. Commonly, utility peak-shaving programs result in far fewer generator run-hours than in-house peak-shaving programs, meaning there is less loss of sales. In some cases, these utility controlled peak-shaving programs are packaged with other competitive energy rate offerings to provide sufficient incentive for a facility to forego an alternative, more extensive on-site self-generation option.

Where permitting regulations allow and expected run time is very low, emergency generators may be used in utility peak-shaving programs. Generator sets rated for emergency duty are less expensive than prime power units and they may either already exist on-site or be required anyway. However, in many states, on-site generation equipment may only be exempt from air emissions control regulations as long as the sole purpose, without exception, is emergency service.

An emerging application of standby generation systems is to support interruptible power service purchased on the retail wheeling market. A facility with dispatchable on-site generation capacity can lessen or eliminate the need to pay for firm purchased power capacity. This enables the facility to purchase low-cost commodity power, and, during periods when capacity is not available or when costs are high, the on-site system can be used. In the evolving deregulated power market, access to dispatchable electric generation capacity is becoming an increasingly valuable asset.

Interconnecting Peak-Shaving Generators

Often, when a facility decides to install standby generation capacity, it also considers expanding the project scope to include peak-shaving generation. Added capital cost may be incurred in selecting a more durable or fuel-efficient system when both interconnected operation and isolated standby duty are required.

Standby generating systems commonly operate at 480 volts and are coupled to critical loads via a transfer switch that locks out the utility feeder. This causes an interruption of power to the critical loads, since one power source must be dropped out before the other is picked up. In cases where interruption cannot be tolerated, facilities may have multiple feeders from the utility network. In the event of a complete utility blackout, the feeders usually do not go down at exactly the same time, allowing an interconnected standby generator to be used. In these cases, where required interconnection is in place, the system can also be used for demand limiting purposes. To ensure required standby availability, the additional duty may warrant consideration of a higher quality, more durable engine-generator system.

If the generator cannot support the entire facility load, an operational strategy must be in place to allow the facility to restart or continue operation after the main breaker has opened. A typical sequence is to open the generator circuit breaker, shed non-essential loads, and then reconnect critical loads back to the generator. With the use of high-speed relays and a suitable plan, this process may be accomplished without interrupting generator output. Alternatively the generator circuit breaker can be tied directly into the feeder that supplies power for critical loads. The utility tie-breaker then will function as the feeder circuit breaker for non-critical loads.

Peak Shaving/Load Shaping Case Study

In 2000, a military facility in Georgia was on an electric rate with Georgia Power (GP), under which the electricity costs were calculated from demand and energy charges that are determined by a customer base load (CBL). The CBL is an hour-by-hour demand load profile at the facility's substation, metered at half-hour intervals. The facility's CBL was originally established by contract from the 1994 demand profile and adjusted once for a lighting efficiency upgrade project. The full value of the CBL is charged at a conventional TOU rate, regardless of actual usage. All energy consumed above the CBL is billed under an RTP rate. If demand falls below the CBL, the bill is credited at the RTP rate for that time interval. The RTP, a function of GP's generation and power purchase contracts, is calculated continually and announced an "hour ahead" of taking effect.

Since converting to the CBL-based rate in 1994, peak summer demand at the facility has declined from 27.5 to 24.9 MW, while the average peak winter (non-cooling) demand has remained relatively constant. Since, most of the time, RTP rates are less than half the TOU rate, there is substantial benefit from reducing the CBL and thereby shifting kWh from TOU to RTP.

The facility leases nine 1.5 MW packaged 700 rpm EMD Diesel engine generator sets built and previously used by the military during the 1960s. Three units are wired to one control trailer to form an independently operating 4.5 MW plant. The plant capacity is presently three of those sets, for a total of 13.5 MW. The facility pays a fixed annual lease cost plus a variable cost per engine operating hour that includes accrual for major overhaul at 16,000 hours. While these engine generator sets are thermally inefficient by today's standards and also have fairly high regulated air pollutant emissions levels, they are renowned for their reliability, a critical element for the facility.

The generators have historically run 200 to 300 hours per year, all on summer afternoons and evenings. Most of the revenue from this operation came from complying with interruptible service (IS) dispatch requirements from GP, while most of the operating hours occurred during peak shaving when RTP costs were high. The IS rate rider requires the facility to reduce demand to their IS threshold within 30 minutes of notice from GP. The levels and the potential for credit are agreed upon in advance under a 3-year contract with GP. The IS load is defined as the difference between the maximum CBL demand during the IS peak period and the kW amount of the contracted IS threshold. Up until 2001, the IS threshold was set at 12.5 MW with the IS peak established at 23.8 MW. Credit is reduced if the CBL load profile does not exceed the required 600 hours use of demand (or HUD, defined as the total monthly kWh divided by the peak demand) in the contracted CBL profile. When the HUD is below 600 hours, the incremental IS credit is reduced by a load factor. Additionally, excessive failure to respond to curtailments within the allotted dispatch time may forfeit the credit for the year. In addition to IS-related savings, the units have been operated whenever the RTP rose above $0.08/kWh. This is the approximate threshold at which the operating costs, inclusive of O&M accruals, are lower than the RTP market price for generating power.

Peak Shaving/Load Shaping Strategy

During 2000, the facility contracted with an energy services company (ESCo), to implement a peak shaving/ load shaping program under a master Energy Savings Performance Contract (ESPC). An objective of this program was to ensure reliable long-term operation of these engine-generators as emergency backup units for the facility's critical loads. Hence, the key was to utilize savings generated by a more aggressive operating strategy to fund overhauls of the engines, switchgear, and other related auxiliary equipment and provide a more rigorous ongoing preventative maintenance program. An additional objective was to generate excess savings that could be used to leverage upgrade of other energy infrastructure equipment at the facility. Under the contract, the ESCo would implement and maintain all the measures at their own expense and be compensated by the facility out of a portion of the annual savings generated. In this manner, the facility could accomplish its mission objectives with no upfront capital investment.

The primary basis of savings for this strategy was to take advantage of the RTP component of the facility's utility bill. Under the applicable GP rate guideline, for a facility to have an RTP component, a CBL must be established. While the existing CBL provided some RTP operating benefits, a lower CBL would provide additional opportunities to generate further RTP savings. Hence, this load shaping program targeted an additional adjustment to the CBL. This required a new contract rate with GP and one year of operation to establish a new CBL. After implementation of the new rate, one year of proven operation of several load management strategies was required to reduce the peak electrical demand for calendar year 2001.

After detailed analysis of all electric rate options and load shape strategies, it was determined that it would be most advantageous to lower the CBL during the more expensive peak period, 2:00 p.m. to 7:00 p.m. summer weekdays. In addition to meeting the peak period requirements, operation would be required for all GP peak hours, 7:00 a.m. to 10:00 p.m. weekdays. Per GP's guidelines, this could be accomplished by going off of the RTP-type rate during 2001. This would remove the CBL and the facility would be charged only at the traditional TOU rate. After 2001, the facility could return to service under the RTP rate with a newly established CBL based on the 2001 actual load. If the actual load in 2001 could be driven down by on-site electric generation and other load management systems during peak periods, then the CBL could be set at these lower load levels for 2002 and beyond. This strategy would create significant recurring annual savings. It was also determined that additional savings could be achieved each year by setting more aggressive targets for the IS program and through more aggressive electric generation during RTP periods when the price was above the break-even threshold.

Three basic load management strategies were developed to achieve program objectives.

1. Run the generators and manage load aggressively during high priced summer peak hours in 2001 on the new rate tariff. This would shift kWh from the CBL price to the RTP during the critical afternoon hours in 2002 and beyond when the facility switches back to the original rate. The 2001 load, which was driven down by management of the generator plants and other load control systems (involving duty cycling of air conditioning systems and interruption of other non-critical systems) will become the new CBL beginning in 2002. Dramatic savings are achievable in that removing peak kWh from the CBL drops the average price from $0.25 to under $0.06 per kWh during selected periods.

2. Once the new CBL is set and the facility is back on the original rate tariff in 2002, the generators and chilled water storage will be tactically dispatched to displace or shift load when the RTP is higher than the break-even threshold, which will vary depending on fuel cost. As the price of fuel drops, the generators can be run cost-effectively at lower RTP prices and vice versa.

3. Establish more aggressive IS targets. By lowering the target from 12.5 to 10.0 MW or even less, more IS capacity credits would be achieved, producing greater annual savings. Also, by reshaping the load profile, the HUD-related credit reduction would be greatly reduced or eliminated.

This strategy carried considerable risk in that once the new CBL was established, it would remain in place indefinitely. One significant outage of peak shaving capacity during a 30 minute period could result in setting a higher than planned CBL. This would result in a shortfall of the expected cost savings, which were to be used to pay for the system overhauls and other energy infrastructure improvements. Additionally, more risk was assumed by targeting the lower IS threshold since penalties for missing the target are more severe than the benefits of hitting it. To mitigate these risks, major system overhauls were designed to ensure generation system reliability. Detailed automated operating protocols were established for monitoring, control, and dispatch of the generation system and all other load shedding systems. In addition to the system automation, well-trained, highly focused system operators were required to ensure smooth, reliable operation and respond quickly to any system failure or emergency conditions.

Another challenge was to work within the facility's air permit limits, while substantially increasing generator operation during 2001. The facility is located in an EPA Attainment Area. It emits about 100 tons (91 tonnes) per year of a potential 417 tons (378 tonnes) per year of regulated pollutants. The Georgia State Air Quality Division allows for the operation of the Diesel engine-generators for 500 hours per year under the Title V Major Source Operating Permit. To ensure that the generators could run enough to meet load management goals, the facility filed for an air quality construction permit on the innovative basis of kWh generated (in lieu of the normal potential-to-emit basis). Permitted output was designed to avoid triggering Prevention of Significant Deterioration (PSD) status that would have delayed the project for months. While this provided more headroom for emissions in 2001, it would require careful management of the generator output so that the target load profile shape would be achieved without hitting the strictly enforced emissions cap allowed under the permit.

System Upgrades

Prior to commencing operation for testing and fine-tuning in May 2001 and active operation in June 2001, the ESCo established a system upgrade scope of work to improve reliability. The following improvements were made prior to the critical summer operating period:

• Overhauled and upgraded the 13.5 MW Diesel engine-generation plant.

• Installed 30,000 gallons (113,500 liters) of additional fuel storage and redundant fuel pumping capability.

• Installed backup transformers and a 1.8 MW standby generator at the facility Hospital and added a communication system to the central operating station (the Hospital on-site electric generator was also included in this load shedding strategy, so a temporary backup generator was installed to increase reliability).

• Expanded the load shedding control system to include 2.5 MW of routine load shedding circuits and several additional MW of potential load shed circuits to be used only in the event of short-term emergency outage of a significant portion of the engine-generator capacity.

• Upgraded the software, hardware, and communications of the enormous central energy management system (UMCS).

• Developed and implemented an automated operational protocol and manual backup protocol and conducted extensive training of all operators.

Results

On January 1, 2001, the facility changed to the TOU rate as a new two-meter load group consisting of the electric meter at the Hospital (located at and paid for by the facility) and the facility's main electric meter. This combined load group was then aggressively managed to shape a favorable purchased power load profile. On January 1, 2002, the facility will return to the RTP rate with the actual 2001 load profile as the new CBL.

Figure 23-16 documents the power usage for one day at the facility. It shows the hourly kW of actual demand, old and new CBL, and the on-site generation system output. Notice that the shape and area of the generation output closely matches the difference between the actual demand and the new CBL curves. Using this same basic daily load shape strategy of producing up to 8 MW on-site, 3 to 4 MW was shifted from TOU to RTP permanently. Since the old CBL was lower than the actual demand (this had been previously negotiated), new additional cost savings are only achieved based on the reduction from the old to the new CBL. Yet, the peak shaving profile, which is the effective combined impact of the on-site generation and any other load shedding, had to work against the actual higher demand level producing up to 8 MW in order to achieve the 3 to 4 MW reduction objective.

Through careful focus on the objective, the program exceeded the original target load management goal by 700 kW. This was accomplished by keeping the local electric generation and load shedding systems in operation or fully available every minute on weekdays from 7:00 a.m. to 10:00 p.m., June through September 2001. Through extensive monitoring and forward modeling of operations, the air permit limitations were managed to ensure that the engines could continue to operate as needed throughout the summer. Actual kWh generated this summer came within 2% of the permit limit.

The ESCo will now continue to operate and maintain the Diesel engine plant, a new chilled water storage system, load shedding control, and the UMCS system on a year-round basis for the duration of a 20 year contract. Long-term annual net savings from this measure will be in excess of $800,000, net of all OM&R costs. This will be sufficient to pay for all of the system upgrade work performed in 2001, as well as some additional energy infrastructure improvements desired by the facility. While there remains some ongoing risk and uncertainty about the exact long-term savings in each year due to RTP and IS operation, the vast majority of savings have been assured with the achievement of the new CBL.

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