An innovative office building takes advantage of the "spark spread"—the difference between the price of natural gas and the cost of electricity.
As southern California struggled last summer with sweltering heat and staggering demand for electricity, a new cogeneration system eased the strain for the 550 North Brand Boulevard Building in downtown Glendale. By burning natural gas to generate electricity and capturing waste heat from that process to chill water for air conditioning, the cogeneration system—completed in December 2005—cut the building’s energy costs and gave it a margin of safety when grid power was strained. In case of a grid-power failure, the system can maintain the building’s essential functions and those of offices where tenants have paid to receive standby power.
The 22-story structure stands two blocks south of the Ventura Freeway (“the 134”), the main east-west artery through downtown Glendale. Built in 1987, the building has 284,000 square feet of interior space and a 289,000-square-foot parking garage. Its 30 tenants, primarily financial-services and legal firms, include Metropolitan Life Insurance Co., National TeleConsultants Inc., and the Smith Barney division of Citigroup Global Markets Inc.
The building is owned by 550 North Brand Owners Corp., which in turn is owned by a pension fund that employs Morgan Stanley Real Estate as real-estate investment advisor. SHM Partners (formerly Smith, Hricik & Munselle Management Co.) continues to manage the property, which it sold in 1990.
Weston Munselle, the SHM partner responsible for onsite management of 550 North Brand, says the cogeneration installation is part of “a demonstrable strategy of reducing consumption and reducing the unit cost of utilities. It ends up as a financial benefit to the building and to the tenants, and an environmental benefit to the world around us.”
In coastal California, a differential between the price of natural gas and the price of electricity has long existed. Natural gas is domestically produced, readily available, and often used by the power companies to produce electricity. “Our cogeneration system takes advantage of the ‘spark spread’—the differential between the price of natural gas and the cost of electricity,” Munselle says.
Surprising Agreement
Northern Power, a Waitsfield, VT-based division of Distributed Energy Systems Corp. in Wallingford, CT, designed and installed the cogeneration system. “We put in the initial interconnect application in December of 2003,” says Jan Tierson, project engineer and lead electrical engineer.
That application went to the city of Glendale’s municipal utility, Glendale Water & Power, which generates, transmits, and distributes electricity to 75,341 residential, commercial, and industrial customers. At 550 North Brand, two GWP service transformers feed the building, and one supplies almost twice as much power as the other—a situation with ominous implications.
“For cogeneration, you need to run a generator at no less than 75% of its rating for best efficiency. The disparity would lead toward unequal-sized units or decreased run time, which wouldn’t recoup as much cost,” explains Dan Lenel, lead mechanical and controls engineer for Northern Power.
“We proposed to GWP that we share power between the two services, and they agreed—surprisingly. Their attitude was that the utility was there to serve the customers. They allowed us to distribute power over a portion of their equipment within the building to balance the load, which we did through monitoring and controls, with no changes in the distribution-system hardware. Because you’re providing power to the combined service load rather than an individual service load, the number of hours you can operate a single genset is increased.”
This is the first cogeneration plant in GWP’s territory, but Lenel says utility officials “understand the environmental importance of cogeneration for reducing greenhouse gas emissions and utilizing waste heat. Most utilities lose revenue because of cogeneration, because they’re providing less electricity than before, but GWP wasn’t looking at it just from a revenue standpoint. Their willingness to let us combine the services and export power between the two services made a huge difference in the viability of the project.”
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| The generators are fueled by natural gas via underground pipes. |
Equipment and Construction
The cogeneration system includes two gensets, each rated at 375 kW, with Waukesha H24GSID engines and Stamford HCI 534C generators; a Cention AR-D240L2 absorption chiller with a 240-ton nominal capacity; and an Evapco UBT 12-612B cooling tower with a capacity of 1,350 gallons per minute.
To fuel the generators, Southern California Gas Co. supplies natural gas through underground pipes; no gas is stored onsite. Because of the extra cost of the equipment and diesel-fuel storage facilities, dual-fuel generators weren’t installed.
“It’s a question of cost benefit,” Lenel says. “How much is a customer willing to pay for what level of redundancy and backup? To have power assured 100% of the time, there’s a cost associated with that. The likelihood of an electric outage is higher than the likelihood of a gas outage. For the building owner, using this cogen system as a standby power system is a reasonable expense. During the Northeast blackout, many offices in New York City were out for longer than their uninterruptible power supplies could handle the interruption. With a standby power system such as this, their servers and data wouldn’t have been disrupted.”
Construction took about a year. The dry weight of each generator was 7,200 pounds. They arrived on skids, and an 820-square-foot room in the basement of the parking garage was built around them. The absorption chiller weighed 19,000 pounds on arrival. With its associated pumps and the cooling tower, it occupies a 310-square-foot fenced area in the garage basement.
“The installation sacrificed six parking stalls,” Munselle says.
How It Works
The generators produce 3.676 million Btu (equal to 1,077 kW) of waste heat per hour—the absorption chiller’s energy source. Like a household refrigerator, the absorption chiller operates by evaporating and condensing a refrigerant fluid under varying degrees of pressure. Unlike a typical refrigerator, however, the absorption chiller lacks a compressor; its internal pressure variations are due to temperature variations and the chemical attraction between absorbent and refrigerant compounds.
The absorbent agent in this chiller is lithium bromide, a compound with properties similar to those of common salt (sodium chloride). The refrigerant is water.
The engines’ waste heat goes from their water jackets into a high-temperature, heat-recovery water heater, a closed hot-water loop that supplies the heat to a generator vessel to boil a diluted solution of lithium bromide and water. Boiling concentrates the lithium bromide and releases water vapor, which enters a condenser.
In the condenser, a cooling-water loop from the cooling tower cools and condenses the water, which flows into an evaporator. There it vaporizes at about 42°F. due to reduced pressure and the transfer of heat from the chilled-water inlet, circulating 45°F water back to the air handlers.
Attracted by the lithium bromide, the water vapor then migrates from the evaporator into the absorber. There its condensation and absorption into the lithium bromide releases heat, which the cooling-water loop carries away.
En route back to the generator vessel to repeat the process, the diluted lithium bromide passes through a solution heat exchanger that transfers heat from the concentrated lithium bromide to the diluted solution. The solution heat exchanger helps to remove heat from the absorber and decreases the amount of heat needed to boil the diluted solution.
All of this takes place in a vacuum to make the lithium bromide and water solution more dense, so its propensity to absorb water vapor increases. In an evacuated chamber, the evaporation effect is enhanced and occurs at a lower temperature.
Ammonia is used often as an absorbent in industrial settings such as the food-processing industry, because it allows evaporation to occur at temperatures down to 0.0°F., but ammonia is a very toxic gas. Its use in a commercial application such as 550 North Brand would require compliance with stringent and costly safety requirements. The lithium bromide absorbent limits chilling of the water to 42°F. “Water freezes at 32 degrees Fahrenheit, and you need a little margin,” Lenel says. “Crystallization can be going on before the water freezes, and you don’t want any ice buildup.”
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| The generator exhaust goes through a heat-recovery system, supercritical silencers, and an exhaust line that rises up outside the building. |
System Integration
The flow rate in the chilled-water line from the absorption chiller is 651 gallons per minute. This line runs parallel to the chilled-water lines from the building’s two existing 350-ton mechanical chillers.
Integrating the absorption chiller into the existing air-conditioning system was a challenge, Lenel says. The building has a sophisticated Siemens Apogee energy-management system with Insight software that controls how many chillers are on at what rate, how much the chilled-water control valve for each air-handling unit is open, and how the chilled-water pumps operate.
“The Siemens system gives us a set point to run the chilled-water pump,” Lenel says. “We use the absorption chiller as the baseload chiller—the first one in service, if the generators are running and it’s available. Then the existing two mechanical chillers are added according to the load.”
Acoustic Design
Because 550 North Brand is in a mixed commercial-residential neighborhood, the cogeneration system had to meet stringent acoustic-design requirements. “It’s whisper-quiet,” Lenel says. “When you’re outside the building, you don’t know whether it’s running or not. You don’t hear it. Inside, you would hear it if you were in the engine room. Right next to the engine you need hearing protection. It’s over 100 dB. Outside we easily fulfill the Occupational Safety & Health Administration requirement for 65 dB in nonindustrial areas.
“We chose a premium cooling tower with very good sound reduction, and built a masonry block generator room with appropriate acoustical sound traps—baffles of a specific shape, with pinholes in them. You can look right through, but sound doesn’t make it through too well.
“We draw a lot of air through the generator room to keep the units cool. There’s an oversized fan to carry exhaust out of the engine room, but it’s operated by a variable frequency drive at about 25% of its nominal flow rate, so low that you don’t hear it, and it’s on only when the cogeneration system is operating. The building already had two big exhaust fans for the parking garage, and that’s the only noise you hear.”
The generator exhaust goes through a heat-recovery system, supercritical silencers, and an exhaust line that rises up outside the building and overhead to the atmosphere. The dampening for those silencers is such that one can hear only the sound of moving air, but not the engine’s pulsations.
An Elderly Technology
Absorption chillers aren’t new. They first appeared in the early 20th century, and they were in great demand up to the 1960s, especially in cities that had downtown steam networks. “San Francisco has a central power plant that distributes steam through the city, and people installed absorption chillers to use that steam,” Lenel says. “That was a good way to go when coal was cheap, but when energy costs started to rise, the COP [coefficient of performance—the ratio of energy consumed to the cooling effect delivered] was lousy.
“The COP of a single-stage absorption chiller is about 0.7. If you put in one million Btus of hot water, you get only 700,000 Btus of chilling capacity. A modern electrically driven mechanical chiller has a COP of between 4.5 and 7.5, and now most are at the higher end of that range, so for every kilowatt of electrical energy, you get 7 kilowatts of cooling energy.”
Lenel explains that cogeneration in the United States is a byproduct of demand for electricity. “Typically, in Europe, it’s the other way around,” he says. “You generate electricity to create load for your thermal demand, but electric tariffs here offer no incentive or ability to export power, so everything is done based on electric demand and thermal output is a byproduct—a bonus.”
Not Primary Power
The generators at 550 North Brand weren’t sized to serve as a primary power plant for the building. If that had been the intent, the system would require a third or even a fourth generator to provide a cushion for scheduled equipment maintenance and unscheduled breakdowns.
The two generators can produce a total of 750 kW, representing about two-thirds of the building’s typical load at 95% occupancy. Because the interconnection agreement with GWP prohibits the building from exporting power, the cogeneration system’s controls are set to accept at least 50 kW from GWP at all times.
“The generators were sized to limit the peak grid demand of the building to 500 kW,” Lenel says. “Guaranteeing that limit makes the building eligible for a more favorable electricity pricing pattern.”
The dispatch routine for the generators is based on time of day or load demand, or a combination of both. It’s controlled by the building’s energy-management system, based on computer programs Northern Power developed to model the savings and dispatch the generators to their best economic advantage.
The gensets automatically share lead duties, according to which one has run the most hours. If necessary, an operator can override the automatic selection. The generators typically run during weekdays when demand is at its peak, though they could run at night if sufficient load exists.
Because service technicians from Northern Power’s southern California service office participated in installation and commissioning of the cogeneration system, they already were familiar with it when they assumed responsibility for its operation and maintenance. “We’re particularly proud that we can offer a service package,” Lenel says. “Before we had a service capability, we would turn a completed installation over to a maintenance company, which sometimes would question whether the control system was working properly and should be covered as a maintenance item. With our own service arm, we’re all on the same team.”
Refining the System
Within months after the cogeneration system entered service, Northern Power began modifying it to serve as a standby power system. This entailed control modifications and installation of a standby power circuit—a separate 600-amp, 480-volt, three-phase distribution feeder—that runs to the electric rooms up to the 17th floor.
“If GWP has an outage, the generators will provide an alternate power source to customers who pay for that privilege,” Lenel says. “Tenants coming in are attracted by the possibility of standby power on the floors that have it. Utility equipment occupies much of the 18th through 21st floors, but we could have extended it a few more feet up into the building had the space or desire been available up there.”
Another possibility is using cogeneration to heat the building. At present, electrical coils in the air handlers provide heat. Those would have to be replaced with hot water coils, which would require a hot-water distribution system.
Munselle says such a distribution system already exists. “We built a spare loop in the building in case we had tenants who wanted chilled water off the plant, but that never happened. The loop is there, virgin and unused, with taps on every floor. Whatever hot water isn’t being used in the absorber can be sent up into those coils. We’ll place the coils into the hot side of the HVAC system, then run the hot water through the loop and blow the fans over the hot water.
“During the winter, I could simultaneously energize the chilled-water loop to keep computer rooms in the building cool, while the hot-water loop supplements office heating with extra heat from the hot water that otherwise would not be used.”
Implementing that concept is a year or two away, Munselle says. He estimates that it will pay for itself within five years.
At present, the generators have a gross electrical efficiency of just 32.2% based on lower heating volume (LHV), without taking the cogeneration into account. That means only 32.2% of the energy in the natural gas is being used to generate electricity.
With the absorption chiller in operation, gross overall efficiency is 68% based on LHV, which means 68% of the energy in the gas is being used as electrical power or chilling capacity. “That’s fairly low,” Lenel says. “The absorption chiller is not a very efficient machine. A lot of heat goes back to the cooling tower. If you used that wasted heat to heat the building, you would raise the cogeneration system’s gross overall efficiency into the 80% to 90% range.”