Driven by upheaval and pending changes in California’s energy markets, commercial and institutional facilities in the state rushed into onsite power generation technology from 1999 to 2001.
Facilities that have bought into this technology understandably are anxious about the higher cost and uncertain reliability of California’s electric power, but many other facilities nationwide are just as uneasy. As a result, investigating onsite-power technology has become a top priority for many organizations.
Dan Rastler, area manager for distributed generation for the Electric Power Research Institute (EPRI), reports a significant trend nationwide toward more onsite power generation. The U.S. Department of Energy forecasts that by 2010, onsite power could provide 20 percent of all new power generation.
Obstacles remain, however, to greater use of onsite power. Regulatory barriers in every state make grid-connected systems difficult to achieve, and regulations govern air emissions and fuel storage. The technology also can carry a high first cost.
But maintenance of onsite power systems isn’t a barrier, or at least it shouldn’t be. Technology and facility professionals familiar with the more popular onsite power sources say maintenance is not a significant issue, provided that maintenance and engineering managers follow regular preventive maintenance (PM) procedures.
Diesel and natural gas reciprocating engine-driven generators are the leading onsite power-generation technology. These systems can provide 30 kilowatts (kW) to more than 6 megawatts (mW). Installed costs vary from $600 - $1,200 per kW, according Distributed Generation Forum, a group of utilities, industry associations and government agencies.
The Gas Technology Institute (GTI), a natural gas research and development organization, says installed costs with heat-recovery package start as low as $425 per kW and go up to $1,200 per kW. With current technology, electrical efficiency is around 38-40 percent. Natural gas offers greater energy efficiency and lower emissions than diesel fuel.
But these efficiencies will change, says Tim Callahan, principal engineer with Southwest Research Institute, which does engineering research for engine manufacturers. Callahan says manufacturers are pushing to increase energy efficiency and lower emissions, in part because the California Energy Commission has issued a request for proposal for “ultra-low emission” and higher energy-efficiency technology.
In about five years, Callahan says manufacturers expect to bring 1-3 mW units into the 40-47 percent efficiency range, up from 38-40 percent with emissions of nitrogen oxides (NOx) by 2010 down to 0.01 grams per brake horsepower-hour. That level would be fine with California, where the current requirement is 0.15 grams per brake horsepower-hour. And by 2007, the state will require levels of 0.015.
Does higher efficiency in these power generation sets, or gensets, and more frequent use increase maintenance requirements? Probably not, Callahan says. If a maintenance department performs proper PM of backup generators, using a current or new generator more often does not equate to disproportionately more maintenance.
“Think of your car,” he says. “If you change your oil every 3,000 miles, it doesn’t matter if you’re doing it once a week or once a year — it’s the same maintenance. If you’re doing quarterly preventive maintenance on gensets, maybe you will have to do it more often.”
The average operations and maintenance cost for diesel reciprocating engine-driven generators is $0.005-$0.010 per kWh, according to the GTI. For natural gas generators, the average cost is $0.007-$0.015 per kWh.
Field applications of onsite power systems are demonstrating that maintenance costs shouldn’t be an obstacle to wider acceptance of the technology. The University of Iowa in Iowa City, for example, has incorporated its backup generators into a load-shifting and conservation program as a way to cut utility costs. Duane DeRaad, the university’s director of utilities, says starting and stopping the generator more often during peak times does mean higher labor costs from additional man-hours.
But the university receives close to $500,000 in curtailment cost savings, which will cover much of the labor cost. Aside from starting and stopping, maintenance costs haven’t increased, DeRaad says.
Reciprocating engine generation — the best known and best tested onsite power technology — dominates the marketplace today. But growing in interest, if not application, are alternative sources of power, such as microturbines and fuel cells. These technologies offer two recognized benefits — higher efficiency and lower emissions. But low maintenance is also a benefit.
Microturbines are small, natural-gas-fired jet engines that drive a near-frictionless turbine on an air bearing. They range from 30-400 kW and have an installed cost of $1,200-$1,700 per kW, says the Distribution Generation Forum.
GTI estimates that a microturbine costs $675-$1,500 per kW with a heat-recovery package. Operation and maintenance costs are $0.005-$0.010 per kWh, and their simple electric efficiency is 20-30 percent. As with reciprocating gensets, however, microturbine efficiency can be 80-85 percent if heat is captured.
The University of California in Santa Barbara has installed three 60-kW microturbines in place of a fuel cell installed five years ago to power a building and heat a pool. The fuel cell worked fine, but when it needed a major overhaul, the cell’s owner — the local utility — took it back.
George Lewis, the university’s associate director of physical facilities, says he looked at microturbines rather than fuel cells because he could afford to own microturbines. University officials also hoped a microturbine could be a simple drop-in replacement for the fuel cell, but it wasn’t.
Managers should keep in mind a number of issues when considering microturbines, says Mark Pepper, the university’s project manager. For example, microturbines require about 70 pounds of gas pressure, but most natural gas comes at 5-6 pounds. So each microturbine requires a compressor, as well as larger gas piping.
Also, Pepper says that while the fuel cell used a 1 1/2-inch water line to carry hot water to the pool, the microturbine required 2 1/2 inch piping because the required heat exchanger pump was rated at 80 gallons per minute. Also, the microturbines required mufflers because they were placed under bleachers near the pool.
While the system presents installation challenges, maintenance is minimal.
“There’s a filter, like a HEPA filter, that has to be changed, and after four to five years of run time, the turbine will have to be rebuilt,” says Jim Dewey, the university’s energy manager. “Other than that, there is the normal electrical equipment and the normal plumbing maintenance concerns.”
The project cost about $325,000, but the university received a $60,000 tax credit from the state.
Microturbines “really work for us also because our electric costs have gone from about 5 to 10 cents a kilowatt-hour, and during the summer, the rates can go relatively high — even up to 18 cents a kilowatt-hour,” Pepper says. “Even if we threw away the heat at those costs, they would still make sense.”
The four most common types of fuel cells are proton exchange membrane (PEM), phosphoric acid, molten carbonate and solid oxide. Stationary fuel-cell sizes vary from a few kW to 3,000 kW, electric efficiencies range from 36-50 percent, and overall efficiencies are similar to microturbines, about 80-85 percent.
Fuel cells’ installed cost is the highest of all onsite sources, roughly $3,000-4,000 per kW, says the Distributed Generation Forum. Other industry sources put the costs closer to $2,300 -$2,800. Fuel cells also emit the lowest amount of NOx and CO2 of all onsite power sources, and operation and maintenance costs are $0.005-$0.010 per kWh.
Because fuel cells use only hydrogen and because an infrastructure to supply hydrogen doesn’t exist, most cells today run off of natural gas or methane. In either case, the fuel must be broken down to release the hydrogen, a process that requires a reformer.
In terms of fuel-cell maintenance, individual stacks must be replaced after 4,000 hours, says Mark Williams, fuel product managers for the National Energy Technology Laboratory with the U.S. Department of Energy. Other than that, there is little maintenance.
In terms of other maintenance, a catalyst in the reformer must be replaced every 5,000 hours, Williams says. The entire system requires the usual maintenance on pumps and valves. Also, minerals must be removed from water used in the reforming process, an important issue for all types of fuel cells but an especially big issue for phosphoric acid fuel cells, Williams says.
The Liverpool (N.Y.) School District recently installed a 200-kW phosphoric acid fuel cell, which fits into the district’s performance contract, says Joe Camerino, the district’s assistant superintendent of schools.
“It was cost-effective because we just didn’t need the power,” Camerino says. “We needed the heat for the pool and domestic hot-water systems.” The fuel cell cost $1.8-1.9 million but the cost is partially offset by a half million dollars in grants.
The district also has to perform maintenance on steam valves, and a couple of pumps had to be rebuilt, says Paul Davis, the district’s energy manager.
The district’s PM includes cleaning the condenser, draining and cleaning the water storage tank, and providing corrosion protection to the system, says Carl Barber and Ed Strodel, lead maintenance technicians on the project. They also have had to tweak some aspects, such as change out galvanized ductwork for stainless steel. And since the fuel cell’s installation, Barber says, the district has not had to fire up its boiler.
