CHP in distributed generation applications can add efficiencies to electrical systems.
Roman sawmills dating to the 3rd–6th century AD have been discovered with what might be described as the first, albeit very rudimentary, model for a reciprocating engine. A crank-connecting rod mechanism converted the rotary motion of the waterwheel into the linear movement of the saw blades, according to three authors writing in the Journal of Roman Archaeology, in 2007.
Today, reciprocating internal combustion engines are the heart of generator sets found worldwide in combined heat and power (CHP), or cogeneration, systems, in standby generators and in peaking units. These engines can be run on natural gas or diesel oil in industry, educational institutions, government offices, prisons, and methane or biogas in landfills or farms. The type of fuel always depends on the application.
For example, gas-fired generator sets are the logical choice for CHP applications as company executives discuss below. Diesel-fueled generator sets are often the preferred option for standby units because of their ability to start up quickly. It is critical to keep in mind that, when designing a cogeneration system, the amount of electricity generated should be matched to the thermal load of the building or application if the system is to be economically viable.
Europe has been ahead of North America in CHP products because of differences in regulatory policies. Tariff rates are lower in North America and governments support smaller projects in Europe. Furthermore, farmers in Europe are far more likely to generate power from waste, and biofuel projects are only now catching on with US farmers. This can explain why two of the companies or their products discussed below had a long history in Europe before migrating to North America.
While reciprocating generator sets have long been a staple as standby units and some utilities have installed them to supply power during peak periods, CHP projects have faded in popularity in the past 10 to 15 years in the US, due to a lack of incentives for utilities to buy excess power. Without excess power sales, CHP projects are often not economically viable.
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Photo: MTU Onsite Energy
MTU Onsite Energy is seeing increased activity with sales of its generator sets in the Midwest, Midsouth, as well as the mid-eastern corridors from the Carolinas to Washington DC. |
However, the Obama administration and many states are now taking measure of the efficiencies CHP in distributed generation applications can add to electrical systems. The US Department of Energy has allocated $156 million in federal stimulus funding for CHP, district energy, and waste energy recovery deployment and demonstration projects.
CHP for Baseload Power
“Going forward, we’re seeing traditional cogeneration and trigeneration business increasing,” says Roger George, general manager for GE’s Jenbacher gas engine business for North America. The market has been volatile, but looking to the future, the need for efficiency and reductions in carbon footprints will improve the market, he says. While there has been a great deal of interest in renewables, “people will be forced to look at natural gas” for efficiency’s sake and cogeneration is the way to do it, adds George.
By 2000, there was almost 20 GW of larger industrial cogeneration in the US. Today, the new markets are with the smaller units, of the 5-, 10-, or 15-MW size in the commercial, industrial, and hospital arenas where electrical prices are high and customers are looking for green solutions to reduce their carbon footprints, George argues. George acknowledges the barriers, but regulators and industry have to see the need for cogeneration. “In Europe, CHP was the first thing they went after, before biogas and renewables,” he says.
Jenbacher reciprocating engines are designed primarily for natural gas, although some are designed for biogas applications. Models start at 300 kW, and the newest model is sized at 4 MW with pure electrical efficiency over 45%. In a cogeneration application it is over 80% efficient, depending on thermal requirements. With trigeneration, in which exhaust heat is used for chilling, efficiency drops slightly to the 70% range.
George says the company has sold units for some selective standby applications, but Jenbacher engines are designed for base load applications. Peaking cogeneration units “are very much in play here” he says, since the engines are designed for varying loads and the response times are very good. “As long as the application is economically justified, we do it all the time.”
Austria-based Jenbacher has been in business for over 45 years. GE bought the company in the early part of this decade. GE Energy Jenbacher now has over 400 units installed in the US, predominantly in industrial applications. About 40% are landfill gas–to-energy projects, and some biogas animal waste projects.
In 1994, Wellesley College in Massachusetts installed four gas-fired 1.4-MW Jenbacher generating sets. A fifth, 1.9-MW unit was added in 1998. Each is equipped with heat recovery to produce steam, medium-temperature hot water, and chilled water. The system provides 97% of the campus’s power, and saved the college over $10 million in energy costs in the intervening years. First-year net savings alone were $936,826. The simple payback was six years. The college has withstood several attempts by the local utility to shut the cogeneration plant down.
The college also considered backpressure steam turbines and gas turbines, and eliminated them because of low steam and electric output during summer months and low part load efficiencies. For the gas turbine, a single engine reduced system reliability.
On July 1, six Jenbacher landfill gas generator sets began operating the 11.5-MW biogas plant at the Ox Mountain landfill in Half Moon Bay, CA. Ameresco Inc. developed and built the plant, owned and operated by Republic Services. The generated power is being sold to the cities of Palo Alto and Alameda, CA.
GE developed a pre-combustion temperature swing absorber to clean up methane, and it is installed on the generator sets at Ox Mountain landfill. George explains that this new technology cleans up siloxanes, an element in landfill gas that deposits silicon in the engine and eats up catalysts used to capture emissions. Siloxanes are becoming more visible in landfill gas because it is attributed to detergents that end up in landfills. The absorber is still in its testing phase, and this is its first application in California. With the addition of a selective catalytic reduction unit and catalyst, methane is scrubbed clean.
Peaking and Standby Markets Stable
The market for CHP projects has been in a state of flux for the past 18 to 24 months, says Peter Schroeck, manager for North American Business Development at Cummins Energy Solutions. He attributes this flux to the volatility in the gas commodity trading markets as well as changes in the regulatory environment. Gas prices spiked at $14 per mmbtu seven months ago and recently returned to $4 at the Henry Hub, a major natural gas delivery point. Adding in delivery charges, users can now buy gas at $7–$10 per mmbtu.
“When you have this kind of volatility, it’s hard to predict savings,” says Schroeck. Adding to the uncertainty of the economics of cogeneration are potential cap-and-trade regulations and/or carbon offsets, which are metric components included within the makeup of the economic pro forma model.
In contrast, the market for peaking and standby applications utilizing gas-fired reciprocating engines is very active, says Schroeck. In the peaking market, there is a convergence of factors, driven by the regulatory environment. For example, with the popularity of renewable portfolio standards pushing utilities to buy or contract for intermittent renewables, such as wind and solar, gas-fired generator sets are being considered as deployable peaking solutions. As a wind or solar resource cuts out, the peakers can fire up quickly. “We fill a good niche at up to 100 megawatts,” says Schroeck.
The Long Island Power Authority [LIPA] has leased 48, 2-MW generator sets that produce a total of 96 MW at two locations. For that amount of generation, why not turbines? Schroeck says that reciprocating engines and turbines each fit a particular application. Capital costs are far less and the cost of fuel for reciprocating engines is half that of turbines. Below 5 MW, reciprocating engines will have much higher electrical efficiencies, he explains. Until you reach larger turbine frame sizes, even the 25-MW single-turbine unit won’t be as efficient or cost effective on the capital side, he argues.
Turbines are rated to ISO conditions at 59˚F and will “roll off” in performance for every degree above that. Reciprocating engines are immune to dropping off in performance under high ambient temperatures until they rise above 120˚F. A turbine designed to produce 25 MW will generate 17 MW on a hot day.
Putting power where you need it is also a key attribute of reciprocating engines, argues Schroeck, whether spreading the generator sets across 10 substations or at a central delivery point within the electric grid. The scalable feature of utility peaking power modules means that you can position them where you need them.
There is a tremendous uptick in interest for high power density gas engines for standby applications, says Schroeck, in particular the coastal areas in the southern states where Hurricane Katrina ravaged the population centers. The interest is driven by environmental issues, since no onsite fuel storage is required. In addition, natural gas generator sets are designed to run for extended periods without the need for maintenance that make them ideal for situations where you can’t shut the generator down to service it. A lean-burn gas generator set can operate for months without the need to perform any maintenance. This includes oil and spark plug changes. Popular applications are at wastewater treatment facilities, hospitals, and prisons.
In a correctional facility currently being designed, standby units will provide power for an outage lasting up to two hours, Schroeck says. If the outage lasts more than four hours, the alternative is to move prisoners. Another more cost-effective solution might be a CHP plant that could also serve as a standby unit, he explains. Furthermore, it could step in as a peaker, if market conditions exist.
There are considerations when thinking about generator sets serving in dual roles, Schroeck says. Diesel fuel would be necessary if the standby unit is legally required for life safety. Only diesel generators will meet the requirements to meet the life safety requirements of the National Fire Protection Association. However, diesel-fired units could not be converted from a standby to a cogeneration unit, but a gas-fired reciprocating engine could be. Furthermore, fuel costs for a natural gas–fired unit are currently one-third the cost of diesel oil.
CHP Power Sales Add Profit
William Floyd School District, located on the south shore of Long Island in Shirley, NY, installed a 2.5-MW CHP plant in the summer of 2002 to provide power, heating, and cooling to three schools located next to each other. The elementary, middle, and high school buildings require about 2 MW of power during the day, space heating during the winter, and air conditioning during the summer. In its first year of operation, the CHP system saved the school district more than $1.2 million.
Two gas-fired 1.25-MW Cummins PowerCommand lean-burn reciprocating engine generators drive the CHP system that is operated from 10 a.m. to 10 p.m., daily. This schedule responds to LIPA’s peak usage periods. In the winter months, the waste heat is used to supplement the hydronic heating system for the 220,000–square foot middle school.
“This allows us to shut down the large oil-fired boilers that had provided heat to that building,” says Herb Hodge, plant facilities administrator for the school district.
In the summer months, the system provides all of the power for the three schools on the campus when school is in session, and the waste heat is used to supply a high percentage of the air-conditioning load. The CHP system produces about 500 tons of chilled water per day to power a 200-ton absorption chiller system in the high school building. A Cummins 1.25-MW diesel standby generator adds excess capacity in case of an emergency. Two operators operate and maintain the plant.
The $5-million cost of the plant was absorbed by a $50-million capital improvement project, of which 85% came from New York State. The local share of the CHP project was paid back in 18 months, says Hodge.
The CHP system has allowed the school district to avoid demand charges for the five years it has been operating, saving $40,000 a month. Should the system go down, the school district has a 10-minute window in which to bring the standby generator online to avoid a demand charge.
Hodge says he needs other markets in which the CHP system can participate and bring in resources. “If I generated electricity only, it wouldn’t be profitable,” he says.
So from mid-July through August, the CHP system provides power to the New York Independent System Operator’s (NYISO) 24-hour capacity market when called 24 hours in advance. The school district can usually sell back as much as 500 kW.
The school district’s energy management system is programmed to systematically shut down pieces of equipment to reduce demand at the agreed-upon time depending on the amount of power requested. Much of the air conditioning can be shut off, replaced by fresh air to ventilate rooms. Finally, lights can be shut off periodically, even if summer school is in session, since these classes let out between 11:30 a.m. and noon.
Hodge says they can also pre-chill buildings in the mornings to 68˚F, about four hours before they get a capacity call from NYISO. The chiller can then be shut down, and air handlers move fresh air.
The school district gets monthly checks from NYISO and has earned a total of $483,000 from its participation in the capacity market. Hodge added that LIPA’s payments for regular excess energy exports are minimal. LIPA is working with the school district on a new program in which the CHP system would act as a voltage regulator, helping the utility to level out its peaks. It would require a 1.25-MW CHP generator to be turned off with a five-minute warning. Details are still being worked out and there is no start date, Hodge says.
Gensets Provide Options
Patrick Barrett, manager of distributed generation at Caterpillar, agrees that the market for CHP is growing. The company is seeing increased interest with potential customers such as universities, hospitals, biopharma companies, and wastewater treatment facilities. Contributing to this growth is the availability of federal stimulus package money and state programs providing funding being offered, for example, by New Jersey with its Master Energy Plan, Texas, Connecticut, and Massachusetts. They all provide rebates based on kilowatts installed.
For example, the New Jersey program awards $450 per kilowatt to projects based on certain total plant efficiencies. It sets that amount aside in an escrow account and the funds are then released as power is delivered. This ensures that the CHP plant will continue to operate.
Caterpillar is enjoying a large market share in the data center industry for standby capacity, says Barrett. Data centers have always been concerned first about redundancy in power supplies, and the value of rental space is based on the level of redundancy customers need to meet their computing needs. Now the data center marketplace is reviewing CHP applications to improve operational efficiencies and cost reductions.
Onsite power provides advantages to private companies by allowing them to make decisions to buy utility power or run their CHP or standby unit, Barrett says, and it depends on the markets. For example, an industrial company may decide to purchase a portion of its electrical demand on an interruptible basis at a reduced rate, and to match that demand amount with installed capacity. When the utility calls to notify the plant of a power interruption, the plant manager must make a choice between running their installed assets or paying the higher price of the utility’s tariff for power.
The Fairbanks Memorial Hospital and Denali Center in Fairbanks, AK, while it chose a diesel-fired standby system for its internal use, will be able to consider selling peaking power to its local utility. The 152-bed hospital embarked on a $120-million program in 2004 to build a new outpatient-imaging center, expand its emergency room, and improve other infrastructure. It also increased its standby electrical power to 4.25 MW when it expanded and upgraded the hospital’s electrical and trash systems.
Two Cat 3512 diesel-fueled generator sets, each rated at 1.5 MW were fully integrated with the existing standby generator set and commissioned in June 2007.
Although the standby system is configured to operate in parallel with the local electric utility, Golden Valley Electric Association, and could export power to the grid, the hospital is not using that capability at present.
The hospital has two utility feeders, each serving about half the facilities. The generator sets are kept online in an auto mode. If the hospital loses a utility feed, a signal is sent to the generators that start within nine seconds. The generators synchronize and begin delivering power to critical loads, including surgery suites, life safety systems, boilers, and essential lighting. Engineering staff then must decide whether to switch the entire hospital over to the remaining utility feed or use the standby generators to restore the facility to full power. When the utility feeder is restored, the generators seamlessly shift the hospital back to utility power.
In the future, the system’s ability to parallel with the utility could enable Fairbanks Memorial to receive special rate incentives in return for running the generator sets during winter peak-demand periods on the Golden Valley Electric grid.
Diesel Gensets Work for Standby Power
MTU Onsite Energy is seeing increased activity with sales of its generator sets in the Midwest, Midsouth, as well as the mid-eastern corridors from the Carolinas to Washington DC, according to David Pitzer, senior sales manager at MTU Onsite Energy, formerly Katolight Corporation, a 50-year-old company based in Mankato, MN. MTU Onsite Energy is part of Germany-based Tognum Group’s business unit, Onsite Energy and Components.
Pitzer’s primary focus is on stationary standby projects that back up utility power. MTU Onsite Energy’s diesel-powered generator sets range in nameplate ratings from 30 kW to 3,250 kW. Its natural gas–powered generator sets range from 25 kW to 125 kW for standby and prime power.
MTU Onsite Energy does have over 5,000 CHP installations globally. Its primary market for CHP is in Europe, but this market is migrating into North America, Pitzer says. The company has also seen numerous peaking application opportunities with utilities and cooperatives recently.
Funding for projects has been the main barrier since late last year, when financing opportunities dried up following the 2008 banking crisis and the withdrawal of lending by commercial institutions. Pitzer has not yet seen wide use of federal stimulus package funding by government and local institutions that might use this funding to replace equipment.
MTU Onsite Energy manufactures and sells both diesel- and natural gas–fired generator sets that incorporate engines manufactured by MTU, John Deere, and GM. Diesel engines are able to come online quickly and respond to quick changes in loads in emergency standby situations, Pitzer says. On the East Coast, diesel fuel prices range between $2 and $4.50 per gallon, and have not impacted emergency standby applications, he says.
Pitzer says MTU engines are commonly permitted in EPA non-attainment areas, using after treatment catalyst reduction devices to reduce NOx emissions up to 90% when required.
The Hoosier Park Racing and Casino located in Anderson, IN, about 20 miles northeast of Indianapolis, IN, has been in business for more than 15 years. Located at the end of a single power line, the track often experienced electrical power brownouts and blackouts caused by summer storms in central Indiana and a growing demand for power in the area.
When the owners decided to build the 90,000-square-foot casino, they included in their plan a standby power system that would keep the lights on, the horses running, and the electronic gaming machines operating. When Hoosier Park was just a racetrack, racing customers would tolerate outages lasting an hour or two, but interrupting gaming was taboo for business.
The engineering design company, Meridian Engineering, designed a standby system utilizing two sound-attenuated 1,000-kW MTU Onsite Energy diesel generator sets that have been operating since June 2008. The 2,000 kW of generating capacity can accommodate 100% of the casino’s energy needs, including 2,000 electronic slot machines, new electronic poker tables, lighting emergency systems, food service, and refrigeration. The security system, the slots control system, and the surveillance cameras are also backed up. Furthermore, Hoosier Park arranged for the local utility to bring in a second feeder line to the facility from a separate substation. And, it also made room for two more generator sets in the future if the facility expands.
The HVAC system is designed to work in conjunction with the generator sets and the energy management system that controls the HVAC. The chiller load can be reduced by 50%, if needed, while the facility is running on the generator set but only if outside temperatures were under the temperatures stipulated as the design maximum. Up to a certain cooling level, 100% comfort is maintained while the facility is on standby power.
MTU engines are designed for very low emissions and produce 5.5 grams per horsepower-hour of carbon monoxide and 0.131 grams per horsepower-hour of particulate matter. They are certificated to EPA Tier 2 standards.
The power system also has critical-grade exhaust silencers and sound-attenuated steel enclosures to avoid spooking the 300 to 350 horses, some representing very large investments, in the nearby stables whenever the system runs. The enclosures limit the sound from the generators to 75 dB(A) at full load measured at 23 feet.
The regular exercise and maintenance schedule includes operating the generator sets once a week for about 30 minutes to get them up to operating temperature. Twice a year, the staff does a full-load test during which they transfer the entire facility load to the standby system.
Not long after the generators began operating in 2008, they were pressed into action to provide power to the casino. In the first instance, an intermittent brownout caused by a voltage drop brought the units on automatically and forced the facility to operate on generator power for about two hours. Another time, a complete loss of power lasted only a few minutes. The units fired up and came online within 10 seconds.