By Douglas J. Smith IEng, Senior Editor
Distributed generation not only meets specific customer needs, it also supports the economic operation of the transmission and distribution grid.
What is distributed generation? Some people believe it only refers to plants with a capacity up to 30 MW, while others believe it includes cogeneration plants generating hundreds of megawatts of power. The jury is still out on this question.
There is no question, however, that distributed generation (DG) is a stand-alone electric generation unit located downstream of the electric distribution system at or near the end user. Not only does DG meet a specific customer’s energy needs, it can also support the economic operation of the transmission and distribution grid.
It is generally accepted that centralized electric power plants will remain the major source of electric power supply for the foreseeable future. DG supporters, however, say the technology can complement central power by providing low capital cost incremental capacity to the grid or to an end user. Installing DG at or near the end user can also benefit the electric utility by avoiding or reducing the cost of transmission and distribution system upgrades.
According to Arthur D. Little, DG is economically attractive to electric utilities that are faced with system constraints, particularly in transmission and distribution. Without these constraints, Arthur D. Little says, DG would be more costly than a central plant. When correctly applied DG can improve electric utilities’ asset utilization.
Not withstanding the current crisis in California, the aim of restructuring the electric power industry by federal, state and local government policymakers was to improve the economics of electric power generation and delivery. With deregulation and restructuring, the electric power market for distributed generation has grown.
We have come full circle from Thomas Edison’s Pearl Street Power station, which was essentially distributed generation, to central generating plants and now back to distributed generation. What goes around comes around.
Currently DG is used for:
- Standby or emergency power.
- Cogeneration (combined heat and power).
- Peak shaving.
- Grid support.
- Stand alone on-site power.
Today, combustion turbines, reciprocating engines, micro turbines, photovoltaics and fuel cells are available for DG. However, the economics of the different technologies depends upon the application.
Under the U.S. Department of Energy’s (DOE) Office of Industrial Technologies’ “Distributed Generation Program,” DOE is partnering with electric and gas utilities and industrial users of electricity to identify technologies that will improve the generation, environmental and financial performance of distributed generation plants. A major goal of the program is to look at adapting the improvements made to large advanced gas turbines (lower emissions, increased efficiencies and lower costs) to micro turbines.
Micro turbines range in size from 30 kW to 300 kW and have efficiencies of approximately 26 percent. Under the “Distributed Generation Program” the efficiency of micro turbines is expected to reach 40 percent when operating in simple cycle and greater than 90 percent for micro-cogeneration.
Other program objectives are to reduce the cost of producing electricity by 10 percent, NOx to less than 10 ppm and CO below 25 ppm without any post combustion controls. Enhanced fuel flexibility and increased reliability, availability and maintainability are also major goals of the program.
According to most reports, reciprocating engines are the fastest selling distributed generation technology in the world. Natural gas fired reciprocating engine generators, from 500 kW to 5 MW, can achieve efficiencies of 38-40 percent. Other advantages of reciprocating engines are their low capital cost, ease of startup, proven reliability, and good load following characteristics and heat recovery.
Over the last several years, with improvements in combustion design and the use of exhaust catalysts, emissions from reciprocating engines have been significantly reduced. Over the next few years, engine manufacturer expect to increase efficiency by 15-20 percent and to reduce emissions of NOx, hydrocarbons, air toxics and greenhouse gases by at least 20 percent.
Maintenance costs of reciprocating engines will be reduced by increasing the interval between cylinder head overhauls from 15,000 hours to 24,000 hours. The engines are also being designed to operate for 40,000 hours before a major engine overall is required.
In addition to burning diesel and natural gas, future reciprocating engines will burn a variety of other fuels including landfill gas, propane, and gases from the gasification of coal, biomass and refinery wastes.
Although the first fuel cell was developed in the early 1800s, they were not used for the generation of electricity until the 1960s when NASA installed them on the Gemini and Apollo spacecraft. Today fuel cells are under development for distributed generation applications from 1 kW to one MW and above.
Over the last several years, the primary focus of fuel cell development has been the development of advanced high temperature systems. It is expected that high temperature fuel cells will have higher efficiencies and lower capital cost than existing units. High temperature fuel cells include molten carbonate fuel cells (MCFC) and solid oxide fuel cells (SOFC).
The current R&D schedule is to have high temperature natural gas-fired MCFCs and SOFCs commercially available by 2003. According to DOE, the cost of the fuel cells will range from $1,000 to $1,500/kW and have efficiencies up to 60 percent. They will also have low emissions and a stack life of 40,000 hours.
DOE is also working with industry on the further development of the 1 kW proton exchange membrane (PEM) fuel cell. A major aim of this program is the development of PEM fuels cells that will operate at higher temperatures. In addition to supplying electricity, PEM fuel cells with higher operating temperatures can also be used in buildings for cooling and heating.
A fuel reformer/gasifier, to produce hydrogen, is essential for fuel cell operation. Unfortunately, the production of hydrogen is expensive. Consequently, fuel cells will only become economically viable with the development of a reformer/gasifier capable of producing low cost hydrogen.
Although fuel cell manufacturers believe a cost-effective reformer/gasifier can be developed, some people are saying that they will never be competitive. Dale Simbeck, Vice President with SFA Pacific, Inc., says, “The high cost of making hydrogen is the kiss of death for fuel cells.” In Simbeck’s opinion, fuel cells will never be an economically viable technology for distributed generation applications.
Applying Distributed Generation
On the road again: 23 MW of distributed generation. Photograph courtesy of GE.
Speed and mobility are major advantages of distributed generation. Distributed generation using small gas turbines, micro turbines and diesel engines can be transported to a site and producing electric power in a very short time.
To protect their customers from interruptions in electric service in the summer of 2000, Commonwealth Edison rented five portable power plants from GE. Each of the trailer-mounted gas turbines, based on the GE LM2500 turbine, has a capacity of 23 MW. Because of the mild summer, the units only operated for about 90 hours. Although the running hours were less than anticipated, the units did give the utility the satisfaction of knowing that additional capacity would be available if needed, said Kris Zadlo, technical studies director for Commonwealth Edison.
When Commonwealth Edison needed them, the units were able to be up and running in less than 30 minutes. At the end of the summer season, the trailer-mounted gas turbines were shipped to Ireland where they were used for supplying peak power during the winter months.
According to a report commissioned by Public Service Commission of Wisconsin, consumers will not benefit from deregulation unless substantial improvements are made to the state’s electric transmission system and additional power plants are constructed. Currently Wisconsin imports 20 to 25 percent of its daily electric requirements.
During the last two summers, Wisconsin Public Service (WPS) has set peak demand records. This trend is expected to continue in 2001 and 2002. In the past, Wisconsin utilities were able to supply any additional capacity from their own coal, gas, hydro and nuclear power plants. Additional capacity was purchased under long-term contracts and on the spot market.
Unfortunately, although the spot market was able to supply any needed power, there was no price protection. Because of the economic uncertainty, WPS decided to install temporary electric generators to supply the peak summer demands.
After evaluating the options, WPS contracted with Cummins Power Rent Great Lakes for the rental of 34 MW of diesel generation. Under the contract Cummins supplied 18×1.25 MW and 12×1.5 MW diesel generators, all with step-up transformers. Two 1.25 MW generators were supplied for backup power.
The two substations where the generators were installed are located in the most remote part of WPS’s service area. It is also the weakest part of the utility’s 115 kV transmission system. Consequently not only do the units provide peaking power, they also reinforce the electric supply system.
Piehl, the first substation, is a temporary facility built specifically to house the rented diesel generators. When additional power is brought on-line in the state by independent power producers, within three years, the substation will be retired.
Venus, the second substation, is an existing facility. The engines at the Venus substation stabilize the transmission system. Over the next three years, WPS will be upgrading the transmission system and, when completed, the diesel generators will be removed.
All of the WPS temporary diesel generators can be dispatched remotely from the utility’s operating center in Green Bay. As needed an operator goes to the substations to monitor and refuel the diesels. Because the substations are seven miles apart, only one operator is required.
When in operation the individual engines generally run from three to ten hours. The engines operate up to 300 hours during the three summer months. In September 2000, the diesel generators were removed but will be re-installed for summer 2001. WPS will increase the rental peaking power by 24 MW, this year, using 16×1.5 MW diesel generators installed at a third substation in northern Wisconsin.
As concerns mount regarding the reliability and availability of grid power, distributed generation is once again becoming a technology of choice. For the foreseeable future, the market for DG looks very promising.
There are technical and regulatory barriers to the application of distributed generation. Many of the technical barriers relate to the electric utility’s responsibility to maintain the reliability, safety and quality of the electric power system.
A major safety concern of utilities is to prevent “islanding.” Islanding is where a portion of the grid is still energized while the remainder of the grid has been de-energized. This can happen during a power outage. To alleviate these problems electric utilities have interconnection requirements that include:
- Requirements for protective relays and transfer switches.
- Power quality requirements.
Although distributed generation units have protection devices, many electric utilities are reluctant to accept them and require additional protection. When this happens, the developer of the distributed generation must install separate protective relays. Unfortunately, there is no uniform standard for interconnecting distributed generation with the grid.
For example, the owner of a 0.9 kW photovoltaic system, with its own over/under voltage and over/under frequency protection, was required to install separate protective relays. This increased the cost of the system by approximately eight percent. At another installation in Colorado, a 140 kW reciprocating natural gas-fired distributed generator was forced to install a multi-functional solid state relay system. Again, this was in addition to the multi-function interconnection package installed on the unit.
Two states, New York and Texas, have adopted rules for the interconnection of distributed generation. The New York rules do not require interconnection studies for facilities less than 10 kW. Distributed generators up to 50 kW interconnected on a single-phase line, or a facility up to 150 kW on a three-phase line, may or may not require a study. However, plants above 150 kW do require an interconnection study to be carried out by the distributed generators. The distributed generator also pays for the cost of the study.
The Texas Public Utility Commission’s rule is more flexible and accommodating to utilities and distributed generators. In Texas, a utility may conduct a study before connecting any facility to the grid. However, Texas prohibits the utilities from charging distributed generators for the study in the following applications:
- A DG that will not or does not export power to the grid, regardless of size.
- Individual single-phase DG exporting less than 50 kW to the utility on a single transformer.
- Individual three-phase DG exporting more than 150 kW to the utility on a single transformer.
The Texas rule also establishes certain performance-related standards for a utility where an interconnection study is required. These include a provision that the pre-interconnection study take no longer than four weeks and the distributed generator be given an estimate of the study costs before the utility initiates the study.
Regulatory barriers are another obstacle for distributed generation. These can range from outright utility prohibition to tariff barriers. The tariff barriers include:
- Demand charges and backup tariffs.
- Buy back rates.
- Exit fees.
- Uplift charges for distribution, capacity and losses.
The cost of overcoming these regulatory barriers can be very expensive. According to a National Renewable Energy Laboratory (NREL) report, “Making Connections,” a 200 kW fuel cell project was assessed a demand charge $19.20/kW/month when off-line. If the unit is down during the utility’s peak demand period the total cost for one outage could result in demand charge of $46,080. In addition, the distributed generator receives no benefits when they are generating power for peak shaving.
In another case cited in the NREL report, a 5 MW cogeneration project was cancelled because the electric utility assessed a standby charge of $1 million. Although the host facility, a hospital, had backup power, the utility refused to offer a partial credit for the capacity provided by the backup system.
More bizarre is a 120 kW facility that was assessed a backup charge of almost $144,000 even if the facility operated baseloaded. With the plant operating at baseload and at full capacity, the plant can only generate $100,000 worth of electricity annually. The public utility commission eventually rejected this tariff.