MidAmerican Energy Co., an electric and natural gas utility that serves customers in Iowa, Illinois, Nebraska, and South Dakota, needed some additional generation capacity to ensure an adequate power supply for the summer months. It also wanted a generation resource that could eventually be relocated and distributed to provide backup power and increase system capacity. In May 2000, 28 portable, 2MW diesel power modules were installed near three of the utility's substations. Des Moines, Iowa-based Anderson Erickson Dairy was the first MidAmerican customer to take advantage of the shared generation option as an alternative to purchasing standby generation equipment. This article discusses the process MidAmerican went through to install and operate distributed power modules for capacity support and individual customer benefit.
The Utility's Perspective
Each substation location met the interconnection requirements of Mid-American and the Mid-Continent Area Power Pool (MAPP). Planning for this accredited-capacity approach required engineers to conduct electrical system reviews and load-flow studies for 12 possible sites. These analyses determined which site would best accommodate 20MW of generation next to a 13.8kV distribution substation.
During the approval process, it was also necessary to obtain permission to eventually remove the power modules from the grid. Engineers performed a removal study to evaluate the effects of relocating a large number of modules to customer sites. The study indicated that about half of the modules could be relocated without impacting the added reliability of the grid.
After the installations, Mid-American signed a contract with Ziegler Power Systems, a Caterpillar dealer. The contract included a complete 10-year warranty and a 10-year operations and maintenance agreement, with Ziegler handling the remote control of the units. One phone call by Mid-American's energy trading dispatchers in Des Moines, Iowa, to Ziegler's control center in Shakopee, Minnesota, initiates a dispatch order to start or stop the generators (see Photo 1, on page 26).
Ziegler also sends MidAmerican historical operating data via the Internet at the end of each day to identify burnt fuel amounts, kilowatt-hour generation for each unit, and other information for accounting and environmental-reporting purposes.
Each unit generates 2MW at 4160V and has a step-up transformer to raise the voltage to 13.8kV. Aggregation to at least 50MW was necessary to reach a minimum threshold that qualified as a dispatchable generation resource within a 4400MW-generation mix.
There are other aspects of the power modules that affect MidAmerican only, ranging from startup times and metering to sound levels.
MAPP requires that offline operating reserves have the generation capacity to attain full-load operation within 10 min. The old combustion turbines did not start as fast as the new diesel-fired reciprocal units. Typically, the old turbines required longer periods of operation to make the best use of the associated startup costs, and each turbine start decreased the time to the next overhaul.
An ideal unit enables a dispatcher to make a last-minute decision to start the units. It also allows dispatchers to reverse a decision if system or economic conditions suddenly change.
The normal dispatch guidelines for the power modules specify a half-hour notice with a 1-hour minimum run time. This feature is a desirable addition to the generation mix, especially when no-notice starting is also available for system emergencies. The power modules have earned the title of “super peakers” from Mid-American's dispatchers because they can be started and loaded much faster than any other generation resource within the system.
Utility operators make sure that one power module operates during planned maintenance outages to avoid customer interruptions. They also use the modules for voltage support and transmission outages. In fact, operators have requested a slower startup time to avoid voltage control swings on the system (20MW in 7 min instead of 3 min). This was accomplished by staging the generators online with 1-min delays between the start of two units at a given time, or alternately using half-minute delays and starting one unit at a time. In a customer application, the units can be started and fully loaded in 10 sec with the addition of appropriate controls and high-speed switchgear. A return to utility grid operation would not require a customer outage because synchronization to the grid would be possible.
Each site provides revenue class metering as well as real-time telemetering data. The telemetering data is sent to MidAmerican's SCADA system on an aggregated site basis. Accounting is done on a per-unit basis, while real-time operations are done on a site basis. These functions also can be done equally well or better when the units are distributed throughout the electrical system.
This high-accuracy class of metering is required to meet both MAPP accreditation requirements and customer metering requirements. Accreditation requires that the measured capacity is the net station power usage. This means that the metering can be located after the station power, or the station power can be metered separately and subtracted from the gross generation.
Station power is provided to heat the enclosure to 70°F in the winter, to heat the engine through water-jacket heaters, and to heat the generator windings. It also provides lighting for controls and interlocks and energy for battery chargers.
Actual allowable hours of operation are determined by accurate measurements of fuel usage. The accepted emission rate for all 28 units is based on field tests completed on the first unit off the assembly line (see Photo 2, on page 26). The 10-module sites are permitted to burn a maximum of 1,750,000 gallons of low-sulfur diesel fuel each year.
The upgraded Caterpillar 3516 B engines were fitted with low nitrogen oxide equipment, allowing a maximum of 1190 hours of operation per year with a Title V environmental permit application. Nitrogen oxides became the determining pollutant that defined the maximum allowable hours of operation. Each site must emit less than 250 tons of pollution annually.
The modules were sound attenuated to meet 85 Dba levels measured at a 50-ft distance from each module. Typical area requirements for sound levels of 75 Dba were met by designing the site layout with adequate distance from the modules to dissipate the sound energy before it reaches the property line. (See Photo 3, on page 28).
The Customer's Perspective
Initially, the 28 power modules were located at three substation sites. They could have been located at 28 different sites throughout the MidAmerican service territory in a distributed generation configuration. However, each time engineers relocate a power module to a customer's site, they must meet new interconnection requirements, local environmental codes, and local city codes. These requirements are far more stringent near residential areas. Therefore, the cost to relocate a single module must be considered in the economics of a move. Officials at Anderson Erickson Dairy (AE) carefully evaluated the situation and found that the benefits outweighed the costs.
Before installing the power module, AE risked losing millions of dollars of product if an outage lasted more than 6 hours during the summer. In addition, long winter outages could freeze up the plant facilities and cause further damage and lost production.
Because the dairy's power backup needs are not immediate, it was not necessary to install higher-cost automatic controls and fast-acting, high-voltage circuit breakers to enable quicker startups. However, this lower-cost approach does require another outage to return to the utility because synchronization is not possible with manual switching.
MidAmerican receives some run-time benefit by relocating individual power modules. At the substation, the power modules are limited individually to 1190 hours per year, but they can operate 1900 hours per year at a single generator site.
There were numerous challenges in relocating the power modules to the AE customer location, as you'll read about in the following sections.
In AE's case, city codes require ambient sound levels of 55 Dba at the property line of the nearest neighbor. Site conditions did not allow adding distance between the generator and the neighbor's property line. MidAmerican met city codes by first applying for a variance from 55 Dba to 64.4 Dba based on actual background sound levels measured over a period of several weeks.
The reduction in sound level from 85 Dba to 65 Dba at a 50-ft distance was then met by replacing the original generator enclosure with a better design that incorporated large inlet and outlet silencers. These silencers attenuate the sound while letting cool air enter the unit, pass through the radiator, and exit. The new enclosure was provided by DTS Inc., located in Tea, South Dakota (see Photo 4, on page 28).
One application that engineers evaluated had a substation located onsite, with room for three generators within 100 ft of a spare set of high-speed and high-voltage isolation breakers. The site operators also had oil-spill prevention and related oil-spill catch basins already in place, ready to apply to the new modules. There was at least a half-mile distance between the power module location and the property line. No additional sound attenuation was needed because the sound energy dissipated substantially over this longer distance.
Aesthetics and safety
Decorative and security fencing were installed around the generator site, and the power module enclosure was painted to blend into the environment. The home originally located at the site was relocated (see Photo 5 and Photo 6).
Metering and operating issues
With DG applications, these issues can be complicated. Regardless of where the power module connects electrically (utility or customer), provisions must be made to account for generation costs and metered billing.
If the customer plans on paying the cost to run the standby generation, the metering configuration must be considered to establish accurate billing. If the generator is physically located behind the meter, but is separately metered, as in the case of AE, totalizing the two meters will account for all of the energy delivered to the customer.
An overview assessment to the metering problem is that special adjustments are needed when a shared resource is employed, and these adjustments must recognize the reason for the generator operation and the location of the generator in relation to metering points.
Connection and Relocation Costs
The cost of relocation and interconnection varies by a factor of 4 to 1. Hospitals located near residential areas with fast-starting requirements and no outages allowed cost the most, while some industrial locations produce the least cost. Utility system protection relays and control logic can also be a significant cost factor. The AE application falls in the lower-cost range.
It is typical to have planned short-term outages during installation and possible unplanned short-term outages during the startup and testing phase of the project.
One highly sensitive, process-oriented customer would not accept planned or unplanned outages during the startup phase of the project. In this case, engineers completed the necessary switchgear modifications one full year prior to the generator installation to take advantage of a planned plant shutdown that occurred only once every two years.
Each customer that relocates a generator gains the option to purchase the generator and have its own interconnection with MidAmerican. This allows the customer to choose from a traditional curtailment arrangement or an accredited capacity and bulk power sales arrangement. Eventually, the customer will have the opportunity to sell power to MidAmerican when the cost of wholesale power exceeds the cost to operate the power module.
AE elected a pay-as-you-go option for use of the generator during outages; they only pay for using the generator when it is needed. Interconnection and relocation costs are paid for separately over a fixed term. An available alternative was to rent the unit for a flat fee per month.
The results of the MidAmerican project demonstrate that using aggregated 2MW portable power modules can provide reliable system capacity while meeting or exceeding performance expectations.
According to MidAmerican, customers that can benefit most are large industrial facilities and those in the healthcare and casino industries. These customers have the large flat loads that usually have the most to lose from long-term outages and the most to gain from a free-market environment.
As MidAmerican engineers found out, relocating the modules is feasible, but the costs can vary significantly depending on local site conditions. Metering and billing of the energy for a shared generation resource is complex, but achievable.
The portable power modules are not as mobile as originally anticipated. In hindsight, the modules should have been built with DTS enclosures like the AE unit and moved onsite with standard heavy-transport equipment. Transportable, in place of portable, would have been acceptable, and the sound attenuation is far superior (65 Dba vs. 85 Dba at 50 ft). The new enclosure also contains a single 4200-gallon fuel tank, which would have simplified the design of the fuel system. All in all, the project has involved nearly all of the departments within MidAmerican Energy Co., making the company better suited to address the issues for future distributed generation applications.
Gene Kempers is recently retired from MidAmerican Energy Co. and is currently an independent management consultant and the president of UniqueApproach Inc. You can reach him at firstname.lastname@example.org.
Jim Rasley is the director of power and energy solutions at MidAmerican Energy Co. in Des Moines, Iowa. You can reach him at email@example.com.