Public Power - May 2008 - (Page 35)

at “getting right to the basics,” said Mike Hyland, APPA’s vice president of engineering services. “There are common knowledge things utilities can do that will make delivery more efficient. This is one of those nice little hidden gems.” PWC’s key to making the project work was keeping close track of data. “Very few utilities document their transformer load management practices,” said Conger. “It’s an art that gets placement unit, the known core losses of both, along with removal and replacement costs. Of the 75 units examined, the department concluded that about a third were oversized. Using money spent in 2005, it identified $214,636 in replacement cost savings, alone. Additional savings in core losses added up to more than $77,000. Although winding losses weren’t calculated, since they increase with load tion transformer A and B factors (noload and load losses) is also critical. A and B factors, developed by Westinghouse in response to energy shortages in the 1970s, allow utilities to make more economic transformer purchase decisions, because they can specify preferred life-cycle energy loss factors. Factor A is a present value estimate of the capital cost of equipment that does not depend on load, while factor B an “It’s already prevented us from buying four 2,500 kVA pad-mounts.” handed down from one crew boss to the next. An inexperienced utility engineer that does not have commercial or industrial load trend data will size a transformer based on peak load.” PWC’s project required cooperation over several months from a number of departments including engineering, electrical construction, power billing, information services and the geographic information system (GIS) section. “We got everyone together and explained how much potential savings we could get if we could prove oversize and they bit into it,” Cooper said. The utility gathered and evaluated two to three years’ worth of billing information for 75 of it’s 3,700 three-phase distribution transformers against meter and GIS data. “We picked the maximum demand in any month for each year,” Cooper said. Assuming a diversity factor enabled the inclusion of transformers serving more than one customer. Using kVA size, ANSI transformer guidelines (C57) and their own experience, the department developed a protocol for transformer change-outs based on economic loading. Any decision to replace a transformer had to make economic sense. Factors calculated include the first cost of the existing transformer, the cost of the rewww.APPAnet.org (I2R), additional savings are anticipated. Now that replacement candidates have been identified, whenever an appropriate customer request for replacement comes in, the construction department schedules an outage, replaces the equipment and installs it at the new location. The new placement is usually phased in. “It may take us quite a few years,” said Cooper. “It’s a good thing to build into our routine. It’s already prevented us from buying four 2,500 kVa pad-mounts.” Cooper acknowledges that mimicking PWC’s program could be harder for utilities that don’t track load data. Going forward, the important thing for utilities is to learn how to treat connected load figures. “Across the country, demand is 30 percent to 60 percent of connected load. That is not based on data, but experience,“ he said. “Connected load is typically two to three times what you see on a meter,“ said Conger. Although the approach is reasonably simple, the work requires broad knowledge of utility economics, manufacturer distribution transformer design criteria and the characteristic load behavior of different residential, commercial and industrial customers. A thorough knowledge of how to determine distribu- estimate of equipment that does. “When a utility defines its transformer B factor, it is communicating to the manufacturer its costs of energy as well as its transformer loading practices,” PWC said in a write-up of its program. “The transformer manufacturer goes through a series of design iterations and finds the best balance in transformer design based on the first cost of the transformer and the winding losses within the transformer.” In the course of the transformer sizing work, PWC discovered other opportunities to reduce the costs of its electrical assets. For example, the sizing work led to a re-evaluation of metering practices. Instrument current transformers are most accurate when they are loaded at nameplate. The maximum inaccuracy level under ANSI takes place when current transformers are loaded below 70 percent. When oversized, losses ensue along with more metering inaccuracies that lead to revenue losses. “A municipal electric utility is expected to do more with less,” PWC notes. “Maximizing transformer efficiency and minimizing transformer losses ultimately leads to lower rates for the municipal customer.” ❚ Ben Tansey is an energy writer in Seattle. MAY 2008 35 http://www.APPAnet.org

Table of Contents Feed for the Digital Edition of Public Power - May 2008

Public Power - May 2008 Contents Perspective LEEDing the Way Ontario Moves to Mandatory Time-of-Use Pricing Journey to the Smart Grid Right-Sizing Transformers Energy Audits for Large Industries Economic Development Community Broadband Reliability Hometown Connections Parting Shot

Public Power - May 2008

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