BY CURT HICKCOX,
PUBLIC UTILITIES MAINTENANCE INC.
The electricity delivery system operating in the U.S. and the rest of the world is one of the greatest engineering feats in history. Its design, construction and reliable operation is one of the most critical assets to our daily lives.
This system, the electric grid, comprises high-voltage transmission circuits mainly supported by steel structures that transport electricity from the generation plants to substations where transformers, breakers and other equipment adjust the electricity’s voltages before it is sent to distribution lines and structures that deliver the electricity to homes and businesses. This system is the backbone of the power delivery system that connects and interconnects each utility company with its customers.
In the U.S. alone, there are more than 200,000 miles of high-voltage transmission lines, 10,300 transmission substations and 2,200 distribution substations. Substation equipment includes some 12,200 autotransformers, 195,000 oil circuit breakers, 64,000 transformers, 26,000 voltage regulators, plus the associated structural steel, bus-work, switchgear and foundations. Virtually all the equipment is made of painted steel that is susceptible to corrosive attack from atmospheric exposure. Even the structures, often constructed of galvanized steel, are subject to corrosive deterioration. Because corrosion causes equipment failures that result in service disruption, electric utilities must minimize corrosion through practices that include engineering design during construction and installation, as well as established maintenance programs throughout the service life.
The direct cost of corrosion in the U.S. electric transmission and distribution segment is some $700 million annually. Many U.S. electric utilities maintain their substation and distribution assets by preventing and controlling corrosion. They understand the criticality of substations to their system reliability and how corrosion can damage these components. But often and for various reasons, utilities are reactive rather than proactive when dealing with corrosion. Dealing with corrosion can be expensive, and dealing with it after the fact only increases the cost. But these expenses pale compared with the costs of a failure and resulting service outage. Properly planned and executed prevention programs control and minimize upfront expenditures while maintaining system reliability.
Corrosion is controlled primarily through painting and generally is considered a maintenance, operational or revenue expense. Unfortunately, most utilities fund these types of expenses only minimally because they usually are considered a charge against profit rather than a profit generator as a capital expenditure would be. Available funds are funneled toward expenditures that help the bottom line, but the bottom line suffers more as the result of a corrosion-related failure than by spending money upfront on prevention and maintenance.
Construction of the U.S. high-voltage transmission system and its corresponding distribution system peaked in the 1970s (see figure).
Most transmission lines were built from the 1960s through the 1990s. Nearly 75 percent of the North American electric grid was built during these 40 years. The age of these transmission lines and their large numbers will increase the amount of maintenance work required to keep the system safe and reliable. Because there are so many substations of the same general vintage, many will require corrosion repair during the same time, which will stretch resources and budgets. A utility can control its spending at a more consistent rate by being proactive with its maintenance program, which will allow for better planning and cost-effectiveness that will result in higher reliability and profitability.
A recent Associated Press study found electric customers are spending 43 percent more than they did in 2002 to build and maintain the electric infrastructure. Since then, the number of power outages has remained infrequent, but it takes longer to restore service. One conclusion is the system is not being maintained and upgraded in a way that improves its reliability. It’s another indication of a reactive approach: spending money to fix a problem rather than spending it to prevent one. Since 2002, there has been a 15 percent increase in the annual number of minutes the average customer is without power (although the number of outages slightly decreased), but spending per customer on local distribution equipment and maintenance rose at twice the rate of inflation. This seems to indicate that because of the distribution system’s age, it is getting more expensive to maintain the system’s high level of reliability.
Although the U.S. electric distribution system has serious corrosion issues, it is not all gloom and doom. Many utilities have implemented programs to deal with corrosion in their substations and have eliminated corrosion-related service disruptions. Industry organizations such as the International Electronic and Electrical Engineers Association (IEEE), the Electric Power Research Institute (EPRI) and the National Association of Corrosion Engineers (NACE) have established task groups and are researching and publishing standards relating to substation corrosion. The federal and state regulatory agencies also have started taking note of the condition of the electric grid, and, in some cases, have begun to mandate remediation and improvements. Proven methods of controlling corrosion exist, and with a little effort and dedicated funding, corrosion-related electric service disruptions can be eliminated.
The first step is to assess the distribution system. A utility must understand the condition of its system before it can determine what needs to be done and the cost. The assessment should include a visual inspection of the system components, a condition rating per industry guidelines, prioritization based on the utility’s requirements (i.e., component criticality, condition, logistics and outage limitations), surface preparation and coating system requirements and cost estimates. Simple testing, such as for lead in the existing coatings and coating film thickness and adhesion, should be performed as part of the assessment. NACE and IEEE joint task groups are writing standards that reference corrosion control in the transmission and distribution industry that include details on performing coating assessments on transmission and distribution structures. These standards should be published by the end of 2013.
Once the assessment is complete, a defined program can be developed using a specific time frame and other criteria that conform to the utility’s long-range plans. Upon funding, a project scope can be assembled easily using the assessment as its basis, followed by job award to a qualified contractor. It is critical that only contractors and workers with specific substation training and experience be allowed to bid on this work. Aside from demonstrated capabilities in preparing and coating complex electric distribution equipment, the contractors must have excellent safety records with health and safety programs specific to substation structures and equipment. The project specification must be tailored to the scope and not generic. A coating schedule that details surface preparation and coating system requirements is integral to the specification, as is a listing of all applicable safety rules and regulations.
Various surface-preparation methods for steel surfaces may be employed in a substation. Power washing and abrasive blasting should not be used in an operating substation because of potential safety and damage issues. The Society for Protective Coatings (SSPC) has published surface-preparation standards widely specified throughout the industrial coatings industry, and certain standards ranging from solvent cleaning to hand and power tool cleaning to chemical stripping are applicable in substations, as well. The idea is to have a clean, dry, sound substrate free of contamination, peeling and flaking coatings and loose rust before application of the new coating system. The unique configuration and sensitive nature of many types of electric distribution equipment, especially transformers and their cooling radiators, can make it difficult to properly prepare before coating, but many methods are available to prepare the surfaces. Again, a contractor with specific experience in transformer painting is crucial to the project’s success.
The application of protective coatings also presents challenges because of equipment configuration, as well as procedural and safety constraints associated with working near energized electrical equipment. Spray application usually is not allowed, and the standard hand methods of coating application such as brush and roller, although acceptable on breakers, tanks, etc., are not conducive to proper coating coverage on radiator banks. Flow coating, a specialized paint application technique, is a process similar to dipping radiator tubes. A recirculating system comprising a low-pressure pump, hoses, specially designed nozzle and collection setup allows the coating to reach and covers nooks, crannies and crevices on the radiator tube surfaces. Proper and consistent paint viscosity is required. Although the process is complicated, it is the only application method available for field use that ensures complete coverage of a radiator’s surface area. The thickness of the paint film is important because a too-thin film does not provide adequate corrosion resistance, and a too-thick film can interfere with radiator cooling efficiency. No other method of field application can access and coat these areas, and only a contractor experienced in this application method should perform flow coating. Flow coating also is used for surface preparation on the radiators because often chemical stripping is the only way to remove suspect coatings from surfaces inside the fin banks where hand-cleaning methods cannot access.
The U.S. has an electric transmission and distribution system made of aging structures and equipment. Service interruptions because of failures from corrosion are a fact, but they can be prevented by a proactive approach that includes correct inspections and proper maintenance. Proven methods of ensuring the long-term, cost-effective protection of the system exist. Experience has proven the viability and benefits of formal maintenance coatings programs for steel substation structures and equipment.
Curt Hickcox is vice president of Public Utilities Maintenance Inc., an SSPC-certified and ISO-registered corrosion control contractor specializing in the global electric transmission and distribution industry. He is a member of IEEE, NACE and SSPC and is chairman or vice chairman of three joint task groups responsible for transmission and distribution coatings-related standards. For more information, visit www.puminc.com. Reach Hickcox at firstname.lastname@example.org.
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