July 15, 2008

Focus on O&M (July 2008) 

ELECTRICAL SAFETY
Protection against arc flash more important than ever

Arc flash may be the greatest—yet least understood—danger in today’s power plant. Its danger is not just the risk of electrocution facing technicians when maintaining switchgear but also the equally deadly concussive blast effects and exceptionally high temperatures that instantly occur when a short circuit occurs. In some instances, all three effects occur in chorus, further dropping the survival rate. (See “Arc flash protection should be job No. 1” in POWER, February 2007 for a special report on arc flash causes and technologies available to improve worker safety.)

 

The typical arc flash occurs in fractions of a second and without warning when electrical current, designed to move along a particular path, short-circuits either through the air to the wrong conductor or to a ground path. The arc flash that results has been compared to looking directly at the noonday sun, and the temperature of the arc can be as high as that near the surface of the sun—10,000F.

Secondary effects include explosion, with perhaps shrapnel damage, and an intense sound pressure wave. Because power plants have installed high-voltage switchgear in enclosed rooms in recent years, the blast, flash, and temperature effects are further magnified. In older plants where switchgear is sitting in open bays and standing on the turbine room floor gratings, the blast cone can reach out and touch plant staff several floors away (Figure 1).

 

 

The cost of arc flash events every year is many millions of dollars in equipment damage, lost production, and lawsuits. But the human toll is without price. A 10-year study by Électricité de France found that arcing caused 77% of all recorded electrical injuries. Similarly, one corporation noted that up to 80% of its electrical injuries involve thermal burns due to arcing faults. The U.S. National Institute of Occupational Safety and Health (NIOSH) tabulated 44,363 electrical-related lost-workday cases from 1992 to 2001. Arc flash burns accounted for 17,101 (or about 39%) of those cases.

Another misconception is that only high-voltage switchgear requires arc flash protection. Not true. I can tell you from personal experience that the heat and blast effects from a standard 480-volt motor control center can cause injuries. According to National Fire Protection Association (NFPA) 70E, the following flash protection boundaries (Figure 2) define the safe working distances from an energized component:

• Up to 750 V: 3 feet
• 750 V to 2 kV: 4 feet
• 2 kV to 15 kV: 16 feet
• 15 kV to 36 kV: 19 feet
• Over 26 kV: must be calculated

 

 

An often overlooked risk group is thermographers, who must understand these safety standards and be properly outfitted with protective gear when taking readings. They also should be accompanied by a qualified electrician.

Gone are the days when you stuck your hands into any electrical switchgear, regardless of voltage, protected by only a hardhat, safety glasses, and a pair of rubber gloves. Remember, the human heart will begin defibrillating, and soon stop for good, when hit with a relatively miniscule 80 milliamps of current.

New regulations are making arc flash protection from potential electric shock, flash, and blast effects mandatory for plant owners. NFPA 70E now requires protection from arc flash events and also requires a flash hazard analysis. The Occupational Safety and Health Administration (OSHA) has followed suit and has updated its electrical safety procedures to account for arc flash for the first time. The OSHA change was effective August 13, 2007. The OSHA regulations also recognize NFPA 70E and the National Electric Code (NEC) as industry standards that should be followed. Also, check with your insurance carrier, because it’s typically their practice to require conformance with standard industry specifications.

IEEE 1584 provides a guide for performing the arc flash hazard calculations. There is one area in the calculations that many utilities have found to be problematic—how to accurately determine electrical protective device characteristics or relaying in the plant. The response time assumed has a stunning effect on the calculated arc magnitude and duration. Although it’s not required by the regulations, a sensitivity analysis using relay actuation time is easy to perform—many plants have decided to assume instantaneous relay actuation times for the most conservative calculation.

OSHA has cited plant owners after arc flash events under the General Duty Clause, which states: “each employer shall furnish to each of its employees a place of employment that is free from recognized hazards that are likely to cause death or serious physical harm.” The crackdown follows the release of industry statistics showing that the 80% of accidents and fatalities related to electrical work by “qualified workers” are caused by arc flash. Other facilities have been cited under 29 CFR 1910.335 (a)(1)(i), which requires the use of protective equipment when working where a potential electrical hazard exists and/or 29 CFR 1910.132 (d)(1), which requires an employer assessment of all workplace hazards and the use of personal protective equipment.

I suspect many readers also understand that NFPA 70E specifically excludes utilities from the code’s coverage. However, just because a code or regulation has a “loophole,” plant owners shouldn’t hide behind it when worker safety is involved. Chapter one of NFPA 70E states that employers are responsible for providing workplace practices and procedures and employees are responsible for following those procedures.

If your facility does not have an electrical safety program that addresses the extreme dangers of arc flash, suitable protective equipment for workers, and a training program for the equipment and arc flash protection, then you are gambling with your life and the lives of your coworkers.

—Dr. Robert Peltier, PE

COATINGS

Laramie River Station uses new coating technology

Preventing catastrophic failure is the No. 1 priority for power industry mechanical engineers and supervisors. Though a variety of factors can contribute to such failures and ensuing production downtime, engineers unanimously agree that corrosion is the single biggest contributor to these events. The Laramie River Station, located east of Wheatland, Wyoming, implements an aggressive facility maintenance schedule each year and now utilizes new coatings technologies to help protect new and existing assets from the devastating effects of corrosion.

Laramie River Station is one of the largest consumer-operated, regional, joint power supply ventures in the U.S. and is owned by the Missouri Basin Power Project (MBPP). Basin Electric Power Cooperative (BEPC) is one of six electric utilities that own MBPP, and it serves as Laramie River Station’s operating agent. The Laramie River facility is unique in that it delivers power to two separate electric grids: the Eastern and the Western Interconnections. The plant has three coal-based units, each rated at 550 MW, which began operating in 1980, 1981, and 1982. Electricity produced at Laramie River is sent to substations in Wyoming, Nebraska, and Colorado, where it is then delivered to MBPP participants.

Dan Hagel, Basin Electric’s on-site mechanical engineer at Laramie River, is overseeing several coating and lining projects, inspections, and major repair projects being conducted throughout the facility. Hagel’s first exposure to advanced coating technologies came in 2004 during a project to reline the plant’s 10 absorber feed tanks in the wet scrubbers on Units 1 and 2. Ceilcote, the manufacturer that had installed the original system in the tanks nearly 25 years earlier, introduced Hagel to a new generation of epoxy-based lining systems that are formulated with superior environmental and anticorrosion benefits. The 2005 to 2006 relining of these tanks went very smoothly with a coating that has a maintenance life of 20 to 25 years.

Peeling water tanks. In the spring of 2006, Laramie River’s water treatment operations team inspected several of the plant’s contact basins for damage and saw large areas of flaking in the original coal tar epoxy lining. Some flakes were the size of a hand; others were the size of a sheet of notebook paper. Hagel called the coating manufacturer to ask for a recommendation. Ceilcote’s western regional manager, Dave Brysacz, had previously worked on the absorber feed tank installation with the plant’s painting contractor of 15 years, Riley Industrial Services, so together they created a comprehensive maintenance plan to recoat and line the contact basin interiors.

“Using new coating technologies to prevent corrosion-related power failures makes sense,” said Hagel. “If we can extend the maintenance life-cycle of our assets and achieve greater safety and money-saving benefits in the process, then these technologies will have a long-term impact on the power industry at large.”

The installation project will include a total of nine contact basins: six primary and three secondary basins. The primary contact basins used in the plant’s water treatment process combine lime and other chemicals with the lake water and groundwater to help reduce excess calcium and silica in the water (Figure 3). This treated water is then discharged into the secondary basins, where CO₂ is added for pH control before it is transferred into storage tanks. Stored water is then pumped through a reverse osmosis system and into the demineralizer system before being fed to the plant’s three boilers and to the six cooling towers serving all three units.

 

 

In order to avoid unnecessary production downtime during the peak summer operating season, only two contact basins would be recoated and lined per year: one during the months of January through March and the other in October through December.

The primary basins measure 85 feet in diameter; secondary basins are 100 feet in diameter. The sidewalls and floor of each basin are constructed from reinforced concrete, while the internal structure is made of carbon steel. Each contact basin is covered with a dome fabricated from aluminum (Figure 4).

 

 

Blast the old coatings. The first installation began on one of the primary contact basins in January 2007. Ceilcote’s technical representative, Tom Moran, met with Riley’s painting crew on-site for refresher training on the proper application of the new tank lining technology. The first step was removal of the old lining system inside the basin’s concrete interior and carbon steel interior structure. The basin’s steel interior was grit-blasted to a white metal finish, 2- to 3-mil profile. In some instances, a second grit blast treatment was needed to remove stubborn patches of the coal tar lining. Next, the reinforced concrete interior received one coat of Ceilcote 680 primer, which was spray-applied and back-rolled to penetrate, strengthen, and seal the concrete. Painters then troweled on one layer of Ceilpatch 610 to fill in pinholes and smooth out any remaining rough spots. Damaged areas of the concrete, in excess of a quarter-inch deep in some areas, were repaired with Corocrete 400 MP.

The internal steel structure was sprayed with a coat of Ceilcote 680 primer, one layer of Ceilgard 664 as a base coat, and a second coat of Ceilgard 664 as a top coat. This solvent-free, moisture-tolerant epoxy coating with flake reinforcement offers superior permeation resistance and corrosion protection to steel and concrete structures in highly corrosive environments (Figure 5).

 

 

Finally, one layer of Ceilcote 68 fiberglass-reinforced epoxy lining was hand-troweled as a base coat for the concrete. This was immediately followed by application of a 1.5 oz. fiberglass mat, which was saturated in via an application of Lining 68BC Resin. The fiberglass mat, in combination with the permanently tough resin, gives this unique moisture-tolerant lining system the excellent crack-bridging capability and tensile strength required for optimal concrete protection. This step was followed by rolling one layer of Ceilcote 664 as a top coat and the application of EJ3 or EJ4 in the expansion joints in the concrete floor (Figure 6).

 

 

Labor-intensive process. In all, Riley’s crew of 8 to 10 painters worked 10-hour days, six days per week for nearly three months to complete the surface preparation work and installation of the coating and lining system on one contact basin. Crews will use approximately 2,000 gallons of coatings per basin to achieve an overall film thickness of 120 mils. It is anticipated that completion of the nine contact basins will occur in December 2011.

—Contributed by Dave Brysacz (dave.brysacz@ceilcotecc.com), western regional manager, Ceilcote (www.ceilcotecc.com).

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