By Dominique Dieken, P.E., Starr Technical Risks Agency Inc.

Carbon dioxide (CO₂) has successfully been used as a fire extinguishing agent for many years. The demise of Halon 1301 as a gaseous fire extinguishing agent, due to its ozone depleting characteristics, has renewed interest in CO₂. CO₂ is a colorless, odorless, generally non-reactive and electrically nonconductive gas that is slightly heavier than air. It is self-propelling, leaves no residue and is inexpensive.

If it weren’t for one major drawback, CO₂ would be the perfect solution to just about all fire protection needs. The drawback is that CO₂ displaces oxygen, which is its main fire extinguishing mechanism. The minimum theoretical CO₂ concentration to extinguish fire with most fuels is 28 percent. But the maximum concentration at which harmful effects become noticeable in humans is about 6 percent. It is obvious that any CO₂ concentration suitable for fire protection is also lethal to humans. Although the safety record of CO₂ as a fire extinguishing agent is relatively good, several fatalities have resulted from unintended CO₂ system discharges. One of the more recent incidents occurred in 1998 at the Test Reactor Area of Idaho National Engineering and Environmental Laboratory, which resulted in one fatality and several life-threatening injuries.

The industry design and installation standard, National Fire Protection Association Standard 12 (NFPA 12), Carbon Dioxide Extinguishing Systems, has been periodically revised since its inception in 1929. Starting with the 2005 edition of NFPA 12, new requirements for personnel safety were added to the standard which required that all existing CO₂ fire suppression systems be retrofitted with warning signs, lock-out valves, pneumatic time delays and pneumatic predischarge alarms. These requirements affect most existing CO₂ systems in the power generation industry. The 2008 edition of NFPA 12 was partially revised to add language concerning occupiable vs. unoccupiable spaces.

Safety Signs

While most CO₂ systems come with some type of warning sign, the signs need to be upgraded in accordance with the 2008 NFPA 12 edition to meet the new (2002) revision of American National Standards Institute (ANSI) Z535 format—the only format now permissible. The only time signage can differ from ANSI Z535 format is when a formal signage training program exists. This means that all personnel with access to the protected space must either be trained or accompanied by personnel trained on the signage program. Because this exception can be cumbersome, most facilities find it easier to simply change to or install the ANSI Z535 signs. These signs follow a three-panel pictogram format (Figure 1). Warning signs are required in every protected space; at every entrance to protected spaces; in spaces near the protected spaces where it is determined that CO₂ could migrate, creating a hazard to personnel; and at each entrance to CO₂ storage rooms and where CO₂ can migrate or collect in the event of a discharge from a storage container’s safety device.

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The sign’s required text differs according to its location (for example, within the protected space as opposed to at the entrance to a protected space as opposed to outside the entrance to CO₂ storage rooms) and whether or not the CO₂ is odorized. There are, therefore, six different sign options, although typically only two or three will apply for a CO₂ system at a power plant.

Lockout Valve

Manual lockout valves were provided on many CO₂ systems in the past and became a requirement for all systems beginning with the 2005 edition of NFPA 12. The only exception is where dimensional constraints prevent personnel from entering the protected space. Even then, a lockout valve is required if CO₂ could migrate and create a personnel hazard. Essentially, the lockout valve requirement applies to every CO₂ system typically found in a power plant.

Because all components in a fire protection system are required to be listed for fire protection service, the valve must have a visual indication of its position and a provision that allows it to be locked in the closed position. In addition, the valve must be supervised. This means that the valve must have a normally closed electromechanical switch. This switch should be electrically connected to the CO₂ system’s control panel so that when the valve is in the closed position, a supervisory signal is initiated, and an open circuit, ground fault or loss of integrity results in a trouble signal, as required by NFPA 72, National Fire Alarm Code. A service disconnect switch is not a permissible substitute for a lockout valve.

NFPA 12 permits the “authority having jurisdiction” (federal, state or local fire prevention bureau or insurance carrier) to waive the valve supervision requirement. A typical example would be a situation in which an older existing system is provided with a lockout valve that does not include electronic supervision. In such a case, the valve should be equipped with a seal for when it is in the open position, along with a procedure to restore the seal after the valve is closed. A weekly documented visual inspection of the valve should also be required.

These CO2 upright canisters are safely and securely stored in stands and equipped with proper valves and alarms.Click here to enlarge image

The lockout valve is typically located on the discharge side of the CO₂ supply and the protected space where it is easily accessible. Power plant personnel should consult with their CO₂ system’s manufacturer or an authorized representative regarding which lockout valve is recommended and how to connect its supervising hardware to an existing control panel.

Predischarge Alarm and Time Delay

While many existing CO₂ system designs for gas turbine enclosures are already provided with time delays, NFPA 12 permits the omission of the time delays for unoccupiable areas “where the provision of a time delay would result in unacceptable risk to personnel or unacceptable damage to critical pieces of equipment.” Gas turbines meet this definition. While NFPA 12 does not specifically mention generator enclosures, generators such as those at larger hydroelectric generating stations may also meet the definition for omission of time delays. In all cases where time delays are omitted, it is critical that a formal procedure be in place that requires lockout/tagout of the system anytime the protected space is entered.

If the time delay is provided, no specific time requirement exists, but typically 30 seconds is considered reasonable for most machinery enclosures. The time delay usually consists of a mechanical accumulator device located on the discharge piping near the CO₂ supply. It must be listed for its intended use.

Almost all CO₂ systems are hydraulically calculated to ensure that the CO₂ supply, the piping and the nozzles are designed to require the minimum amount of CO₂ concentration within the protected space.

One additional caution associated with retrofitting an existing CO₂ system with a lockout valve, pneumatic time delay and/or pneumatic discharge alarms is that the addition of such hardware results in additional equivalent pipe length to the system. Thus, NFPA 12 requires that the system flow calculations be verified and “be in accordance with” the current edition of NFPA 12. Unless the original designer has (and is willing to revise) the hydraulic calculations, it could be difficult to comply with this requirement. The addition of a single lockout valve should not significantly affect the flow characteristics of a system; however, the addition of pneumatic delays and alarms may, especially if the designer did not leave a generous safety margin. The verification requirement could also be complied with “reverse engineering” by performing an actual discharge of the system while simultaneously measuring the CO₂ concentration within the protected space. That is the best available method of not only “proving” the system’s design and testing the new hardware’s functionality, but also of knowing the system will, indeed, extinguish the fire.

Author: Dominique Dieken is a Senior Fire Protection Engineer with Starr Technical Risks Agency Inc., a member of the C. V. Starr & Co. Inc. group of companies. Starr Tech is an insurance agency serving the power generation, petrochemical, chemical, energy, oil and gas industries and other complex occupancies with property insurance coverages and technical loss control support.

Divers Help Keep Plants Up and Running

By Ken DeCoursey, Siemens Water Technologies

When Joe Borho and Jim Couser go to work, they know it will be wet and possibly very cold and muddy. It is usually also quite dangerous, requiring that they be totally focused on the job at hand.

Borho and Couser work for Siemens Water Technologies as dive service crew supervisors for the intake service line. Their job is to make sure the company’s underwater equipment is maintained and repaired so that customers experience as little downtime as possible. These divers specialize in intake, or traveling water screens, designed to remove trash and large pieces of debris (typically greater than one-quarter inch) from power plant intakes.

The traveling water screens are vertical conveyor machines partially submerged in water. Because the screens are installed in challenging environments, they can experience mechanical wear, corrosion and damage.

A Dive Crew Is Born

The intake dive crew was formed in May 2005. Based in Madison, Ind., the crew found they were almost immediately in demand. In fact, demand was so high, the company added a second dive crew in March 2006, one-and-a-half years ahead of schedule. Before the crew was formed, Siemens’ underwater equipment maintenance was outsourced to external diving crews, but this proved to be unsatisfactory.

The Siemens crews operate in teams of three, with one or two members heading underwater while a “tender,” who is connected to the divers via cable, remains on the surface and communicates with his underwater colleagues with an intercom. With their diving suits and apparatus, the divers look like they might have walked straight from the set of Twenty Thousand Leagues Under the Sea, only with much more high-tech equipment. Images captured by high-resolution cameras on the divers’ helmets, for example, often provide the tender with better visibility than the divers have. This allows the tender to provide the divers with additional information about their environment.

“Sometimes the water is so muddy you can’t see your hand in front of your face, even with strong flashlights,” said Couser, who has been with Siemens since 2005. “You have to know your equipment really well to perform in such extreme conditions.”

Being a certified commercial diver requires a special kind of mental and physical preparedness. Borho and Couser’s crews sometimes climb into murky lakes, rivers or even narrow wells that most people wouldn’t even dream of dipping their toes into.

To be accepted as a trainee, an applicant must pass physical examinations to make sure he/she can cope with the stress and strains of the job. Qualified divers undergo training for nine months before they can become a certified commercial diver. An engineering background is also necessary so the diver can maintain and repair the equipment. The divers must also be mentally prepared to go as far as 140 feet down into extremely unwelcoming water to accomplish some complicated engineering feats.

While most of the work is cold and unpleasant, sometimes the crews get to dive in near-perfect conditions. Couser recalled one job in Indonesia, a diver’s paradise.

“Some people pay a lot of money to go diving there, yet we got to go diving and get paid for it, which was really neat,” he said.

Teamwork and trust are critical ingredients for the divers’ success. They know that they can trust each other with their lives when they head down into the murky depths.

“I became a diver because I have always loved the water and I love to travel. But even more important is the sense of family with the other divers,” said Borho. “We spend so much time together that we can anticipate each other’s thoughts and actions.”

Nuclear Power Plant Challenges

The intake dive service crews are often required to work on highly secure jobs such as nuclear power plants. When a nuclear power plant in Northeastern Ohio purchased new replacement baskets, main carrier chain and lower foot shaft assembly units, divers were needed to remove the existing lower foot shaft units of the traveling water screens and properly install the new units.

Stringent security and background checks must be run on all contract employees by an independent security agency before the plant can grant permission to enter and begin work at a nuclear facility. The highest safety training certification levels for OSHA and all other related categories are also required. Siemens’ intake crews maintain these training levels as part of their yearly certification for employment.

Once the employees were cleared for work, the dive team began rebuilding two of the plant’s traveling water screens. After the divers completed the work, they made additional dives to make sure the chain was properly seated into the foot wheels to prevent premature wear and ensure long equipment life.

During the project, the dive crew encountered some unique challenges. The underwater work to remove and reinstall the lower foot shaft units on a traveling water screen is typically performed during a factory rebuild. In such instances, the entire screen is pulled and shipped to a rebuild facility for rehabilitation. It is not unheard of, however, to do this work with the screen still installed in the well and the lower unit under water. Because these screens were nuclear safety-related back-up screens, it was important that personnel closely adhere to and not deviate from the work schedule. Therefore, pulling the screen from the well and shipping it to a rebuild facility for a six- to eight-week rehabilitation operation was not an option.

Because the screens were in a secure concrete building with small access doors that prevented the equipment from being easily removed, the existing old main carrier chain and basket assemblies had to be lifted by boom crane through a roof hatch. A concrete plug had to be removed from the roof hatch opening to allow the old equipment to be lifted out and the new replacement parts to be lowered in.

Another hurdle occurred when the boom crane, which was being used to lift the equipment from the staging area over the building and down through the roof hatch, broke down. This was a critical project setback, slowing the job for several days while a new part was ordered and delivered. Despite these obstacles, the crew adapted by revising their planned schedule. They worked through the delays and still finished the job within the allotted plant outage.

Once the traveling water screen rebuilds were completed, both units were tested to make sure they were within OEM specifications. The dive crew then certified that the screens were in “as-new” condition and ready for operation.

Author: Ken DeCoursey is service manager for intake products at Siemens Water Technologies.