By Douglas J. Smith IEng, Senior Editor
When the first steam boilers were introduced in the 18th century, in the U.S. and Europe, safety was a big issue. During a 12-year period, 1879 through 1891, there were 2,159 reported steam boiler explosions in the U.S. These explosions killed 3,123 people and seriously injured 4,352.
The earlier steam boilers were manually operated, and the only safety requirements were generally the installation of water level gauges, low water alarms and safety valves. However, as boilers became larger and steam pressures increased, the operation changed from manual to the current automatic control. Today’s automatic boiler control systems include burner management systems (BMS) with flame scanners and igniters.
According to William A. Wood, assistant vice president, Hartford Steam Boiler, electric utilities are looking at ways to prevent catastrophic failures of boilers. In many instances, when inspectors have examined how accidents can be prevented, the answer is improved training. Since the late 1990s, the power generation industry has seen a revival in training for maintenance and operating staff. During training, the utility management emphasizes the importance of well researched and detailed written operating procedures.
2002 Incident Report
According to the National Board of Boiler and Pressure Vessel Inspectors, there was a significant drop in deaths from power plant boilers in 2002 compared to 2001. The number dropped from 12 in 2001 to 5 in 2002. The 2002 Incident Report also noted a significant drop in injuries, from 2,219 in 2001 to 1,663 in 2002, a 25 percent reduction.
The National Board states that the leading cause of accidents on power boilers and heating boilers, Table 1, was low water conditions. However, the leading cause of injuries and deaths was operator error and poor maintenance.
With a commitment to improving plant safety, some power plants are devoting one day a quarter to training. In conjunction with the formal training sessions, the plant’s operating procedures are regularly scrutinized and upgraded. Power plant managers are developing more detailed procedures with step-by-step checklists for startup and shutdown of the plants. In some instances power plants are making the procedures for startup and shutdown available on the plant’s distributed control system screens, which are located in the control room.
Recent Boiler Explosion
A boiler explosion at a Michigan power plant in 1999 killed six people and seriously injured 14. The explosion resulted from natural gas buildup in the furnace. A secondary explosion resulted from accumulated coal dust. The boiler had the capability to fire natural gas, coal or blast furnace gas.
Following the explosion, Michigan’s Occupational Safety and Health Administration (MIOSHA) conducted an investigation of the accident. Based on interviews, observations and reviewing relevant documentation, a chronology of events leading up to the accident was developed. Using this information MIOSHA concluded that the operators were in the process of taking the boiler off-line for its annual licensing inspection.
Anytime the Michigan unit was removed from service the plant operators were required to close 30 natural gas valves and shut down all pilots, ignitors and burners located on two floors. Maintenance personnel had the responsibility to disconnect or cap six of the 30 natural gas lines and valves. During the process of shutting down the unit, the Michigan plant’s operators were responsible for monitoring the induced draft, forced draft and the primary air fans. They also had to monitor the steam pressure temperature and water levels within the boiler.
Prior to the explosion, the blast furnace gas and the pulverized coal systems had been removed from service and the maintenance personnel were in the process of blanking two main 10-inch natural gas lines. Unfortunately, only one of the 10-inch natural gas valves had been closed when the explosion occurred. As a result, natural gas was trapped between the shutoff valves and the burner control valves.
Unfortunately, this required the operators to reopen the burner fuel control valve and vent the natural gas into the furnace. When this occurred it allowed natural gas, at line pressure, to flow into the furnace. According to MIOSHA, although the ignition source for the explosion was not determined, the probable cause of ignition for the natural gas was hot ash in the super-heater boiler tubes.
The investigation of the Michigan boiler accident determined that the plant lacked adequate combustion controls from inoperative flame monitoring, burner safety devices and ignitors. As a consequence, the pilots had to be manually lit using an alcohol soaked glove. In addition, the plant’s housekeeping was found to be inadequate as it allowed coal dust to accumulate throughout the power plant.
Adding to the burner management system’s problems, the plant’s system for identifying the isolation valves, butterfly valves, and pilot and ignitor valves was inadequate. The plant had also failed to establish proper written procedures for startup and shutdown of the boilers and had failed to institute correct lockout procedures.
A major failing of the plant, according to MIOSHA, was the plant’s failure to provide adequate training, procedures and certification proficiency for the boiler operators. Safety training and reporting was not centralized. As a result, insurance audits and engineering studies showed that recommended combustion safety controls were only forwarded to the operational staff and not the maintenance and safety departments for their review and comments.
The investigators concluded that the accident could have been prevented if industry standards—NFPA 8502, NFPA 8503, ASME BPVC Section VII and ASME B31.1—had been followed. An earlier version of NFPA 8502, covering the prevention of furnace explosions in natural gas multiple burner furnaces, had previously identified fuel leakage into an idle furnace and its ignition, as one of the most explosive conditions that could occur.
To prevent explosions in boilers, MIOSHA recommends that maintenance of burner management and safety systems be given priority, especially in older plants where the equipment is reaching the end of its useful life. MIOSHA stated in its report that, because coal dust is a major hazard, good housekeeping is essential in coal-fired power plants.
Besides making sure that all safety systems are operating correctly, and housekeeping is being conducted on a regular basis, MIOSHA states that it is important to have clear lines of communications between all plant personnel including safety departments, maintenance, operations and management. It is essential to have written operating procedures, job training, checklists and training records for all power plant operations, MIOSHA states.
At all of TXU Energy’s power plants, the safe operation of the boilers is a high priority. Each of their plants has standard written procedures and checklists that the operators use when starting and shutting down the units. As the energy company’s power plant personnel have become multi-skilled it has become more important that TXU Energy’s plant staff have the knowledge and training to safely operate the plant’s boiler equipment.
In recent years, TXU Energy has upgraded many of their burner management systems (BMS) to digital controls. On a regular basis, the BMS and its associated burner equipment are inspected and tested. These inspections will often coincide with required maintenance being carried out on other systems. The tests insure that the ignitors, scanners and purging cycles are operating correctly and safely. Prior to replacing the older BMS, TXU Energy had experienced delays in starting up some of the units while they would troubleshoot problems. However, new digital BMS have reduced these problems.
All of TXU Energy’s power plants conduct regularly scheduled safety meetings, where the plant’s personnel and supervision discuss ways for improving operational safety. Whenever equipment is modified or upgraded, new procedures or checklists are written and any changes that are required to the plant’s operation are discussed. Prior to equipment commissioning and start-up, operators are trained on the new operating procedures.
TXU Energy has several plants that were originally designed to be fueled with Texas lignite in a mine mouth operation. They now supplement their solid fuel consumption with Powder River Basin (PRB) coal. This change in fuel mix has prompted TXU Energy to re-evaluate suppression and collection systems to ensure increasing amounts of PRB will not have an adverse affect on the performance of these systems. Because of the differences between lignite and PRB coals, TXU Energy is working to ensure that existing fire and explosion protective systems and designs maintain their capabilities.
Another mid-west utility that has switched from high sulfur coal-fired to low sulfur PRB coal is We Energies, Wisconsin. More than 70 percent of We Energies power plants are coal-fired. In plants where low-NOx burners have been installed they have also installed new ignitors in-line with the coal nozzles. However, when the modified boilers were put back into service, the plant experienced problems with the flame scanners monitoring the burners.
When the new flame scanners were first put into operation the scanners had difficulty in differentiating whether the coal or the natural gas was burning. However, the problem was rectified after the flame scanners were realigned. The flame scanners are now able to detect two distinct flames: the coal flame and the natural gas flame.
Preventing Pulverizer/Mill Puffs
In addition to boiler safety issues, the safe operation of fuel handling supply systems is another major concern for electric utilities. Coal handling and processing equipment are particularly susceptible to fires and explosions.
Boiler furnace wall failure. Photograph courtesy of Aptech Engineering Services, Inc.
Although pulverizer fires and explosions are major problems for coal-fired power plants, it is only recently that power plants have looked at installing fire detection and fire prevention systems on the equipment. In the middle of the 1990s, Duke Power installed mill fire detection systems on the pulverizers at their Cliffside station’s Unit 5.
After looking at various options, Duke Energy decided to install Aptech’s mill fire detection system (MFDS) on the six CE Raymond 863 pulverizers. The MFDS’s installed on Unit 5 instantly determine the presence of a flame or glowing materials.
Shortly after startup of the MFDS, the operators were alerted to a problem in one of the pulverizers. After investigating the problem, it was determined that a recently installed vane wheel assembly was rubbing which caused the coal to stick to the liner and smolder. A few weeks later, a locknut came off a grinding roll journal. This caused sparks from the rubbing action between the grinding roll and the nut as the bowl turned. The MFDS also picked up an under bowl fire which was a result of coal accumulation under the bowl near the pulverizer’s inlet hot air duct. After removing the pulverizer from service, the fire was extinguished with no damage to the pulverizer.
An alternative to installing diagnostic monitoring systems to prevent pulverizer fires and explosions is to install pulverizer inerting systems. Figure 2 shows a typical low-pressure CO2 coal pulverizer inerting and fire protection system.