Case study # 2: “Don't believe those readings.”
The following series of incidents occurred at a two-year-old 3 x 1 combined-cycle merchant plant in a western state. One day, the plant's steam turbine tripped as HRSG #2 was being started up. The plant recovered from the trip and HRSG #2 resumed starting up. Wet chemistry tests (performed in the plant's lab on schedule, shortly after recovery from the trip) indicated a low pH (about 7.5) in the HP drums of HRSGs #1 and #3.
Like many plants, this one assigns water chemistry duties to junior operators. The junior operator in the chemistry lab, who had never seen drum pH this low, didn't believe his eyes. He did what any good junior operator would do—he called a senior operator to ask about the low readings.
Because HRSG #2 was in start-up mode, it took the senior operator over an hour to get to the lab. He and the junior operator checked the drum pH readings again, and they were even lower than before, at about 5.5.
Seeing isn't believing. Both operators were certain that the bench-top pH analyzer producing the readings had failed because they assumed that the plant's on-line pH analyzers weren't working. But after they calibrated the bench-top analyzer, it generated an even-lower pH reading—4.5. Still sure that the lab analyzer was the culprit, the operators next replaced its probe and calibrated it again. Still no luck: The instrument continued to indicate a very low drum pH. Frustrated, the operators looked around the lab for another pH analyzer to use but couldn't find one.
By this point, the bench analyzer indicated that the drum pH readings of HRSGs #1 and #3 had stabilized at around 4.0, but the operators remained certain that these were “bad” readings. An additional factor added to their confusion: The same analyzer appeared to produce “good” readings from other grab samples. The operators next tested the pH of the plant's feedwater, condensate, and demin water, and those results were well within the normal range of values. By then, HRSG #2 had completed start-up and was operating at low load.
Finally, both operators contacted the control room supervisor to ask if another bench-top pH analyzer was available anywhere. Two hours after he relayed the request to the plant's chemist and operations supervisor and got “no” for an answer, the control room supervisor shut down the plant.
All told, the two operators wasted about six hours believing that they needed another bench-top pH analyzer. In fact, the one they were using had been working properly the entire time. It took another two hours to begin shutting down the plant, a process that required the plant's chemist, operations supervisor, and manager to concur that the low pH event was, in fact, real. A subsequent examination of on-line analyzer data showed that the pH in the drums of HRSGs #1 and #3 had indeed fallen quickly to around 4.0 and remained there for the duration of the incident.
Wasting away. Though this plant's forced outage could not have been prevented, the resulting HRSG corrosion could have been. One tube section from the HP drum of HRSG #1 was removed six months after the incident and tested. A deposit weight density (DWD) analysis indicated 16 grams/ft2 of buildup after only one year of commercial service. Such a level is more consistent with seven to 10 years of operation. As in the first case study, significant iron deposition occurred as a result of this event, so the HRSG will require chemical cleaning sooner rather than later. The full extent of the damage is still unknown. Hydrogen damage also certainly took place, but the plant has not yet seen HRSG tube failures as a consequence.
Low-pH events can cause several problems, including corrosion fatigue, hydrogen damage, and deposition of corrosion products. We can't say that a tube failure initiated by low pH will occur within a month, a year, or even within 10 years. We can only conclude that one or more tubes will fail sooner than they would have had the event not occurred. The adverse impact of the event is roughly proportional to its duration. Based on data recorded by the one working on-line pH analyzer at this plant, the plant operated with low pH in the drums of two of its three HRSGs for six to eight hours.
The low-pH event was initiated when material in the HRSGs' condensers came loose and struck tubes, damaging them and causing them to leak. Among the factors that made the leak(s) more difficult to detect were the lack of reliable on-line pH indication (a sample panel maintenance and design issue), the absence of specific or cation conductivity measurements upstream of chemical feeds (a sample panel design issue), and reliance on wet tests alone to identify water chemistry problems.
Wrong number. Like the plant described in the first case study, this one had on-line pH analyzers installed on all three of its HRSG drums. But in this case, only one analyzer was working, and operators' lack of confidence in the instruments led them to believe that wet chemistry analysis was the only way to detect pH excursions. Plant management knew about the analyzers' reliability problem but had failed to address it after one year of commercial operation.
Although the plant also was equipped with an on-line specific conductivity analyzer, its poor placement made it useless for accurate leak detection: The flow sampled by the analyzer is downstream of the point where boiler feedwater chemicals (a passivator and an amine) are added. Both chemicals increase condensate conductivity in direct proportion to the amount added. Accordingly, changes in condensate flow rate will cause a change in condensate conductivity even if the chemical feed rate remains constant. Because of this inherent variability, small condenser leaks may be masked by the noise of variable condensate conductivity.
As this example proves, even small leaks can quickly cause a low pH upset in HP HRSG drums. Plant personnel were confused because condensate conductivity appeared to be normal.
A cation conductivity analyzer would have been immune to the interference caused by the chemical feed and would have accelerated detection of condensate contamination. It should go without saying that the specific conductivity analyzer should have been installed where it would receive samples of condensate prior to any chemical addition. Had that been the case, the variability in condensate conductivity caused by the chemical feed would not have been a problem. With this variability removed, it becomes easier to detect small increases in conductivity that are indicative of an incipient condenser tube leak.
Once again, poor plant O&M practices meant key on-line analyzers were unavailable during start-up, and readings from the one operating analyzer were distrusted. Also, senior techs seemed to be instilling poor O&M habits in younger techs, which made the problem an institutional one. Apparently, the plant manager didn't believe in investing in the immediate repair of these instruments, thereby reinforcing the mistrust. What this plant has is a leadership problem, not an analyzer problem.
Email
Comments
Print
Reuse
