By Jim Montague, Executive Editor
If knowledge is power, then detailed and sophisticated information that arrives early enough to prevent problems and even disasters is super-duper power.
For instance, Entergy Corp.'s (www.entergy.com) primary goal for more than 60 years has been to produce electricity safely. Located in Woodlands, Tex., north of Houston, Entergy provides electricity though its Fossil Energy divisional headquarters to 2.8 million customers in Arkansas, Michigan, Louisiana and eight counties in southeast Texas. It generates power using nuclear, coal, oil, natural gas, hydroelectric and wind sources.
"Process safety is our number one priority, and so we focus on it from our CEO on down. Most of our plants are OSHA Star program facilities," says Gary Barnes, superintendent of Entergy's seven-year-old Performance Monitoring and Diagnostics Center (PMDC). "We say that no job is so important that it can't be done safety, and we practice what we preach by emphasizing safety in our training, goals and meetings.”
To aid this safety effort, PMDC monitors Entergy's fossil units for subtle indications developing in its equipment or other operational issues, so it can quickly identify problems when they're smaller, easier to address, less costly, cause little or no equipment outages, and limit the potential for any catastrophic failures. The center uses three main types of software to help Entergy find problems and improve performance, including OSIsoft's PI data historian on all key units to capture data and show how well they're functioning, and General Physics' ETApro to perform thermal calculations for turbine effectiveness, heat balances around heat exchangers, and other tasks that used to be done manually.
In addition, to give it advanced pattern recognition capabilities, PMDC began beta testing SmartSignal's (www.smartsignal.com) EPI*Center software in 2006, and now uses it on 36 units at approximately 16 plants, which represent about 95% of Entergy's total fossil generating capacity. "PMDC monitors our fossil units, and it's been acknowledged as the leading remote diagnostics center in our industry," says Barnes. "In fact, though Entergy's nuclear division is separate from our fossil division, it's implementing PI and SmartSignal's software in our nuclear fleet, and we recommended it to them.”
Jim Gagnard, SmartSignal's president and CEO, adds that, "We originally decided to focus EPI*Center on the process industries because they have continuous manufacturing applications, and so we can use individual historical data to create personalized models for each piece of equipment. For the 300-400 plants that use our technology, it's the data that defines the model, not the software. As a result, we can help users see subtle changes in their unique processes ahead of time, and so some problems never become big ones. In fact, three or four of our customers already have negotiated lower insurance rates by having this early detection of problems in their processes. We have a real-time version of the usual risk-assessment process and can report every five minutes on what's going on that might be abnormal, which make problems a lot easier to fix." (Figure 1)
Little Vibration Reveals Big Crack
For example, shortly after installing EPI*Center on its 411-megawatt Waterford Unit 2 gas/oil generator, Entergy's engineers and operators got an alert from the software that vibration levels on the exciter end of the unit's turbine were slightly elevated, and starting to steadily increase (Figure 2). Barnes says this unit usually runs at 3,600 rpm, and that an ideal vibration level is 1 mil (a unit of vibration equivalent to 0.001 of an inch), though usually operators are satisfied with 2 mils.
"The first notification at 12:30 p.m. was that the unit was running at 3-3.5 mils, which is elevated, but not a lot, because there's not usually a problem until you reach 5-7 mils," explains Barnes. "So, we weren't too concerned, and notified the plant, and continued to watch the situation. However, the vibration level continued to increase until at 5:30 p.m. it reached 6-7 mils, and the decision was made to shut the unit down.
"Because of the early notification from EPI*Center, we were able to learn about the elevated vibrations very early, watch it increase, and then jointly consult with the plant and dispatch center about taking the unit offline. We were able to proceed very calmly and shutdown safely. If we hadn't had this information from the PMDC, then the plant wouldn't have known there was a problem until the vibration level reached 6-7 mils and an alarm went off. As a result, we would have had a lot more critical situation, maybe not enough time to shutdown safely, and possibly have had a catastrophic failure.”
After the safe shutdown, Barnes adds that Entergy's engineers diagnosed and disassembled the unit, and found a 2.5-inch deep crack running 180° around the end of the rotator shaft (Figure 3). Analysis revealed that the new crack was due to stress fatigue from a previous arc gouge that had been repaired several years earlier.
"The consensus of our rotating equipment and generator experts was that, if we hadn't taken this unit offline, then the shaft would have cracked through, and we would have had a catastrophic failure. The 3,600 rpm section would have hit the stationary area, which would have completely wreaked the generator, done serious damage to the turbine, and probably caused hydrogen coolant and oil fires. In other over-speed events, large pieces of metal also have penetrated their facility's shell, and flown up to a half mile away. An incident like this would have caused $40-50 million or more in damage, and this unit would have been down for months, if not years. Because of our safe shutdown, the repair cost only $5 million, and the unit was only down six weeks."
Seeking, Showing Small, Significant Signs
Tim Holtan, manager of SmartSignal's Availability and Performance Center in Lisle, Ill., reports that, "The initial value proposition of early warning in process applications is revenue improvement, but we're seeing signs that SmartSignal can mitigate a lot of accidents, too."
For example, Holtan reports that SmartSignal is used at another client's major refinery to detect very early signs of possible leaks into the seal oil system on a centrifugal compressor that circulates hydrogen through the desulfurization unit. These leaks occur over time because the seals are in contact with and eventually degraded by H2S-rich gas in the unit. The seal oil is circulated to a reservoir that is open to atmosphere, and in the past that reservoir could be vented to flare when an H2S alarm sounded. However, EPI*Center can detect subtle but significant shifts in temperature, indicating that a leak may be starting, and then quickly call for the oil to be changed, so the process doesn't have to go to flare so often.
To process applications' data and detect changes, EPI*Center begins with a personalized, empirical model of each piece of equipment in the process where it's being implemented. These data may include pressure ratios, temperature ratios, power inputs and other typical operating norms. Next, these models are compared to actual operating data, which reveal the small but significant shifts that don't turn up with traditional performance methods.
"Another refiner using EPI*Center found a decrease in efficiency in their diethanolamine system, which picks up H2S in the process unit and delivers H2S to the filter unit," says Holtan. "Only four measures are collected—suction flow, suction temperature, motor current and discharge pressure—but our model was able to pick up 25 gpm less suction flow in one pump, even though it was using the same power.
"So, the refiner's staff shut the pump down, investigated, and found the cause was significant corrosion. If that line had broken, there could have been an H2S leak and exposure to staff and the atmosphere. This pump's loss of efficiency wouldn't have been noticed otherwise because it was no one's job to check what amps it was pulling. This is how we get to the needle in the haystack. There are different levels of attention paid to equipment in facilities, and so EPI*Center can monitor 400 pieces of equipment, but maybe only send alerts on the two or three that need it.”
Taking Control of Downtime
Because most U.S. power generating utilities are past their designed lives, Barnes reports this makes it even more important for these older and often smaller units to have the right sensors and instruments in place. "There's always some risk in running and maintaining any power generation system, and so it's also part of Entergy's policy to have pattern-recognition capabilities on all our units. EPI*Center mitigates our failure rate, and improves our cost of doing business. In fact, we had zero recordable accidents in 2008 for our fossil operations.”
Likewise, Barnes adds that having PI data and past failure data makes it easier to do failure modes and effect analyses, and then build in improved safety features to make future machines, applications or systems less prone to failure. "For us, the real, day-to-day benefit of detecting problems early is simply that we can have time and ability to make informed decisions," explains Barnes. "Consequently, instead of simply running a process until we have to shut down a unit right away, now we can know enough about a problem to know how long we can continue to safely run its process—perhaps for additional days or weeks until we can fix it as part of a planned outage. This lets us decide when to shutdown and make repairs, and makes it easier to keep other processes running. In general, unplanned outages are more costly than planned ones, and so it's especially useful that we can now turn unplanned outages into planned ones. For example, we buy a lot of our fuel on the spot market, and so if we know that we're going to have a shutdown soon, then we can buy fuel ahead of time and not have to buy it when it's more costly.”
These and other benefits are how PMDC helps save Entergy millions of dollars per year in avoided repair costs, according to Barnes, who adds these savings quickly grow to tens of millions of dollars when the costs of saved replacement power and avoided repair costs are added. "We used to rely on traditional plant alarms and staffers making the rounds, and they're very competent, but they're also busy with day-to-day operations. They don't have the time to pull up weeks of data, and look for potentially beneficial trends," explains Barnes. "This is why it's good that our analysis technology and procedures have evolved from having a failure, looking at strip charts, and trying to figure out what happened with simple root-cause analysis to, now, gathering more subtle indicators, proactively figuring when something will need to be fixed in the near future, doing more minor repairs, and avoiding catastrophic failures. Not only is there less risk to staff and facilities by doing proactive repairs, but our whole process is now inherently safer. Everyone should implement this kind of monitoring to identify the anomalies in their mountains of data, train their engineers and operators what to look for, and use this new data to make better judgment calls."