Most preventive and predictive maintenance practices for steam turbines focus on keeping lube oil pure, vibration levels under control, and all inlet and non-return valves ready to stroke at a moment's notice. Internal leaks of steam cannot be identified easily or measured directly, but they can be detected by performance engineers with calibrated eyeballs and instruments.
Southern Company's team of plant maintenance, central office technical/maintenance, and performance testing/steam path audit personnel has an excellent track record for spotting steam path problems. By closely monitoring turbine performance trends, the team can catch, diagnose, and resolve many problems early—often during the next unit outage.
How are internal leaks identified, and which parts of a steam turbine are most prone to leakage? This two-part series answers those questions, beginning with an overview of the symptoms and causes of the most serious and unmanageable leaks—of excessive steam from a turbine's high-pressure (HP) to intermediate-pressure (IP) section. Part I concludes with three case studies of GE turbines (Figure 1) that illustrate how the concepts apply in practice to these specific machines. In next month's POWER, we'll scrutinize Westinghouse (Figure 2) and Allis-Chalmers turbines.
1. Smooth operator. Southern Company's Plant Branch Unit 2 is a 320-MW GE steam turbine. The unit began commercial operation in 1967. Courtesy: Southern Company Generation
2. Making power. Unit 4 at Southern Company's Plant Branch is a 500-MW Westinghouse steam turbine that began operation in 1969. Courtesy: Southern Company Generation
Say aah
The symptoms experienced by a turbine suspected of internal leakage must be inferred from tests and indirect observations. Medical doctors diagnose patients that way every day. But whereas humans can verbalize their complaints, steam turbines can only speak in the language of lost performance and efficiency. It's a lot easier to detect blood bypassing a cardiac valve than to diagnose HP to IP seal leakage.
The diagnosis begins with the understanding that increased HP to IP leakage can have several causes. Seals damaged or weakened by misalignment, poor start-ups, or multiple temperature excursions will increase leakage, for example. For utility-grade turbines, age is definitely a factor, especially with HP inner shell distortion or loose/overstretched bolting causing leakage at the horizontal joint. A water induction incident will cause seal rubs and HP inner shell distortion.
The typical time between turbine overhauls has increased from four years in the past to as much as eight to10 years today. Lack of thoroughness and poor quality of turbine inspections also may be an issue. In particular, it's important to insist that the inspection include the main steam inlet expansion rings in the turbine's lower inner shell.
Losing load
A turbine's output and reliability can be affected by high internal leakage. An enlarging internal leak will initially increase the unit's capacity in a manner similar to reheat spray. The cycle flow restriction in the first few stages of the HP turbine will be bypassed. Eventually, the effects of reduced boiler reheater flow will cause overheating of the reheater tubes and more tube leaks. Load may have to be curtailed to avoid overheating the reheater.
Other problems could occur, too. On the mechanical side, loose nuts on the HP inner shell could "liberate" their washers. If they enter the IP turbine inlet, they could cause severe damage to buckets. In some turbine designs, the washers could just as easily enter the LP turbine.
Nuts and bolts aside, the thrust balance of the HP-IP turbine also can be affected by a change in internal flow distribution. It may not be possible to achieve full load following such a change if it triggers a thrust bearing alarm.
Other clues that you may have an excessive internal leakage problem include those that follow.
Trouble controlling reheat temperature. If fuel and boiler conditions haven't changed but reheat spray flow has been increasing with time, this could be a sign that internal leakage has increased and is bypassing the reheater. The situation could evolve into one where the flow capacity of the reheat spray is "topped out." At this point, the only alternatives for control would be to reduce load or to lower superheat temperature.
Apparent (measured) IP efficiency changes. Very high (>94%) values of measured IP efficiency (from the hot reheat to the LP crossover) are good signs for all GE units. But for Westinghouse turbines, the same values are indicative of high leakage to the IP turbine inlet, and extremely low values are symptomatic of high leakage to the LP crossover (bypassing most of, or the entire, IP turbine).
Turbine pressure changes at valves wide open. Decreasing first-stage pressure, coupled with increasing downstream pressures, could indicate flow bypassing the HP turbine. (The effects of reheat spray should be accounted for on the downstream pressures.) The main steam flow calculated from the first-stage pressure curve will decrease, whereas the main steam flow determined by the feedwater flow (plus superheat spray flow, if applicable) will increase. Some older units with main steam and hot reheat flow nozzles will show a trend of decreasing hot reheat flow (after accounting for reheat spray differences, and assuming the performance of the cold reheat HP feedwater heater has not changed).
Turbine thrust bearing changes. Although the phenomenon has been rarely reported at Southern Company Generation (SCG) plants, at several other plants the position of a steam turbine thrust bearing has been changed by abnormal flow distribution in the HP and IP sections of opposed-flow turbines (there was less steam flow in the HP turbine than in the IP turbine).
Turbine shell temperature differences. Verified differences of over 100 degrees F between the upper and lower shell metal and steam temperatures could be a sign that an internal leak is cooling an upper or lower section.
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