Finding and fixing leakage within combined HP-IP steam turbines 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.

Quick reaction required

Excessive leakage entering the IP turbine reheat bowl can be (but is not always) marked by a noticeable increase in measured IP efficiency across the load range. Likewise, excessive leakage entering the LP crossover pipe will normally lower measured IP efficiency.

Determining the amount of internal leakage requires conducting a relatively inexpensive HP-IP enthalpy drop test with test-quality instruments. The main steam and hot reheat temperatures are varied to observe the change in measured IP efficiency. This is called the Booth-Kautzmann test (see box, p. 33, #1). SCG calls it the "temperature split test." A large (>1%) change in efficiency from one test to the next is a sure sign of high internal leakage. Ideally, these routine tests should be conducted at least once per year with either calibrated plant or test-quality instruments. Tests conducted with other kinds of instruments can produce inconclusive results. Remember to account for miscellaneous items, such as water legs, when making measurements of static pressure.

As part of its testing procedures, SCG tries to maintain at least a 30- to 40-degree F spread between temperatures, at stable conditions. It is very important to have at least three testing conditions—normal superheat/reheat, normal superheat/lower reheat, and low superheat/higher reheat—at the same load. For boilers that have trouble generating reheat steam that is hotter than main steam, another option is to use various amounts of reheat spray to achieve two conditions: low reheat and lower reheat.

The level of difficulty in achieving the temperature variance depends on the boiler’s design and fuel as well as the patience of the unit operator and test engineer. Variables and equipment that the operator can control include superheat spray, reheat spray, boiler O2, burner tilts, gas recirculation fan operation, selective sootblowing, top-firing pulverizers, and convection zone gas bypass dampers. Some units achieve the variance at full load, others only at lower load.

It’s a good idea (for sanity’s sake) to maintain the difference between the assumed level of leakage enthalpy and that of main steam enthalpy constant for each test calculation. For GE units, SCG usually assumes that the leakage is the average of the test main steam and cold reheat enthalpies. If main steam inlet snout rings are suspected of contributing to excessive internal leakage, it’s reasonable to assume that its enthalpy is identical to main steam inlet enthalpy.

For Westinghouse and Allis-Chalmers units, which have more variations in arrangement, the leakage enthalpy should be more carefully selected. Using the average of the main steam and cold reheat enthalpies has proved sufficient for calculating the leakage enthalpy’s effect on the LP crossover. For later Westinghouse units, which have bell seals that can leak to the crossover, SCG assumes the leakage is that of main steam if a bell seal is suspected to be the major culprit.

SCG engineers use a Microsoft Excel spreadsheet with a Steam Tables add-in to calculate and plot test results. Our simple method does not require any measured flows—only test pressures and temperatures. The three derived lines should intersect at approximately the same point (Figure 3). From our experience, it is relatively easy to achieve good intersection with a high leakage rate, due to the influence of the leakage enthalpy and flow. For a low leakage rate, the lines do not intersect as well, because the leakage has less effect on the apparent IP efficiency. If a high leakage rate is indicated, you should first look for clues, such as those you might find in a review of the last turbine outage report work and any recent operational excursions.

Issues specific to GE turbines

For a General Electric combined HP-IP steam turbine, the design (heat balance) leakage from the HP to IP turbine, through the N2 packing, is typically 2% of hot reheat flow. When the turbine is new, this is usually the only significant HP to IP leakage. But as it ages, components other than N2 packing can become contributors, including:

• Upper and lower main steam inlet snout rings. A clearance of 0 to 2 mils is standard for conventional rings, and gaps over 10 mils can produce large amounts of leakage (Figure 4).

• The N2 packing head’s horizontal joint, and how it fits into the inner shell (if separate) (Figure 5).

• The HP inner shell horizontal joint (if the shell distorts or the joint develops a loose bolt) (Figure 6).

• The turbine blowdown pipe’s snout/piston rings (the pipe is horizontal on smaller units and vertical on larger ones)

• The first-stage pressure-flanged probe, and how it fits in the lower inner cylinder.

4. First contact. Some main steam inlet snout rings for a 250-MW General Electric steam turbine. Note in the top photo the good contact between the inner ring and the snout pipes. The bottom photo shows the inner and outer snout ring stacks after removal. Courtesy: Southern Company Generation

5. Packing heat. A typical N2 packing seal, packing head, and horizontal joint for a 250-MW GE steam turbine. Courtesy: Southern Company Generation

6. Nuts to that. Loose stud nuts caused this leakage around the HP inner shell horizontal joint of a 125-MW GE steam turbine. Courtesy: Southern Company Generation

Any or all of these leakages, along with those through the N2 packing, flow to the IP turbine inlet (or reheat bowl). Increased leakage will cause a rise in the measured (or apparent) IP efficiency (from the hot reheat to the LP crossover). The increase is not due to a gain in blading efficiency but, rather, to lower-enthalpy HP turbine steam mixing with higher-enthalpy hot reheat steam. The heat rate penalty is caused by the leakage of steam around the HP turbine and boiler reheater.

Ruling out abnormalities

The Booth-Kautzmann test defines two methods for determining HP to IP leakage. The first method, for measuring total leakage requires the temperature split test. This method will determine the total HP to IP leakage and is the more important test to conduct. SCG abandoned the temperature split test in the early 1990s on GE turbines because we assumed any other abnormal HP to IP leakages were taken care of in turbine overhauls; we were wrong. We resumed this testing in 1996 after we could not resolve some performance issues; this proved to be a blessing, as we found many problems with excessive HP to IP leakage resulting from HP inner shell joint and snout ring leakages.

The second method, which determines only leakage through the N2 packing and any through the blowdown pipe snout rings, involves opening the turbine blowdown valve and measuring the change in apparent IP efficiency that results from diverting the N2 packing steam to the condenser. (Some GE units do not have this valve, and on others it is not large enough to pass all the N2 packing flow.)

If there are no other leakages to the IP turbine, this method will provide a true measure of the IP blade path efficiency. The value can be converted to units of leakage using Figure 3 in Booth’s paper (see box). As shown by numerous comparisons of the blowdown test to steam path audit clearance measurements, it is quite accurate at calculating N2 packing leakage.

If there is no significant difference between total leakage and N2 packing leakage, then there are no other abnormal internal leakages. A significant difference between the two numbers indicates the existence of an abnormal leak, most likely either in the HP inner shell horizontal joint or in the main steam snout rings.

Where and how to inspect

A visual inspection of the ring contact area on the HP inner shell pipe only indicates the condition of the inner main steam inlet snout rings. The condition of the alternating outer rings can only be assessed by unstacking the rings and carefully measuring the clearances. The outer rings may carry telltale signs of steam erosion of the shell, but the signs remain invisible unless the rings are unstacked.

GE turbines larger than 300 MW have three sets of snout rings. Leakage through the outer shell and inner shell rings of each set goes to the IP reheat bowl, where it contributes to overall HP to IP leakage and affects the apparent efficiency of the IP turbine. Because leakage through the nozzle box set rings bypasses the first stage, it would affect only the HP turbine. Although this leakage has a minor effect on efficiency, it could have a major impact on flow capacity.

For GE steam turbines built in the mid-1960s and later, there is a mid-span balance port flanged connection that can be used to inspect for loose HP inner shell nuts. The balance port may not be shown on the turbine cross-section diagram if it is not exactly top dead center. In any case, the turbine instruction book will contain a page describing the balance port access.

Use a borescope to check for loose nuts (Figure 7). One turbine vendor offers a high-temperature borescope service, so the procedure can be performed during short outages while the turbine is still hot. Using the balance port also allows inspection of the IP inlet stationary blading, which typically erodes after many years of service. Another inspection approach that may work on older units is to remove an intercept valve and use a long borescope.

7. Scope of work. This loose nut atop an HP inner shell washer was found with a borescope inserted into the mid-span balancing port of a 250-MW General Electric steam turbine. Courtesy: Southern Company Generation

If excessive leakage is detected, reducing it will require taking these steps:

• Replacing the N2 packing seals if they have excessive clearance or broken teeth. Proper alignment and a controlled start-up after the turbine outage are critical to maintaining the seal clearances.

• Replacing snout rings (for main steam and the N2 packing blowdown pipe) that have excessive clearance, taper, or erosion. The snout pipes themselves may be worn or eroded enough to require refurbishment (Figure 8).

• Weld build-up and machining the HP inner shell horizontal joint surface, including an evaluation of its studs and shell threads (Figure 9). Leakage can actually flow up through shell holes, eroding the studs. The stud nuts should be "sounded" with a hammer to determine if any are loose prior to disassembling the unit. One possible retrofit, which SCG

has used very successfully on one unit, is to switch to a through-bolt stud arrangement. Whatever the arrangement, it is very important to know both the stud material and the nut tightening specs.

8. Triple play. The main steam inlet snout pipes of a 320-MW GE steam turbine with three sets of snout rings. Courtesy: Southern Company Generation

9. Fixing the fix. Weld build-up on the HP inner shell joint of a 75-MW GE steam turbine required machining and the replacement of studs. Courtesy: Southern Company Generation

Outage inspections to correct an internal leakage problem may create the need for some unexpected IP turbine repair. On two occasions, a stud nut washer came loose from the HP inner shell nut, broke into pieces, and was propelled into the IP turbine, damaging its buckets and covers (Figures 10 and 11).

10. Nice catch. This broken stud nut washer from the HP inner shell of a 350-MW GE steam turbine was found lodged in the stationary blading of the IP section. Courtesy: Southern Company Generation

11. Nut on the loose. Here are the IP turbine buckets damaged by broken pieces of the stud nut washer. Courtesy: Southern Company Generation

After an outage to fix excessive HP to IP leakage, the turbine should be thoroughly tested to ensure that the work was successful. In SCG’s experience with GE turbines, total internal leakage can be reduced to less than 3% of hot reheat flow leakage.

The remainder of this article presents three case studies of successful evaluation and repair of GE turbines suffering excessive internal leakage. Remember to consult the August 2007 issue of POWER for similar stories concerning Westinghouse and Allis-Chalmers turbines.

Case study #1: Excessive HP to IP leakage in a 250-MW turbine

At this plant, a high level of turbine internal leakage was having an "invisible" impact on unit heat rate. The rise in heat rate, in 1999, would not have been diagnosed if the leakage test had not been conducted, because the turbine was running smoothly, with normal levels of noise and vibration.

At the time, 10 years had passed since the turbine had had its total HP to IP leakage measured using the temperature split test. The test had indicated that both total leakage and N2 packing leakage were both relatively low: 3.5% of hot reheat flow.

However, in 1996, a routine HP-IP test pointed to some type of damage (pressure changes) in the initial stages of the IP turbine. Just prior to the unit’s scheduled 1997 major outage for turbine maintenance, an open reheat spray block valve caused a turbine water induction event that

affected the turbine’s HP exhaust stages and inner shell. The outage inspection found the HP inner shell horizontal joint open near the HP inlet and detected several loose inner shell stud bolts.

SCG engineers didn’t believe that the bolts had been loosened by the water induction. Rather, they concluded this had occurred prior to the 1996 test, as a loose washer had disintegrated, entered the IP turbine, and caused damage the prior year. The HP inner shell required stress relief to correct distortion and some older cracks that had been weld-repaired. All new studs were installed on the inner shell. As the last outage in 1995 had indicated possible leakage, alternative main steam inlet snout rings were installed as part of the outage work.

Post-outage 1997 temperature split testing measured total HP to IP leakage at 7.5% of hot reheat flow, while blowdown testing indicated that N2 packing leakage was only 1%. The big differential pointed to a significant HP to IP leak. Because the snout rings had been replaced, they became prime suspects. As part of the investigation, discussions were initiated with the snout ring supplier.

In 1998 both tests were repeated. This time, measured total HP to IP leakage was 8.8% of hot reheat flow, and N2 packing leakage was 2.1%. Significantly, both percentages were increases.

In 1999 the tests were repeated a third time. Now, total HP to IP leakage was 16.6% of the hot reheat flow (nearly twice the previous level), while N2 packing leakage remained constant at 2.0%. By this time, the unit’s rolling-average heat rate had increased significantly, so an outage for inspecting the turbine was scheduled for early 2000.

The 2000 inspection revealed loose nuts on the HP inner cylinder, some with three to four turns open. The original nuts had been replaced by pinned nuts and washers that had been incorrectly installed. A measurement of the open joint area read 40 mils. The pinned nuts and washers then were installed properly. Although the inner snout rings appeared to be fine, there were signs of incipient problems with outer rings that led to a decision to replace all rings with conventional rings.

The post-outage HP-IP test to confirm the "fix" was delayed due to budget constraints. So the unit’s heat rate continued to rise throughout 2001, and plant personnel attributed the gains to "a boiler problem."

The post-outage test was finally conducted in January 2001. Discouragingly, it found total HP to IP leakage practically unchanged, at 17%, and N2 packing leakage at 3.5%.

In February 2001, SCG engineers arrived at the plant to perform a borescope inspection of the nuts of the turbine’s HP inner shell, using the midspan balance flange hole. Once again, there was evidence of loose nuts and—possibly—stretched studs.

GE was consulted for an alternative "fix." The company proposed installing Inconel through-bolts to replace the stud arrangement, and that was what was done prior to the major scheduled unit outage of 2002. For a few months preceding the outage, the leakage problem got bad enough to force a unit derate, because of excessive overfiring.

Inspection during the 2002 outage confirmed that nuts were loose on both sides of the HP inner shell and that the threads had been damaged by overstretching the studs (Figure 12). The through-bolt arrangement was installed.

12. Let’s tighten up. Loose nuts in the HP inner shell can increase internal steam bypass leakage. Shown is a 250-MW GE steam turbine. Courtesy: Southern Company Generation

The post-outage HP-IP test was conducted in June 2002. Total HP to IP leakage had significantly decreased to 4.5%, with N2 packing leakage at 2.0%. Although the numbers were not back at design, they were a tremendous improvement. The improvement was also reflected in the unit’s rolling-average heat rate (Figure 13). Although the correction of some boiler economizer performance problems during the prior outage also lowered the heat rate a bit, there was no doubt that decreasing HP to IP leakage was a much bigger contributor. To this day, the heat rate of the unit remains under 10,000 Btu/kWh.

13. Rolling average net unit heat rate. Unit heat rate improved significantly after the successful 2002 repair outage. Courtesy: Southern Company Generation

Case study #2: Excessive HP to IP leakage in a 250-MW cross-compound turbine

A 250-MW cross-compound turbine also was experiencing higher-than-normal heat rates in 1997, due to an unknown HP to IP leakage. As in the first case study, eight years had passed since the last temperature split and blowdown tests, which found the levels of total HP to IP internal leakage and N2 packing leakage fairly close, at 1.8% and 1.5%, respectively.

In 1995, as part of a major unit overhaul, the turbine’s main steam inlet snout rings were replaced with those of an alternative design. The subsequent performance test did not include a temperature split test; a blowdown test measured N2 packing leakage as "low."

A temperature split test was finally conducted on the unit in 1997; it measured total HP to IP leakage at 4.5%, with N2 packing still low at 1.5%. The disparity pointed to an undetected HP to IP leak.

In 1998, prior to the unit’s major annual overhaul, another temperature split test measured total leakage at 5.7% and N2 packing leakage at 2.7%—both increases. During the 1999 outage, when technicians unstacked the snout rings, they bore signs of leakage along the outer ring to shell bore fits as well as leakage across the ring stack flat surfaces. The main problem, engineers decided, was that the outer seal rings had expanded too much into the shell bore, mushrooming the softer shell material and causing "blue-blush" to exfoliate and migrate to the ring-to-ring flat surfaces.

Additionally, the snout ring material did not match the snout bore material on two of the four snouts. This caused those inner rings to not seal due to identical thermal expansion coefficients. The main steam inlet snout rings were replaced with conventional rings. The HP inner shell joint closure was found to be tight. The worn N2 packing was replaced.

Following the repairs, the two diagnostic tests were performed in 1999. They measured total leakage at 2.8% and N2 packing leakage at 2.0%—both decreases. The closeness of the two values indicated the presence of very little other leakage. Three more performance tests conducted in 2000, 2001, and 2005 verified that both leakage types remain low. However, both tests were again conducted earlier this year, and they measured total leakage at 7.0%, with a large contribution coming from the N2 packing leakage (3.7%). During this year’s scheduled outage of the unit, SCG expects to replace the N2 packing and check the condition of the snout rings and HP inner shell joint.

Case study #3: Excessive HP to IP leakage in a 500-MW supercritical turbine

Post-outage tests of a 500-MW supercritical turbine in 2003 measured total HP to IP leakage at 4.2%, with a 1% contribution from N2 packing. Routine testing in late 2005 indicated that total leakage had increased to 8.5%. At that time, N2 packing leakage could not be measured because the turbine blowdown valve would not open.

The unit’s outage records revealed that the bolting of the turbine’s HP inner shell had been replaced, but there were some misunderstandings because the bolt material was also changed, which could affect stretch requirements. The decision was made to open up the HP-IP turbine, with the expectation of finding loose HP inner shell bolting.

Unexpectedly, however, the source of the leakage problem was found to be broken N2 packing teeth (Figure 14). The HP inner shell joint was found to be tight. There was also one broken stud on the N2 packing head. It was determined that the N2 packing teeth broke because of looseness in the tooth slot; the packing had been re-toothed twice.

14. Needs dental work. These broken N2 packing teeth were found on a 500-MW GE supercritical steam turbine. Courtesy: Southern Company Generation

After replacing the N2 packing, the unit was retested in early 2006. Total HP to IP leakage was found to be 4.2%, with a 2% contribution from N2 packing leakage (as measured by a turbine blowdown test). If the turbine blowdown valve had worked properly in 2005, it would have been clear then that all of the prior increase in total leakage was due to leakage through the N2 packing.

For Westinghouse (Figure 1) and Allis-Chalmers combined high-pressure/intermediate-pressure (HP-IP) turbines, there are more design (and potential nondesign) leakages to the IP turbine than in General Electric machines. That’s because the former units require balancing the thrust loading of the reaction blading. Leakage can enter the IP turbine inlet, IP turbine exhaust, low-pressure (LP) crossover pipes, and occur between split IP1/IP2 turbines. Its result can be an apparent increase or decrease of IP turbine efficiency, depending on the source.

1. In the spotlight. A typical Westinghouse 500-MW BB44 HP-IP steam turbine. Courtesy: Southern Company Generation

Southern Company Generation (SCG) has found that trending of the apparent IP efficiency using the Booth-Kautzmann temperature split tests (discussed last issue in Part I) is very useful for resolving internal leakage problems on our Westinghouse and Allis-Chalmers turbines. It should be noted that the true IP blade path efficiency of these units is difficult to measure.

For later (BB44) Westinghouse turbines, the sources of design leakage (Figure 2) include:

• Main steam inlet bell seals (the leakage bypasses the HP-IP turbine; more recent units indicate zero leakage on the design heat balance).

• HP-IP-LP dummy balance seals (Figure 3). • HP exhaust piston seal rings.

• IP inlet (hot reheat) piston seal rings.

2. Go to the source. Design and nondesign leakage areas on the lower inner shell of a Westinghouse BB44. Courtesy: Southern Company Generation

3. To be smart, test these. The HP, IP, and LP dummy seals of a typical Westinghouse BB44. Courtesy: Southern Company Generation

Depending on the unit design, HP dummy seal leakage can affect HP turbine efficiency as it flows through the equilibrium pipes to the HP exhaust. If the IP dummy ring is severely distorted, it is possible for the IP dummy leakage to be a mix of HP dummy leakage and HP exhaust steam flowing in the reverse direction through the equilibrium pipes.

Among the sources of nondesign leakage are:

• The HP inner shell horizontal joint (distorted shell or loose bolting). • Broken internal equilibrium balancing pipes. • A broken first-stage drain or pressure-sensing line between the inner and outer shell. • Piston seal rings on the IP turbine mid-point extraction pipe. • A missing mid-span balancing port plug in the inner shell. • Cracks in the main steam inlet pipes at the trepan radius.

Relating efficiency to leakage

For the BB44 design, two values of apparent IP efficiency should be measured. The IP efficiency measured from the hot reheat to the IP exhaust at the blading only takes into account the leakage

effect of the IP dummy. The IP efficiency measured from the hot reheat to the LP crossover includes the effects of all HP to IP leakages. The temperature split tests are also used to estimate the IP dummy leakage and the total HP to IP leakage.

Although the test wells provided by the turbine manufacturer at the IP blading exhaust on the upper and lower (difficult-to-access) shells are in stratified locations, they are still useful for trending. Because the deaerator and boiler feedpump usually extract at these points, the temperature of the extraction line also should be measured. On one Southern Company unit that had been retrofitted with a new design IP dummy ring, we also installed two new test wells in the upper outer cylinder just upstream of the hot reheat inlet pipes. The results of testing using these wells still indicated some stratification of IP exhaust temperature.

A broken or cracked bell seal on a BB44 turbine can be diagnosed by trending the difference between the deaerator/boiler feedpump turbine extraction temperature and the LP crossover pipe temperature. If the former is several degrees lower than the latter and the two crossover pipes are at a different temperature, a bell seal or inlet pipe could be cracked.

For units with electrohydraulically controlled governor valves that are individually operated, the manufacturer’s bell seal diagnostic test is useful to perform. Each of the eight governor valves is closed (and re-opened) and the above temperatures are trended. (Exercise caution when doing so on the normal initial opening governor valve, including temporarily disabling the unit trip function.) A change in the temperature differences will be observed on a leaking bell seal when the corresponding governor valve is closed; this reduces but does not eliminate the leakage, which is reverse flow from the first stage, rather than main steam. If the testing indicates that an upper bell seal is the problem, it can be fixed relatively quickly because only the upper half of the outer cylinder must be removed. But if the testing indicates a problem with a lower bell seal, fixing it will not be easy because it will require removing all HP-IP turbine components.

Diagnosing other models

For Westinghouse turbines with an IP1-HP-IP2 arrangement (Figure 4), there are also two values of measurable IP apparent efficiency. The IP1 efficiency is measured from the hot reheat to the IP1 exhaust using vendor-supplied casing pressure and temperature connections in the lower test wells that are somewhat difficult to access on-line. (On some units, there is an extraction location on the IP1 exhaust that can be used for pressure/temperature measurements.)

4. Horse of a different color. A Westinghouse 180-MW IP1-HP-IP2 turbine. Courtesy: Southern Company Generation

IP1 efficiency values account for the effect of leakage of HP exhaust steam leakage to the IP1 inlet through the IP dummy seals. The total IP efficiency, measured from the hot reheat to the LP crossover pipe, includes the effects of leakage through the IP and LP dummies, the bell seals, the HP exhaust piston rings, the hot reheat inlet piston rings, the governor valve stems, and the seal at the end of the governor shaft. Possible sources of nondesign leakage include broken equilibrium pipes, a leaking HP-IP1 inner shell horizontal joint, broken first-stage drain and pressure-sensing lines, and cracks in main steam inlet pipes.

Until recently, the only unusual problem that SCG has experienced on the IP1-HP-IP2 type of turbine was a very high IP dummy leakage on one unit, but not on a sister unit. The problem was diagnosed as "extra" cooling holes found in the IP dummy ring, and it was fixed by reducing in size (welding up) the holes, as the existing IP dummy seals would provide sufficient IP inlet bucket cooling steam. A post-outage test revealed that taking this action substantially reduced both IP dummy leakage and total HP to IP leakage. Including the effect of reduced reheat spray flow, the unit heat rate improvement was about 40 Btu/kWh.

Smaller (100-MW and less) Westinghouse turbines have piston seal rings on the main steam inlet pipes. On these units, excessive leakage will reduce HP turbine efficiency as some or all of the HP blading is bypassed. Total HP-to-IP leakage is not affected by this leakage through the piston seal rings.

On SCG’s 100-MW Westinghouse turbines, the LP dummy flow (external pipes) to the IP exhaust can be measured using the vendor-supplied flow measurement/restriction orifice plates. On one occasion, the rotor of one unit was visibly thrusting, causing measured LP dummy flow to cycle. The results of temperature split testing were inconclusive due to the swings in leakage. Eventually, the turbine required an inspection to check for wear of its thrust bearing. The root cause of the thrusting was determined to be worn-out IP dummy seals, which were no longer in a hi-lo configuration (Figure 5).

5. Seals don’t lie. A 100-MW Westinghouse turbine with severely worn IP dummy seals that caused noticeable thrusting of its rotor. Courtesy: Southern Company Generation

Later Westinghouse units have a mid-span balance port that can be used for borescope inspections to check for loose HP inner shell bolts and broken equilibrium pipes. On BB44 units, this can also be accomplished by removing an LP crossover pipe.

Allis-Chalmers reheat turbines also are susceptible to several sources of design and nondesign internal leakages. Figure 6 highlights these sources for 75-MW Allis-Chalmers units, of which SCG has three. The sources of design leakage to the IP turbine include the IP dummy, the reheat diaphragm packing, and the LP dummy. Excessive leakage through the IP dummy and reheat diaphragm packing into the IP turbine inlet would produce an increase in measured IP efficiency. By contrast, excessive leakage through the LP dummy into the LP cross-around pipes would cause a decrease in measured IP efficiency. Sources of nondesign leakage include the reheat diaphragm packing housing joint and the horizontal joint.

6. Other sources of internal leakage. The HP, IP, LP, and reheat diaphragm packing of an Allis-Chalmers 75-MW turbine (L) and the HP-IP-LP dummy seals location (R). Courtesy: Southern Company Generation

Nondesign leakages—through the two sets of main steam inlet piston seal rings or the HP inner shell horizontal joint, or due to a broken first-stage pressure-sensing line/drain on the inner cylinder—affect the performance/efficiency of the HP turbine, but not leakage into the IP turbine. SCG has used the Booth-Kautzmann temperature split test to trend the leakage rate before and after a turbine outage on Allis-Chalmers units. We also have temporarily opened the reheat diaphragm (similar to the GE N2 packing blowdown test) and balance piston unloading valves to calculate the reheat diaphragm packing leakage and IP dummy leakage, respectively, based on the change in measured IP efficiency.

Recipe for repairs

Reducing excessive internal leakage in Westinghouse and Allis-Chalmers turbines may require taking any or all of the following steps:

• Replacing any HP-IP-LP dummy and reheat diaphragm packing seals with excessive clearance or broken teeth.

• Replacing bell seals or piston seal rings that are cracked or broken (Figure 7) or have excessive clearance/taper or erosion. The inner cylinder nozzle chambers or inlet pipes may require refurbishment if they are eroded or worn. Any unused bell seal retainer nut lock screw holes should be welded up as they can be a source of main steam leakage. Some piston seal ring designs (Figure 8) can produce excessive leakage if installed improperly, upside-down (one side is flat, and the other has alternating high and low sides).

• Checking inlet sleeves for cracks in the trepan radius using the turbine manufacturer’s test method. In Westinghouse BB44s that are routinely found to have cracked bell seals, distorted inlet sleeves could be the problem (a consequence of age); the manufacturer offers a method for straightening the inlet sleeve that SCG has used successfully.

• Changing the usually distorted IP dummy ring on BB44s to an improved design offered by the manufacturer. There’s another good reason to do this: BB44 IP dummy ring bolts broken by the distortion can enter the IP turbine and damage its blading.

• Repairing any broken equilibrium pipes or first-stage drain/pressure sensing lines. Sometimes, a equilibrium pipe can be eroded by a broken bell seal steam jet.

• Closing up or reducing in size any "extra" IP dummy ring cooling holes on IP1-HP-IP2 turbines. (Before doing this, consult with the manufacturer.)

• Inspecting the studs/shell threads of the HP inner shell horizontal joint for possible weld build-up caused by machining of the joint surface. The resulting leakage can actually flow up through the shell holes (Figure 9). The stud nuts should be "sounded" with a hammer to determine if any are loose prior to disassembly. For both studs and through-bolts, it is very important to know what they are made of because the material determines how much they can be tightened.

7. Yet another source. Cracked and broken main steam inlet bell seals on a Westinghouse BB44. Courtesy: Southern Company Generation

8. One-way street. The alternating (high- and low-side) piston seal rings of a 50-MW Westinghouse reheat turbine. Note that the rings are installed correctly, with the hi-lo side opposite the outer shell. Courtesy: Southern Company Generation

9. Loosey-goosey. Loose HP inner cylinder bolting on both sides of this BB44 turbine caused excessive HP to IP leakage, severely penalizing the unit’s heat rate. Courtesy: Southern Company Generation

After a repair outage, the turbine must be retested to ensure that the work was successful. In SCG’s experience with Westinghouse turbines, less than 6% of hot reheat flow leakage (the design level is 4%) can be achieved with good overall work. Although SCG’s experience with Allis-Chalmers turbines is limited to three units, results indicate that less than 6% of hot reheat flow leakage (design is 3%) can be achieved.

Case study #1: Excessive HP to IP leakage in a 500-MW Westinghouse combined HP-IP drum turbine

In this extreme case, a bad bell seal was determined to be the cause of excessive leakage that raised the unit’s heat rate. The turbine began producing an unusually loud noise following a temperature excursion. A temperature split test indicated that the measured IP efficiency to the LP crossover had decreased 5%, with a significant increase in the LP crossover pressure. Main steam flow had increased 6% although corrected load had only increased 3.2%. The test also revealed that total HP to IP leakage had increased from 6% of hot reheat flow to 13.5%. The temperature rise from the IP exhaust (deaerator/boiler feedpump turbine extraction) to the LP crossover suggested a possible leak through the bell seal or equilibrium pipe.

SCG engineers then decided to conduct the manufacturer’s bell seal leakage performance test. Analysis of that data indicated that closing the No. 7 and 8 valves, which feed a common nozzle block, produced the biggest change in temperature.

Since the No. 7 and 8 valves on this unit are upper inlet valves (narrowing the scope of the problem), the decision was made to remove the upper half of the outer cylinder. Doing so revealed a broken bell seal on the No. 8 governor valve inlet sleeve (Figure 10). Fortunately, the broken portion of the seal could be extracted from the inner shell, minimizing the duration of the outage.

10. Untrained seal. A broken bell seal on the sleeve of the No. 8 governor valve of a 500-MW Westinghouse BB44 steam turbine. Courtesy: Southern Company Generation

Case study #2: Excessive HP to IP leakage in a 500-MW supercritical Westinghouse combined HP-IP turbine

This case is more typical of excessive leakage that goes undetected. Pre-outage temperature split testing of this unit in 1992 indicated a very high level of IP dummy leakage (7.6% of hot reheat flow) and similarly high total HP to IP leakage of 7.4% of hot reheat flow (design is 5.4%). Since it is impossible for the IP dummy leakage to be higher than the total leakage, the absolute accuracy of the IP dummy leakage was called into question. A steam path audit calculated IP

dummy leakage of 3% through a distorted ring. Distorted IP dummy rings are a generic aging problem for the BB44 design.

The distortion of the IP dummy ring was "fixed" during the 1992 outage by installing new seals and boring them out off-center. Outage inspections also revealed that a broken first-stage drain pipe and worn HP dummy seals were contributing to the high leakage. The bell seals were in good condition.

Unfortunately, post-outage testing, in 1993, produced worse numbers for IP dummy leakage (13.4%) and total HP to IP leakage (14%). The unit experienced some thrust balance problems after start-up that may have contributed to the higher leakage. Computer models indicated that the leakage raised the unit’s heat rate by anywhere from 32 Btu/kWh to 109 Btu/kWh, depending on its source (first stage or cold reheat). The unit was retested in late 1993 and then again in late 1996. Both tests indicated that both the IP dummy leakage and total HP to IP leakage had decreased somewhat over time, which could not be explained.

Since the distorted IP dummy ring was a known problem, the plant purchased a "modernized" BB44M IP dummy ring from Westinghouse and installed it during a 1999 outage.

Inspections during the 1999 outage revealed some severely worn IP dummy seals (Figure 11) and some with rows missing. The HP dummy seals were also in poor condition, with numerous teeth broken off by axial movement. The LP dummy seals also were worn, and two leaking bell seals were found as well. However, a pre-outage test had not been conducted. If it had been, the total HP to IP leakage would have been much higher than reported by the last readings, in 1996. The dummy seals and worn bell seals were replaced when the IP dummy ring was upgraded.

11. Age takes its toll. A 500-MW supercritical Westinghouse BB44 turbine with a distorted and damaged IP dummy ring seal. Courtesy: Southern Company Generation

The 1999 post-outage test revealed tremendous improvements in IP dummy leakage (1%) and total HP to IP leakage (5.4%) to values near design. A test repeated one year later indicated that

both leakage rates had remained near design. Without a doubt, the new IP dummy ring had worked as advertised. The apparent values of IP efficiency, which had been high due to the IP dummy leakage, returned to more normal values. Unfortunately, during the 2004 outage, the replacement IP dummy ring was found to be distorted. Recent testing indicated that the IP dummy leakage rate (4.4%) and total leakage level (7.0%), though not quite as good as the 1999 results, are overwhelmingly better than those found by the 1993 tests.

Case study #3: Excessive HP to IP leakage in a 180-MW Westinghouse combined IP1-HP-IP2 turbine

This case also is typical of excessive IP dummy leakage that goes undetected. For many years, temperature split testing of this unit indicated very high levels of IP dummy leakage (5% of hot reheat flow) and total HP to IP leakage (8.6% of hot reheat flow). Measured values of IP1 and total IP efficiency were always higher than design, indicating significant leakage into the IP1 turbine inlet. The seal clearances of the IP dummy and the horizontal joint of the IP dummy ring, and the fit of the IP dummy ring into the outer cylinder had always been found acceptable. Finally, the mystery was resolved during a 2005 outage inspection. Three 1.25-inch holes were unexpectedly found in the IP dummy ring: one on top and two in the lower quadrants (Figure 12).

12. Size matters. "Extra" IP dummy ring holes (arrows) for cooling steam on a 180-MW Westinghouse IP1-HP-IP2 turbine. Narrowing them reduced HP to IP leakage rates. Courtesy: Southern Company Generation

A review of the turbine cross section and of detailed IP dummy drawings revealed that the holes were supposed to be there. Flow calculations indicated that these holes for cooling steam were the source of the excess IP dummy leakage (a significant 40,000 lb/hr). After discussions with Westinghouse, SCG decided to reduce the size of the holes to 0.4375 inch by welding and drilling. Post-outage testing confirmed that the work lowered the measured IP turbine efficiency by lowering its HP to IP leakage rates (to 1% for the IP dummy, and to 5.4% for total leakage).

On a similar, smaller unit at this plant, the holes in the IP dummy ring were completely welded up in the 2007 outage because a sister unit at another plant did not have the extra cooling holes.

For more information:

1. Booth, J.A., and Kautzmann, D.E., "Estimating the Leakage from HP to IP Turbine Sections," 1984 EPRI Power Plant Performance Monitoring Conference.

2. Blachy, S.R., and M.E. Foley, "Testing for Turbine Degradation and Improving Performance with Seal Optimization," 2005 Power-Gen Conference.

3. Cotton, K.C., Evaluating and Improving Steam Turbine Performance, 2nd ed. (Rexford, N.Y.: Cotton Fact Inc., 1998). 4. Hopson, W.H., "Practical Field Experience with Steam Turbine Performance Testing," 2003 EPRI Heat Rate Improvement Conference.

5. Svensen, L.M.E., "Internal Leakage Study Winyah Generating Station Unit #3," 2003 Scientech PEPSE Users’ Group Meeting.

6. Tirone, G., L. Arrighi, and L. Bonifacino, "Diagnostics Based on Thermodynamic Analysis of Performance of Steam Turbines: Case Histories," ASME PWR, vol. 30, 1996 Joint Power Generation Conference, vol. 2.

The author wishes to recognize the outstanding turbine maintenance performed by James Carlson and Bill Broos of Southern Company Generation’s Mechanical Field Services department. The enlightening test results and discussions in this article are due to their efforts and the hard work of SCG’s Generating Plant Performance department.

—Warren Hopson, PE, is a Southern Company Generation principal engineer for Generating Plant Performance. He can be reached at whhopson@southernco.com.

Author’s note: At press time, SCG was investigating a sudden rise in thrust bearing temperature in a 125-MW IP1-HP-IP2 turbine. Further review of the incident indicated sudden increases in measured IP2 efficiencies (one to a heater extraction and one to the LP crossover), along with lower reheat pressures and higher pressures in the IP2 turbine. The problem was determined to be a broken equilibrium pipe between the IP1 exhaust and the IP2 inlet. Unit full load is restricted until an outage can be taken to correct the problem.