Measure the Cause, Not the Symptom

Directly measuring bearing metal temperature is the most effective way to really determine if a bearing is running hot. Bearing oil drain temperatures are still being utilized on older machines. By the time the bearing oil drain temperature has increased, the bearing may have already been compromised (wiped). PSG recommends that these older machines should have temperature probes (thermocouples or RTD’s) installed in the bearing Babbitt to properly monitor performance. A two-level alarm is recommended (not automatic trip). The first alarm should be set a few degrees above the highest temperature in the recommended normal operating range. Operators should closely monitor bearing temperature after the first alarm sounds. If the temperature rises abruptly and unexpectedly, the bearing may have been compromised and immediate action needs to be taken. Gradual temperature changes which trigger the alarm may be the result of other factors but are still a concern and should be thoroughly investigated. The second alarm should be set at the maximum operating temperature of the bearing material. Operators should manually trip the unit in a controlled manner as soon as possible after this second alarm sounds and determine the cause. The critical temperatures for each of the two levels can be supplied by the manufacturer or recommended by PSG for your individual unit configuration. Different temperature ranges are recommended for Tilt Pad, Elliptical, Short Elliptical and Thrust bearings. Measuring drain oil temperature is too slow and too imprecise to effectively minimize your overall cost of maintenance. Retrofit your machine and save your bottom line.

The Ugly Effects of Water in Lube Oil

Free and emulsified water are the two most harmful conditions in a lubricating system. The incompressibility of water overrides the hydrodynamic oil film that protects bearings, leading to excessive wear. As little as one percent water in oil can reduce the life expectancy of a journal bearing by as much as 90 percent.

Water will also degrade the life of your lubricant. Moisture contamination can promote the oxidation of the oil by up to 10 times, breaking down the hydrocarbon chains and decreasing the lubricating properties.

Oils containing some types of additives are even more vulnerable to water contamination. Sulfurous AW and EP type additives and phenolic antioxidants are readily broken down by water. This not only destroys their usefulness, but the destruction forms acids which can corrode soft metals such as Babbitt, bronze and brass. The copper, lead, and tin released from this corrosion are catalytic metals which actually accelerate the process. Even synthetic oils containing dibase esters and phosphate esters are not immune. These compounds are known to react with water and form acids, increasing corrosion and degrading the base stock.

Water can disperse other additives such as demulsifying agents, detergents and rust inhibitors, resulting in sludge and sediment buildup, filter plugging and poor oil/water demulsibility.

There is no safe level of water contamination. While maintaining contamination below the saturation point will reduce the levels of free and emulisified water, any amount will start the cycle of degradation.

We recommend that you send a lube oil sample out for analysis on a monthly basis. Then read their report very carefully, noting all metals and water contamination. The service should also provide a narrative of the findings. If you need any help in interpreting the report, please contact us at Ask Mr. Turbine.

Click Here to ask your own question of TGM’s Mr. Turbine or call the 24 Hour Hotline at 888.MrTurbine (888.678.8724)

Inadequate Oil Supply: Measure the Cause, Not the Symptom

This is Part Three of a three part series on steam turbine tips, discussing the challenge of inadequate oil supply.

Directly measuring bearing metal temperature is the most effective way to really determine if a bearing is running hot. 

Bearing oil drain temperatures are still being utilized on older machines.  By the time the bearing oil drain temperature has increased, the bearing may have already been compromised (wiped). PSG recommends that these older machines should have temperature probes (thermocouples or RTD’s) installed in the bearing Babbitt to properly monitor performance.

Inadequate Oil Supply - Part ThreeA two-level alarm is recommended (not automatic trip). Consequently, the first alarm should be set a few degrees above the highest temperature in the recommended normal operating range.  Operators should also closely monitor bearing temperature after the first alarm sounds.

Keep in mind that if the temperature rises abruptly and unexpectedly, the bearing may have been compromised and immediate action needs to be taken. Gradual temperature changes which trigger the alarm may be the result of other factors but are still a concern and should be thoroughly investigated.

The second alarm should be set at the maximum operating temperature of the bearing material.  Operators should manually trip the unit in a controlled manner as soon as possible after this second alarm sounds and determine the cause.

The critical temperatures for each of the two levels can be supplied by the manufacturer or recommended by PSG for your individual unit configuration. Different temperature ranges are recommended for Tilt Pad, Elliptical, Short Elliptical, and Thrust bearings.

Measuring drain oil temperature is too slow and too imprecise to effectively minimize your overall cost of maintenance. Taking all of this into consideration, the best practice is to retrofit your machine and save your bottom line.

Do you have questions about your steam turbine backup system? Contact PSG today to explore how we can provide support and maintenance options to help you avoid backup system problems.

Inadequate Oil Supply: Don’t Kill Your Turbine on Startup

This is Part Two of a three part series on steam turbine tips, discussing the challenge of inadequate oil supply.

Your lube oil temperature needs to be lower at startup and shutdown than at full speed to reduce potential issues.

Your turbine’s rotor does not actually ride on the surfaces of its bearings. It rides on a thin film of oil between the rotor and the bearing. At high turbine speeds the rotor hydroplanes across the oil, eliminating contact with the Babbit of the bearing. The heat generated by the turbine decreases the viscosity of the oil and increases its “slipperiness”, which is important at high speeds.

Inadequate Oil Supply - Part TwoAs the rotor slows down, the oil needs to be more viscous to repel the force towards the bearing.

Failure to lower the lube oil temperature (and therefore increase viscosity) can result in light bearing wipes or smearing. These conditions would occur during turning gear operation, unit startup and unit coast down during shutdown.

The ideal lube oil temperature at these lower speeds is 90 degrees Farenheit. Of course, oil temperature can also be too cold on startup—similar to trying to start your car on a cold winter day. Operational personnel are ultimately responsible for maintaining this lower lube oil temperature by regulating water through the lube oil coolers.

Maintaining lube oil cooler cleanliness is also very important for turbine startups.  The tubes must be clean to allow the efficient transfer of heat. Also, as a best practice the bundles should be cleaned every two (2) years.  Lube oil coolers are the single most common area for contaminants to hide.

By following these tips, you can ensure the efficient startup of your turbine, as well as greatly reduce any potential operational issues or challenges.

Do you have questions about your steam turbine backup system? Contact PSG today to explore how we can provide support and maintenance options to help you avoid backup system problems.

Inadequate Oil Supply: When a Backup isn’t a Backup

This is Part One of a three part series on steam turbine tips, discussing the challenge of inadequate oil supply.

The International Association of Engineering Insurers has found that the loss of oil pressure causes the highest frequency of failure in steam turbines worldwide. 

Inadequate Oil Supply - Part OneMost of these steam turbine failures are caused by an unreliable backup system to maintain oil pressure to the bearings should the primary AC-driven lube oil pumps fail. These AC motors are powered by either the turbine’s output or the grid—causing a failure if the turbine or generator trips—or if there is an external outage.

Modern turbines have backup powered DC oil pumps mounted on the oil tank, which are triggered by a pressure switch in the event of a loss in oil pressure. With this in mind, it is very important to conduct tests with the AC and DC oil pumps during scheduled maintenance inspections to ensure that the DC pump engages as required.

Such tests can be referred to as cascade pump pressure inspections.  In addition, the tests will confirm the pressures when the DC oil pump will engage after the AC oil pump is actually turned off.

Another best practice is to verify backup batteries on a regular basis, when the unit is down, and mandatory tests should be performed before the unit is placed in operation after an overhaul.

Older turbines can use steam-driven pumps as backup. On these designs, a pressure regulator will sense the drop-in bearing oil pressure and turn on the steam supply to the blade wheel of the pump.  But while these pumps are usually very reliable, they still must be manually tested on a regular basis and after an overhaul.

Care must also be taken to not overspeed the pump or it will potentially cause internal component damage and may even completely destroy the pump.

Some older turbines use gravity lube oil tanks. These tanks are mounted above the unit on stands and are controlled by a check valve type of arrangement. In such cases, there are no pumps involved—gravity provides the bearings with sufficient lubrication in an emergency situation.  While less complicated than DC or steam powered backups, their operation must still be routinely checked.

The bottom line is, that a backup is not a backup unless it is reliable. And it can only be reliable if it is tested.

Do you have questions about your steam turbine backup system? Contact PSG today to explore how we can provide support and maintenance options to help you avoid backup system problems.

Alstom STF Steam Turbine

The Power Services Group, Inc. field service team recently completed a turnkey B-inspection on an Alstom STF steam turbine rated at 190 megawatts output. The work scope included disassembly, inspection and reassembly of the HP stop valve, HP control valve, IP stop valves, IP control valves, bearings #1 through 5, and the thrust bearing. PSG’s turnkey solution supplied outage management, technical direction, supervision, craft labor, outage tooling, consumables, non-destructive testing, and commissioning and start-up services. The project was aggressively scheduled for 10 days mechanical duration, with a two shift around the clock coverage. Completed safely and without rework, the project was one day ahead of schedule. Another great example of PSG’s expertise with Alstom steam turbines, we provide our clients with a proven and trusted alternative to the OEM.

D11 Issues – Cracks in the HP/IP Shell

At STUG 2015, 50% of users of the GE D11 Steam Turbine reported cracking issues in the HP/IP shell, especially the N2 packing gland and shell fit. These cracks create the potential for forced shutdowns and relatively long outage cycle times.

Operators can mitigate this potential through a more rigorous NDE of the gland and fit any time the component is exposed, and monitoring HP/IP efficiency and/or pressure for a significant but gradual drop. This reduction may signal imminent failure and advise a shutdown of operations for a major inspection. GE indicates that the “cycle time for repairing cracked packing glands is approximately 25 days, which can become the critical path during a major outage”. This cycle time can significantly extend the OEM’s recommended 60 day plan for a major outage. GE also recommends having a spare N2 packing gland on hand if this additional cycle time will significantly disrupt operations.

TGM® recommends addressing this potential problem with a thorough and ongoing program of performance monitoring in conjunction with robust advanced planning for outages. Our Running Condition Assessment (RCA) program can help identify and evaluate this and other potential operational issues and form the cornerstone of the shutdown planning. A robust, flexible and contingent advanced plan can reduce major outage cycles from 60 days to 45 or even 30 days, depending on the amount of repair involved.

These results can only be achieved with a high level of coordination (well in advance of the outage) between the operator, the outage team, and an array of subcontractors that may (or may not) be called upon if various planned contingencies are realized. A case in point is the N2 packing gland and shell fit. Significant pre-outage planning is required to prioritize the disassembly and NDE of these components in case long-lead time issues are identified. Dust blast and NDE of the upper half of the N-2 packing case should begin as soon as it is exposed and removed; the lower half should be prioritized after the rotor is removed. A repair plan should be in place in case cracks are found, and the repair vendors should be identified, costed, and notified prior to the outage. TGM® has developed a 14 day cycle plan for most cracking issues, using pre-approved TGM®vendors. Our one-year warranty also applies to these repairs.

Most users who have experienced cracking problems have reported varied results. Repairing shell cracks involves many technical considerations and must be performed by experienced and knowledgeable personnel. Please refer to our previous 3-part series on weld repair (Part 1, Part 2, Part 3). We agree with others that once the N2 packing gland starts cracking, it will eventually have to be replaced.

TGM® additionally recommends providing on-site machining equipment in case adjustments need to be made to the packing gland or the shell fit, and for other potential modifications and known potential TIL requirements. Provisions should also be made to perform high-strength on-site weld repairs to correct dimensions or to repair shell cracks in these or other locations.

Summary
The high-efficiency GE D11 Steam Turbine is a valued workhorse in many combined cycle plants. However, the efficiency comes at the cost of many known potential problems resulting from the higher temperature and pressures, close tolerances, and overall complexity of the unit. The potential for forced shutdowns and relatively long outage cycle times can be significantly reduced. This reduction requires:

  1. A thorough and ongoing program of performance monitoring
  2. A high level of coordination (well in advance of the outage) between the operator, the outage team, and potential subcontractors to develop a robust and flexible outage plan
  3. A knowledgeable, proactive and creative program management / technical direction team to execute the many moving parts of the plan.

Please Contact Us for more information on this and other D11 issues.

Why Valve Freedom Testing is Critical

At STUG 2015, a survey revealed that 43% of D11 combined cycle users perform valve freedom testing on a daily basis, while 38% perform it on a weekly basis. The potential accumulation of deposits is a little more critical in these high temperature units, but exercising valves is important on any unit. For instance, on a recent 40MW forced outage, TGM® serviced a stuck Emergency Stop Valve that was exercised every week. How does one determine the “safe” frequency?

First a little background: We stroke valves to make sure debris and contamination have not blocked the operational clearance between the shaft and its bushing, preventing freedom of the valve to operate. A binding Main Stop Valve (MSV) in an emergency shutdown or trip could cause an overspeed condition resulting in extremely high vibration and equipment failure – even possible personal injury or death. Main steam valves should have a closing time of at least 2 seconds. Non-Return Valves (NRV) also need to be exercised on a regular basis to prevent water induction. This occurs when cooler steam condenses in the pipes and feeds back into the turbine. Water induction can cause serious damage, often referred to as a turbine rotor short condition.

Boiler chemistry plays an important role in the build up of deposits. This issue was covered in a previous Turbine Tip HERE.

In higher temperature units, there is a potential for binding of valve shafts due to exfoliation (blue blush) build-up from either the superheater tubes or reheater tubes in the boiler. Blue blush is a common problem on units that have a single axial type of design or an HP-IP type of configuration with elevated steam inlet temperatures. The HP-IP design not only affects the main steam inlet valves but the reheater valves as well. These HP-IP designs commonly operate at 1,000 degrees F inlet steam temperature at both the main steam inlet and reheater locations. This build-up of blue blush comes in from the walls of the superheater tubes or reheater tubes in the boiler and fuses onto the stems or shafts (also bushings). This exfoliation closes up the operational clearance between the shaft and its bushing, resulting in potential binding of the shaft and preventing freedom of the valve to close in an emergency shutdown or trip.

Another result of exfoliation (or any other hard particle steam contamination) is erosion
which can damage valve parts, nozzle partitions and the blading (buckets) themselves. Elevated temperatures of the steam can also cause valve shafts or stems to distort and bend, resulting in additional binding problems. With temperatures such as 1050 degrees F, creep is apt to take place more rapidly than a 1000 degree F application.

To reduce the chance of binding, OEM’s have increased the operational clearances for these high temperature machines over the design’s original upper limit. These clearances can be achieved during major inspections. Any blue blush (exfoliation) will be removed by sandblasting or by hand with emery strips (fine sandpaper grit). Stems (shafts) can be used over again and this blue blush build-up once cleaned can also be helpful in maintaining the desired clearance between shaft and bushing components.

Now we have a handle on the parameters for determining the frequency of valve freedom testing: Higher steam temperatures, current boiler chemistry, closer stem/bushing tolerances, measured stem runout, and the degree of existing blue blush build up all play a role. If production and manpower are not issues, we recommend daily freedom testing. However, if these issues are a concern, you will have to measure the risk of less frequent testing against these parameters.

If you do not feel comfortable making this decision on your own, the TGM® Running Condition Assessment (RCA) can help. The assessment looks at the condition and performance of the unit while it is running, which means there is no loss of generating capacity and the assessment is easy to schedule. We assess your boiler chemistry and blue blush build up, and consider your operating history and previous outage findings, including as-found and as-left stem/bushing clearances from previous inspections. An opinion on the frequency of valve freedom testing is but one result of the RCA. In addition, TGM® can employ an arsenal of cost-effective testing equipment and inspections to glean a wealth of information about the actual operating condition of the turbine, the generator, and all the ancillaries. TGM® analyzes this data and generates an informative report which assesses potential failure modes and weighs their effect on generating capacity and potential outage duration. Remedies and operational changes are ranked from “easy to implement with maximum benefit” to “hard to implement with minimum benefit”. Operators can then make the most informed and economically-sound maintenance decisions possible.

Click the link HERE for more information on the TGM®Running Condition Assessment.

How 0.002” Can Ruin a Turbine

Steam turbines can reliably run for 30, 40 years or more. However everything wears and eventually fits, finishes and tolerances become unacceptable. For instance, the rabbet fit on the coupling faces of a three bearing machine will eventually become loose and in need of repair. This defect can cause misalignment, abnormal vibration levels and undue stresses on the rotors.

On a three bearing machine the contact area of the coupling faces is also referred to as the friction face. This is where the torque of the coupling bolts exerts the necessary clamping pressure to hold the coupling halves together without any movement. The normal criteria are 0.000″ to 0.001″ interference for the rabbet male to female fit. Clearance is not permitted. Once this fit becomes too loose then any kind of abnormal event, like a full load trip or synchronization of the generator out of phase could cause a small shift of position at the coupling due to the shaft torque. Since the alignment specification is one half of a mil per foot of shaft from the center of the coupling, any movement at the coupling halves can translate into a misalignment problem.

There are basically three components that need to be maintained in good condition: First is the interference fit of the male to female rabbet. We have already described the importance of this. Next is the condition of the friction faces of the coupling. The faces should maintain a surface finish of 63. They should be hand cleaned only and should never be stoned. Last but not least is the integrity of the coupling bolts.The coupling bolts can fatigue and yield over time from being loosened and re-torqued repeatedly. One should check for galls and burrs which might be evident under the bolt heads or on the flat surfaces of the nuts. The coupling bolts should be inspected nondestructively for cracks during every major inspection. All three items are simply mechanical devices which can be overlooked or assumed to be acceptable for continued service. In reality they can cause misalignment, abnormal vibration levels and undue stresses on the rotors.

Although four bearing machines do not have this particular problem, any deviation from any specification can potentially cause problems either immediately or down the road.

Overlooked Gland Seal Can Be Big Trouble

The steam turbine gland steam seal system is designed to keep steam from leaking out of the turbine and to prevent air from leaking into the turbine. A gland seal system can be as simple as a spray chamber, loop seal and a steam ejector or as complex as surface condensers, air blowers or vacuum pumps. Simple or complex, the system requires timely care and maintenance. An improperly balanced gland system can lead to water in the lubricating oil, loss of vacuum or accelerated wear on the packing gland components.
No matter the configuration of your system, there is a delicate balance between the high pressure and low pressure ends of the turbine. The labyrinth-type seal rings in the gland housings are designed for a certain amount of pressure drop which coincides with the designed operating conditions of the unit. If too much vacuum is being drawn across the seal rings premature wear and loss of vacuum will be experienced at the labyrinth seal. If too much pressure is present at the labyrinth seal then steam leakage, corrosion and premature wear will be evident.
We recommend checking the gland system for proper operation during all scheduled inspections. Corrections to the system will usually be performed during a major inspection, when all of the components are accessible. Maintenance items can include partially plugged gland leak off lines, improperly adjusted balance butterfly valves, severe wear of the spray chamber nozzle, worn out vacuum pumps, gland condenser tube leaks, eroded air blower impellers and malfunctioning steam seal regulators.
Neglect of the perceived small things can lead to bigger and more costly problems. All of the auxiliary systems that support the steam turbine are of a critical nature especially when overlooked and not properly maintained.