501F Users Group: No better F-class meeting

Might be a good time to consider which meetings you want to attend in the first quarter of next year. Summer is over, fall outages will take center stage for the next couple of months, and then there are the holidays. This means 2018 is peering over the horizon, especially if corporate approvals are required. A possible benefit of submitting paperwork early is use of 2017 budget surplus to pay for a future activity.

The first user group meeting in the coming year, based on information made available to the editors, will be the 501F Users Group conference at the Hyatt Regency Grand Cypress (Orlando, Fla), February 25 to March 2. CCJ ONsite considers this is a must-attend event for owner/operators of 501F engines.

The all-volunteer organization’s steering committee (sidebar) is honing the 2018 agenda; it will be posted on the group’s website when complete. Next year’s program is sure to have some of the same elements as the information-rich 2017 conference, which ran four and a half days and included the following:

      • User-only roundtables promoting open discussions and short presentations by owner/operators on safety, combustion section, hot-gas section, inlet and exhaust, compressor, rotor, generator, auxiliaries, and outage management. The roundtables typically ran from 60 to 120 minutes each. They are considered by many users as the “heart of the meeting.”

      • Seminars by major products/services providers—Mitsubishi, PSM (Ansaldo Energia SpA), Siemens, Sulzer, and GE—ranging from two to four hours each.

      • Vendorama program. This year, 38 companies made 41 technical presentations ranging from 30 to 50 minutes each to bring users up to date on products/services of interest to the 501F community. The program matrix—seven time slots in each of six rooms, running from 9:30 a.m. to 4:00 p.m.—allowed each attendee to participate in up to seven presentations. Note that Vendorama presentations are vetted by the steering committee to ensure a technology focus and to eliminate blatant sales messages.

      • Vendor fair, following the Vendorama program on the first day of the meeting, provided users the opportunity to peruse the offerings of 89 vendors.

If you have never attended a 501F Users Group meeting, make the 2018 conference your first. The following case history presented by a user at the 2017 meeting offers a glimpse at the level of detail you will gain access to by participating. Material like this, possibly vital to your plant’s future success, is not available anywhere else. Watch for detailed coverage of the last conference in CCJ ONsite in the coming weeks.

Important note for shy O&M personnel: The 501F users is a brotherhood and first timers (about half of the 125 to 150 attendees typically expected at an annual meeting) are accorded the same respect given to more experienced participants.

Steering committee


Russ Snyder, Cleco Power LLC, President and Chairman
Paul Tegen, Cogentrix Energy Power Management LLC, Vice Chairman
Carey Frost, Duke Energy, Secretary
Dave Gundry, Xcel Energy Inc, IT Officer

Board members

John Burke, NAES Corp/LSP-Cottage Grove LP
Blaine Gartner, Xcel Energy Inc
David Lucas, PacifiCorp
Arlen Morris, NextEra Energy Inc/FPL
Jeff Parker, SRP
Ramon Gonzalez Recio, Falcon Group/Comego

Case history: Turbine blade ring burn-through

Vital stats: 2 × 1 combined cycle powered by 501FD2 gas turbines commissioned in 2001 with an average of nearly 60,000 equivalent operating hours per engine and nearly 3200 equivalent starts.

Incident profile: One engine tripped on blade-path spread; a high-temperature alarm was received for disc-cavity (DC) 2 prior to the trip.

Initial findings:

      • Event lasted three minutes.

      • Combustion seemed stable.

      • Inlet-bearing vibration increased slightly during the event.

      • Blade-path thermocouples (TCs) 1 and 16 increased to 1185F and then dropped to less than 1000F, causing the trip.

      • Coast down took 23 minutes, only slightly longer than normal.

      • Turning-gear amps were normal after coast-down.

Operators decided to spin-cool the unit. After the gas turbine was off turning gear, inlet guide vanes were inspected for looseness, TC2 was found melted, and debris was in evidence when the exhaust door was opened. A borescope inspection revealed significant turbine damage. A crawl-through of the combustor case confirmed burn-through of two blade rings (photo); the unit was disassembled.

Damage assessment:

      • Combustion hardware was fine.

      • R1 vanes had minor impact damage at the trailing edge.

      • Tips of R1 blades were worn off and there was evidence of trailing-edge impact damage.

      • Two segments of the R1 ring segment were missing.

      • The breech in the R1 blade ring was about 10 in. in diameter.

      • R2 vanes revealed local melting.

      • R2 blades suffered impact damage.

      • There was no damage to the R2 ring segment.

      • Downstream impact damage.

Root-cause analysis incorporated hardware inspection, metallurgical analysis, and review of operating data and of inspection reports. Investigations revealed the following:

      • Metallurgical analysis showed nothing out of the ordinary.

      • R1 vanes had been repaired previously and areas of erosion had been repaired during the last outage.

      • R1 ring segments were installed new, not refurbished.

      • Assembled blade-tip readings were within spec for non-VGP (Value Generation Program) components.

      • Hardware has 569 equivalent stars and 12,700 equivalent operating hours at the time of failure.

      • Previous borescope inspections identified a rub in the area where the ring segments were missing. The rub had removed the thermal barrier coating and smeared base metal; however, the OEM considered the damage low risk and approved a return to service.

An operational review identified the following changes in the engine:

      • One week prior to the event, a step change occurred on the blade-path TC—7-deg-F warmer on BP TC1. The monitoring center was asked to watch for a worsening condition. No vibration change was noted.

      • Baseload output dropped by 1 to 2 MW over the week prior to the event. But operators would not have detected this on a cycling unit with varying loads.

      • While the temperature in DC2 remained stable, the cooling valve opened gradually throughout the week leading up to the failure.

So, what happened?

No single root cause was in evidence and the findings were relatively inconclusive. A timeline of events during the week leading up to and including the trip was difficult to compile based on operating data.

Investigators believed that the combination of blade-tip rubbing on the ring segment which removed TBC and potentially reduced cooling, and vane shroud erosion which reduced ring-segment leading-edge cooling, likely caused erosion of the ring segment and isolation segments—thereby allowing liberation of the ring segments. After the ring segments liberated there was no protection for the blade ring from hot gas.

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Track performance data from plant’s historian to prevent piping failures

NV Energy’s Silverhawk Generating Station experienced repetitive failures of cold-reheat (CRH) piping which were attributed to quenching of the pipe caused by leaking attemperators. The cause of the first failure, in 2013, initially was thought to be a flaw in a shop weld. Three years later the plant suffered three more failures within a 12-month period and performance data were collected to determine the root cause of the problem.

The Silverhawk CRH piping failures occurred at the high pressure (HP) bypass to the CR tee, requiring multiple repairs at significant unbudgeted cost. The failures caused forced outages and loss of availability hours.  

In a typical combined cycle, after the gas turbine is started and the steam begins to absorb energy from the exhaust-gas stream, it flows from the heat-recovery steam generator through the HP piping and is bypassed to the CRH line via the bypass pressure control valves (PCVs), as shown in Fig 1. The HP bypass lines have attemperators on the line to mix feedwater into the bypassed steam and control the temperature of the fluid in the line. Attemperator water flow is controlled using a flow-control valve and a block valve.

Silverhawk’s plant engineer, Rishikesh Velkar, and NV Energy’s manager of generation engineering, Bob Ott, described to the editors the failures that the plant has experienced since 2013:

      • July 2013. The cold-reheat tee failed on Unit A, identified by water and steam leaking from the piping. The loss in availability attributed to repairing and testing the piping was 55 hours.

With the unit shut down, insulation was removed in the tee area and a visual inspection was conducted. The downstream weld connecting the tee to the CR piping had a clear indication of a crack, which was confirmed by magnetic-particle and dye-penetrant testing (Fig 2).

The indication was 5 in. long on the pipe OD, 24 in. on the pipe ID. During radiographic testing of the weld after repairs, another crack was found on the opposite side of the tee in the same weld that had been repaired. This 3-in.-long circumferential crack was repaired as well.

      • March 2016. The CR tee on Unit A failed again on the downstream weld connecting the tee to the steam piping. Availability loss: 26 hours. The crack, confirmed using dye penetrant, was 8 in. long.

      • September 2016. The CR tee on Unit A experienced its third failure, on the same downstream weld and in the same area as it did in July 2013. Availability loss: 18 hours. Two cracks, each about 10 in. long, were detected during an ultrasonic inspection.

      • January 2017. The CR tee on Unit B failed at the downstream end; availability loss was 20 hours. The crack, about 18 in. long, was found during an ultrasonic inspection (Fig 3).

Investigation of the 2013 incident concluded the failure was caused by flaws in the shop weld and introduced during fabrication. Engineers believed that cycling of the unit could have exacerbated the problem because of thermal fatigue. After the second and third incidents in 2016, investigators confirmed that all three failures were caused by quenching of the metal by condensate.

Staff suggested two ways condensate might enter the CRH pipe and quench it:

      • The first, via the drain pot, by back-feeding through the flash tank header, which if unable to drain correctly would allow condensate to pool in the CRH line. This possibility was supported by a report from plant personnel who saw the flash tank overflowing a couple of years prior to this event.

However, backflow was ruled out after review of historian data. There was nothing to suggest the flash tank was overflowing and the drain-pot valve was functioning normally.

      • The second, via the attemperator and its associated block valve. This could not be verified by historian data because the feedwater flow meter was not working properly.

Engineers then decided to open a drain valve between the flow control valve (FCV) and block valve during normal operating conditions to see of the latter was leaking in the closed position. Water flowing through the drain valve confirmed this was the case. But it was not known if the FCV was leaking as well.

After the CRH tee on Unit B failed early in 2017, insulation was removed and eight thermocouples were installed temporarily on the tee to collect the data required for a true root-cause analysis (Fig 4). Six thermocouples were attached upstream and downstream of the weld, two of them near where the failure had occurred. The remaining two thermocouples were attached on the top and bottom of the HP bypass line connection to the tee.

Pipe temperatures were recorded during a Unit B start and when the plant was transitioning from 1 × 1 operation (Unit B gas turbine, its HRSG, and the steamer in service) to 2 × 1 service. Looking at Fig 5, note that as the unit heats up, the temperatures on the pipe slowly increase to 620F.

Now observe that during 1 × 1 operation, when the Unit B HP steam meets the required set point for it to flow through the turbine and the HP bypass valve closes, thermocouples TE7 and TE8 on the bypass side of the tee drop to approximately 300F. This confirms feedwater was leaking through the attemperator valves.

Furthermore, during the transition to 2 × 1 operation (when the Unit A HP bypass valve closes), thermocouples TE1 and TE4, where the failure occurred, drop down to about 360F. This means that during 2 × 1 operation there was a stream of water spraying in the area where the failure occurred, causing the metal to quench and contract.

Engineers decided to conduct a high-energy-pipe inspection during the spring 2017 outage. Prior to that outage, insulation was removed to prepare the surface of the pipe for an NDE inspection. An infrared camera was used to gain a better understanding of the temperature transients across the tee. The pictures clearly showed the attemperator leak was cooling a portion of the pipe (Fig 6).

Conclusion. A significant area of the pipe was cooled to around 350F to 400F, causing that section of pipe to contract while the remainder was expanding. The cool area overlapped the previous failure areas. Engineering analysis revealed the failures occurred from the inside surface outward in fatigue. The information gathered proved that the failures of the weld at the tee was from quenching caused by leaking attemperator valves.

Final steps. During the 2017 spring outage the following actions were taken:

      • Attemperator block valves were replaced to prevent feedwater leak-by.

      • Permanent thermocouples were installed on the HP bypass line downstream of the attemperator to alarm when steam temperature falls below saturation—this to alert operations personnel to potential attemperator block-valve leak-by and abnormal operating issues.

After these action items were implemented, the thermocouples on the bypass line indicated a steam temperature of more than 600F, confirming that the new block valves prevented feedwater from entering the steam pipe.

Finally, similar issues were found at another plant in the NV Energy fleet that had experienced piping failures—although the piping configuration was different. An infrared camera was used to confirm the quenching and isolation valves were restored to prevent these damaging conditions.

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O&M lessons learned on stator-bar insulation systems help improve generator reliability

Special to CCJ ONsite from Clyde V Maughan, Maughan Generator Consultants

Generator stator-bar insulation systems have experienced a steady evolution since the beginning of central powerplants in the early 1900s. Initially, 1900-1915, natural products were used—for example, shellac, mica flake, paper. These materials apparently worked well on small, low-duty units.

As generators grew in size, problems developed, and during the period 1915-1950 “asphalt-mica” was the common system. But its use was discontinued in the 1950s for generators rated higher than about 25 MW because of materials limitations. Enter thermoset resins, first polyester and then epoxy, for impregnating the mica tapes.

From the 1950s to the present time, thermoset systems have evolved upward in mechanical and electrical capabilities. But during this period, generator ratings also have gone up, with associated mechanical and electrical duties increasing dramatically. Although the still-evolving thermoset insulation systems generally have performed fairly well, problems continue to occur. Some of these problems have been very costly and some have been very persistent. 

From an O&M viewpoint, all thermoset insulation systems used in modern generators are basically the same, although in a few important ways they are different from the soft asphalt systems of yesteryear. Thermoset windings are more vulnerable to cracking of the bar groundwall insulation from sudden short circuits, but more forgiving of over-temperature.  Thermoset bars also are vulnerable to cracking during winding installation.

A few cautions and special considerations relative to the thermoset windings are presented below. But O&M of the soft and hard insulation systems are not greatly different.


Nothing can be seen directly on the winding while the generator is in operation, and monitoring/ instrumentation capability is in general low. However, there are still important operational considerations, including the following:

      • Cleanliness. No insulation system likes contamination. On open, once-through cooling-air systems this can be a huge problem, depending on the local atmosphere. The only solution may be constant physical monitoring of contamination build up.

Even on TEWAC generators, contamination will often slowly build up, depending on tightness of the ventilation system, quality of filtering of the inevitable air ingress, and local atmospheric conditions.

On hydrogen-cooled designs, contamination can still occur, particularly over long periods of time, and primarily during outages. Depending on the nature of the material—for example, coal dust or brush-wear carbon—contamination can be an issue.

Cleanliness issues are greater on the rotor windings, but can be a problem with stator windings as well. It is something that efforts should be expended to minimize, but is likely to continue even under the best of efforts.

      • Moisture is a sub-set of cleanliness. While dirt contamination, and correction, can be well understood, moisture contamination, and its correction, may not be. On open and TEWAC ventilation systems, no prevention really is possible beyond avoiding leaking coolers. On hydrogen-cooled units, humidity can still be an issue with cooler leaks or non-functioning dehumidifier equipment.

      • Direct water-cooled stator winding. These systems require constant monitoring during operation to maintain water purity, correct water oxygen content, water pressure, performance of coolers, and detect water leaks.

      • Overload. System demands may call for overload of a generator. These situations should be limited because excessive load increases the electromagnetic forces on the stator winding as a squared function of current (load).

      • Asynchronous operation. Plant personnel may have little or no control in these situations, except during synchronizing. If the condition occurs at low power, no generator damage may occur. But if at high power, and persisting, total destruction of the generator may result.

      • Sudden short circuit. Except during synchronizing, the operator will have no control relative to short circuits. If synchronizing is off only a few degrees, no damage is likely. If a short occurs at 120 deg, maximum torque occurs and couplings may slip and other damage may occur. If the angle is off by 180 deg, maximum forces on the stator winding will occur and the stator winding almost certainly will be destroyed.

Winding temperature instrumentation. The recommendation of the OEM should be followed carefully relative to monitoring and responding to winding temperature readings. This may prevent a minor problem from turning into a major, costly, and long forced outage. 

There is an inclination to want to load the unit based on slot RTD/thermocouple (TC) readings. On indirectly cooled windings these readings are very indirect and inaccurate. Read an amalgamation of the temperatures of the cooling gas, the core, and the bar copper through a thick thermal blanket (the ground insulation). 

On direct gas-cooled windings, cooling gas often is measured as discharged from individual bars. These values are an important and reliable indication of winding performance.

On direct water-cooled windings, many designs measure the temperature of the cooling water from each individual bar, and these readings give a valuable monitoring of winding condition.

But on a large number of water-cooled windings, cooling-water temperature is measured as it is discharged from pairs of bars. Using the discharge water temperature and the corresponding slot RTD/TC temperatures, some limited intelligence can be derived as to winding condition. But interpretation of winding condition based on these temperature readings is complex and inaccurate.


A well-designed, properly manufactured, and properly operated generator is unlikely to require rewind in 30 years of operation, and maybe never. But it will require regular maintenance. The frequency of OEM-recommended maintenance has evolved in the last 25 years.

But regardless of maintenance frequency, and considering the discussion in the root-cause section above, some basic principles apply. They are:

1. No work should be attempted without a qualified crew and supervision onsite.

2.The quality of the work and the rate of progress will be expedited if all necessary tools and equipment are on hand.

3. Item 2 also applies to all needed materials and parts.

These three items can be a huge challenge. In particular, skilled workmen are limited in supply and availability. The availability of capable supervision is limited as well. Also, often those sent onsite, even by the best of OEMs and vendors, are not well qualified. The result can be costly in dollars and calendar time, and in quality of work.

In the case of failure root cause determination, if the lead investigative engineer is not highly skilled, incorrect determinations often have been reached and the result have been hugely negative in quality and cost. 

Actual routine maintenance work constitutes a broad spectrum of often highly skilled effort. The work procedures have been documented by the OEMs and by others, and this documentation is broad and voluminous. No attempt has been made here to further document these procedures; but some special considerations are offered below on a few specific topics.

A good inspection by a qualified individual generally is the best assessment tool of a stator winding. It can reveal important information relative to deterioration associated with most of the conditions experienced.

Thus the importance of a skilled inspection cannot be over emphasized. This inspection will consume time, maybe a full shift or more, but it must be done and done by a qualified individual. Many technical papers have been written on this important topic as well as two books with chapters on maintenance, one by this author and the other by Greg Stone.

Test. Some stator-bar deterioration mechanisms cannot be detected by inspection—for example, general deterioration of groundwall, internal PD, strand or bare-bar vibration or displacement, and strand and group shorts. (Turn shorts on a multi-turn coil will normally be detected by winding failure.) Detection of some of these conditions may be possible by available tests, the most important of the tests being over-voltage test (hipot). Many papers have been written on the subject.

      • Hipot is a powerful test, but is controversial because of possible winding failure, which would likely force a long outage for bar or winding replacement.

      • Power-factor test can be performed, although this test has limited usefulness in determining winding condition, in the opinion of some experienced individuals.

      • Partial discharge and electromagnetic interference (EMI) may also provide some intelligence on winding condition. Expert assistance may be needed to interpret test results.

      • Finally there is the low-voltage insulation resistance test—the “megger” test. Both resistance and polarization index readings should be taken at every convenient opportunity.

Other maintenance considerations:

      • Robotic inspection without rotor removal is widely recommended by OEMs, and these devices can perform rather well in an inspection of stator core areas. They can also do wedge tightness test and ElCid core insulation integrity test. However, a robotic inspection is expensive and may indicate the need to remove the rotor anyway.

      • Re-wedging of the stator winding is recommended where it is not needed. Judgement of wedge tightness can be very subjective—for example, manual test by inexpert individual, improper use of tightness test device, misunderstanding results of tightness device, etc. Re-wedging is expensive and time consuming, and can result in core and/or winding damage. Also, if only the end wedges are loose, only the end wedges should be replaced, not all wedges.

It is essential that a qualified expert is involved in any wedge tightness assessment decision.

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OEM hosts the only US user meeting focusing on V-frame engines

Music City or the Home of Country Music, whichever you call it, Nashville was the site of the 2017 Siemens V-frame Users Group conference, June 12 – 15. The meeting attracted attendees from across the world representing 37 power generation companies. As with previous meetings for this frame, the scope and design of the agenda provided a platform for sharing information among all parties.

Recall that the OEM accepted the financial and technical-program responsibility for the V-frame annual conference several years ago when users opted out of the work required to organize a successful meeting.

This year’s program focused on safety within the plant during all modes of operation, improvements to the reliability and efficiency of the equipment through improved maintenance processes and procedures, improved monitoring techniques (including new digitalization capabilities), and the implementation of new design components and upgrades to the operating systems.

Highlights of the Nashville meeting included:

      • Exclusive user-only discussion sessions integrated into the four-day program.

      • An exhibition that showcased products and services for V-frame engines offered by Siemens and eight vendor partners. The OEM’s display included its repair and service network and technologies, and cybersecurity solutions.

Fleet update. The conference opened with a V-frame fleet update that reviewed performance data for the SGTx-2000E (known previously as the V94.2x and V84.2x) and SGTx-4000F (known previously as the V94.3x and V84.3x) engines. Both fleets showed similar availability and reliability numbers above 95% with the SGTx-2000F units slightly higher than the SGTx-4000E in starting reliability.

Introductory speakers Thomas Schmuck, for the SGTx-4000F, and Bernd Vonnemann, for the SGTx-2000E, got the audience engaged with a review of user questions and comments extracted from previous-conference user surveys and Siemens responses. Both presenters also provided an overview of new product upgrades.

Siemens unveiled its Health Advisor as a part of the company’s expanding digitization efforts. The performance-analysis tool evaluates and prioritizes solutions by cost and availability and displays potential availability and reliability improvements in unit con?guration, diagnostic monitoring, operation, and maintenance. This helps owner/operators select options of greatest value to their plants.

The OEM’s Continuous Plant Monitoring System also was discussed. It remotely monitors units and develops O&M plans based on the data provided. Such monitoring can support operation and maintenance planning and help users manage their plants optimally.

A new field service tool introduced to the group is designed to measure and monitor combustion dynamics to analyze combustion-chamber frequencies and help minimize the potential for acceleration events.

Outage-related safety tools used by Siemens’ field service personnel were discussed next. They include a method for hand-turning and locking of the rotor during various stages of work—such as blade removal. This flexibility can allow sites with silo combustors to flip the combustion chamber in a controlled manner and allow for work to be performed in a different orientation.

Expanded combined-cycle solutions. While most V-frame users are familiar with Siemens products and services intended to improve plant startup metrics, the new Flex-Power Services™ product includes offerings for the entire powerplant, regardless of the equipment suppliers. Example: Services for the heat-recovery steam generator include water-chemistry consulting, inspections, spare parts, and advanced engineering studies to assess the effects of gas-turbine upgrades on the HRSG.

Case studies

Plant optimization experience. Siemens engineers explained how they developed a solution to reduce emissions during “hot starts” (restarts within 12 hours after an engine shut down), while keeping the equipment within the manufacturer’s startup recommendations for internal temperatures, steam pressures, and flows. This was accomplished with the following series of interconnected steps:

      • Tuning.

      • Control logic optimization.

      • Incorporation of logic improvements with CEMS.

      • Personnel training.

Result: A hot-start CO reduction of more than 40% and a startup time reduction of 35%, in round numbers.

Fuel-gas quality. The OEM discussed its view of the effect of the increase in the number of fuel-gas supplies (wellhead gas, shale gas, and LNG) on plant operations. Siemens believes this has led to fluctuating fuel-gas quality nationwide. The speaker said one reason for the quality differences, is that each supplier has its own processing steps which produce varying hydrocarbon and sulfur (H2S) contents.

Siemens’ experience has been that higher hydrocarbons can lead to a variety of problems—including clogged burners from coking. High levels of H2S also can clog burner nozzles and/or contribute to burner corrosion.

For the user, fuel-gas sources and their mixtures should be considered simultaneously; operation outside of the OEM’s fuel specs could lead to operational issues and void warranties. Fuel gases (mainly consisting of alkanes) may have the same Lower Heating Value (LHV) but a different Lower Wobbe Index (LWI). Among other adverse effects, gas with a low LWI has the potential to cause combustion instabilities; gas with high LWI can cause both combustion instabilities and higher NOx emissions.

While the SGTx-2000E and SGTx-4000F designs can operate over a range of conventional and unconventional liquid fuels, an automatic tuning system is available to accommodate changes in fuel-gas quality. The system can include, among other components, a fuel gas analyzer, liquid separation, coalescing filter, fuel gas preheating, aluminized burner and control logic upgrades to automatically adjust for changes in the LWI.

Generator update

Generator Frame Owner Scott Robinson presented research results that concluded that multiple emergency starts from a standstill without lift oil in operation can potentially damage bearings. Inspections are recommended, based on the number of emergency starts.

Robinson also discussed new products and services, developed based on customer inputs, to help reduce outage duration and/or costs—including:

Ultra-low clearance inspection robot equipped with a high-resolution video can eliminate the need to remove rotors for major inspections. Stator slot wedge tightness, in-situ stator core tests, and retaining-ring inspections also can be performed. Field removal still may be necessary based on findings from the robotic inspection.

High-frequency loop test. Siemens has developed tooling and processes to perform the loop/thermographic inspection of stator cores without the need for a plant-supplied 4160- or 6900-Vac (100 to 700 amp) connection.

GVPI. The differences between the current, new-build generator manufacturing process of Global Vacuum Pressure Impregnation (GVPI) versus single VPI generators were discussed next. Since the global VPI manufacturing process was introduced in 1988, Robinson said, more than 1650 stator windings have been delivered and amassed 25.5-million operating hours, plus 322,000 combined start/stop cycles. To date, the frame owner continued, no stator failures attributed to insulation issues on Siemens generators have been reported to the company.

Robinson concluded his presentation with a review of the benefits and reasoning behind the modular design of the GenAdvisor™ Monitoring Platform. These include:

      • The ability to monitor partial discharge, endwinding vibration, inter-turn short-circuit monitoring, and rotor shaft voltage and shaft grounding current.

      • The allowance of concurrent monitoring of multiple generators and connection to the OEM’s Power Diagnostics Center.

      • Providing real-time information about the machine condition during operation (difference to offline tests).


Cyber attacks, past and current, were reviewed with an eye on how new international standards and government policies are helping to address increasing attacks via industrial devices connected to the OT environment. This was followed by a presentation on Siemens comprehensive cyber security portfolio approach to combatting hacking was presented.

A case study of Darktrace technology, which uses artificial intelligence systems to identify and respond to in-progress cyber threats followed. In the presentation, the Siemens team discussed how they attempted to bypass the Darktrace technology by using a registered, properly configured company laptop. As reported, within seconds of connection, the technology recognized the authorized, but unfamiliar, presence of the laptop and logged an alarm.

Within a short period of time, the technology learned that the computer was new to the network but was properly authenticated and was performing the same tasks as the other computers already on the network and lowered the threat severity level to less than 5%.

Engineering session

RCIE update. Siemens reviewed the 100,000-EOH (equivalent operating hours) Rotor Casing Inspection and Evaluation findings aggregated from overhauls of more than 100 SGTx-2000E and 48 SGTx-4000F gas turbines since 2009. Evaluation of these findings produced the following conclusions:

      • Statistical results have shown that, in some cases, there is a potential to reduce the component replacement scope at an RCIE outage.

      • Component-specific recommendations at an RCIE may change based on changing electricity markets and more demanding operating regimes.

      • Inspection programs are updated based on experience and the latest analytical results.

      • Siemens has an established materials ageing strategy designed to determine the mechanical properties of aged materials and work toward extending the RCIE of 2000E baseload units to 200k EOH.

      • Flexibility in timing of the RCIE and adaptation of the outage scope is possible and has been successfully implemented.

Repair update. A discussion of various state-of-the-art and/or patented repair processes available at the Winston Salem Service Center was conducted. In some cases, the repair technology was transferred from the 50-Hz to the 60-Hz design. These processes are focused on improving technologies to meet customer needs and meet or exceed the original component design criteria. Components that can benefit from these processes include:

      • Refurbishment of blades and vanes. Inspection and repair using welding, blending and/or brazing, recoating of the airfoils, and final inspection which now includes rigorous cooling-hole measurements.

      • R1 blade tip repair uses a patented, precise, automated laser welding process for tip findings and an automated laser re-opening process for cooling-air flow. The repair includes an improved coating designed to avoid spallation of the thermal barrier coating (TBC).

      • R1 and R2 vane repairs. Advanced brazing processes reduce scrap rates. These components may also benefit from the implementation of an upgraded TBC coating.

      • SGTx-2000E Si3D components. Updated repair techniques can increase inspection intervals up to about 41k EOH and 1500 starts.

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Reverse Osmosis, Part I: Value proposition, how it works

This is the first part of a five-part series on the design, operation, and maintenance of reverse osmosis systems for powerplants compiled by Wes Byrne, U.S. Water’s consultant on membrane technologies. Parts II through V, listed below, will appear in upcoming issues of CCJ ONsite.

      • Part II: Importance of a pilot study in system design

      • Part III: Mitigating scale formation and membrane fouling

      • Part IV: System operation and monitoring

      • Part V: When to clean, how to clean

Pure water does not exist in nature. All natural waters contain varying amounts of dissolved and suspended matter. Osmosis is the process in which a solvent (water, for example) flows through a semi-permeable membrane from a less concentrated solution to one with a higher concentration. This normal osmotic flow can be reversed (reverse osmosis) by applying hydraulic pressure to the more concentrated (contaminated) solution to produce purified water.  

There is no perfect semipermeable membrane. A small amount of dissolved salt is also able to diffuse through, but this results in relatively low concentrations compared to the feedwater values.  

The benefits of reverse osmosis (RO) technology should be well understood in water treatment for power generation, particularly because of its potential to reduce O&M expenses. For most sources of water, RO will be the least expensive way to remove dissolved salts.  

The term total dissolved solids (TDS) refers to these inorganic salts with some small amounts of organic matter, present in solution. The salts exist as cations (mostly calcium, magnesium, sodium, and potassium) and anions (mostly bicarbonate, chloride, sulfate, and nitrate). These positively and negatively charged ions can pass electrical flow, thus determining the conductivity of the water as a measurement of its TDS concentration. Pure water is a poor conductor of electricity.  

For plants originally built using only ion exchange, adding RO can reduce chemical regeneration requirements by a factor of 20 or more. Complete removal of regenerable systems might even be considered.  

With RO upstream removing the bulk of the dissolved salts, the polishing ion-exchange systems might be economically replaced with service demineralizer beds that are chemically regenerated by an offsite water service company, or they might be replaced by electrodeionization. EDI units use electricity to continuously regenerate their resins.  

Some new and existing plants are now being required to remove dissolved salts from their wastewater streams prior to discharge. RO may perform this role so well that it may even be possible to re-use the water within the plant. The concentrated salt stream remaining after RO treatment might then be more economically hauled to a region that can better handle the environmental effects, or it could be evaporated or discarded in some other manner. The political and regulatory advantages of becoming a zero-liquid discharge (ZLD) facility can offset part of the capital and operating costs.  

But the superior economics of RO operation are only achievable if the system and its upstream treatment components are correctly designed, operated, and maintained.

Pulling a water sample for laboratory analysis is a good start in preparing an RO design. A comprehensive analysis provides data on the metals in the water (for example, iron, manganese, and aluminum), the dissolved salts (cations and anions), the water pH (acidity), and possibly the inorganic total suspended solids (TSS). A measurement of the total organic carbon (TOC) will often correlate with the potential for biological activity.

A TSS analysis reveals the concentration of filterable solids in the water. The concentration of dissolved metals, such as iron, will change in the water sample as they react with oxygen introduced by contact with air. This will cause some of the metals to oxidize and become insoluble. The metals that stay suspended in the water may cause the TSS value to increase significantly with many well-water sources.

Biological fouling solids will not be well represented in the TSS results. The mass of these solids will typically become negligible when the TSS filter is dried prior to weighing for results. The water could be tested for its silt density index (SDI) if the metals are first separated out of the sample. This test will be highly sensitive to the ability of biological solids to coat and reduce the flow rate through its 0.45-micron test filter. Results will correlate with the fouling tendencies of a membrane system.

No analysis is perfect, and water quality can change over time. Even the characteristics of a well-water source will change if the well is relatively shallow.

Sampling methods affect results. Some concentrations will change between sample pull and analysis. Metals may attach to the container’s inner surface. Ammonia and carbon dioxide may degas or carbon dioxide may dissolve from exposure to air. Any of these changes will cause the water pH to change. An accurate water pH is best measured onsite.

Chemical suppliers can use a water analysis to predict how much purified water (permeate) the RO might safely separate from the source before the dissolved salts become too concentrated in the remaining water and form scale within the membrane elements. The water analysis is also used in designing the RO system, both in projecting the purified water quality and in assessing any effect of the salts on system hydraulics.

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Progress reported on development of new IAPWS technical guidance documents

The Power Plant Chemistry (PPC) working group of the International Association for the Properties of Water and Steam (IAPWS) met in closed sessions at the recently concluded IAPWS annual meeting (Aug 27 – Sept 1, 2017, Kyoto, Japan), to advance the development of several new technical guidance documents (TGDs).

IAPWS (pronounced eye-apps) Executive Secretary Dr R Barry Dooley of Structural Integrity Associates Inc, well known to the global power-generation community, called CCJ ONsite’s editorial offices to say that the TGDs in development include the following:

      • Demineralized-water requirements.

      • Effects of air in-leakage into steam/water cycles.

      • Use of film-forming amines and products.

He added that while considerable progress was made on these documents it was not possible to predict release dates at this time. Dooley suggested that powerplant owner/operators review the eight TGDs currently available free-of-charge on the organization’s website. They offer a wealth of practical information on topics such as steam purity for turbine operation, phosphate and sodium hydroxide treatments for steam/water circuits of drum-type boilers, instrumentation for monitoring cycle chemistry, how to measure carryover of boiler water into steam, etc.

A white paper on corrosion-product sampling for plants in flexible operation was presented at the meeting. Also, a symposium on “Water and Steam: Energy Efficiency and Environmental Sustainability” incorporated several presentations focusing on the integration of advanced thermal powerplants into renewable energy infrastructure through coal gasification, CO2 capture, and ultra-supercritical power cycles. Included was discussion on the modeling and design of turbine stages to accommodate wet steam.

By way of background, the primary purpose of the annual IAPWS meetings is to connect researchers and scientists with the engineers who use their information. The free-flowing exchange provides researchers with guidance on topical industry problems and the engineers with the latest research results. Areas of technology addressed by IAPWS of greatest interest to electricity producers are powerplant chemistry, power cycles with CO2 capture and storage, and combined heat and power systems—including district heating.

The conference just concluded attracted 102 scientists and engineers from 13 countries. The next meeting will be in Prague, Czech Republic, Sept 2 – 7, 2018. Dooley reminds that you do not have to be a citizen or resident of a member country (see list on website) to participate in IAPWS activities.

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