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V Users Group 2022: Introduction and overview

By Team-CCJ | November 8, 2022 | 0 Comments

The V Users Group serves owner/operators of both 50- and 60-Hz engines, as noted alongside the logo above. However, at meetings in the US, the focus is on the 60-Hz models of Siemens Energy’s 4000F and 2000E gas turbines. The V fleets here number about five dozen 2000Es and three dozen 4000Fs. Worldwide, the total is about 1000 engines—roughly 80% made by Siemens Energy, the balance by Siemens Energy licensee Ansaldo (50 Hz only).

Siemens Energy has hosted annual in-person conferences here for almost two decades, except for 2020 and 2021 because of Covid-19 concerns. Web meetings filled the void in information transfer until the 2022 meeting at the Hotel Monteleone in New Orleans, August 1 to 4.

This report summarizes content shared with the nearly 50 users participating in the NOLA conference. It is based on notes taken by the editors, Mike Herman, combustion turbine supervisor, Great River Energy (4000F and general sessions), and Scott Wright, technical superintendent, PowerSouth Energy Co-op (2000E), and from presentations by Siemens Energy engineers led by Service Engineering Manager Jonathan Swasey.

Wright is a member of the US steering committee, which also includes Preston Walsh, combustion turbine supervisor at Great River Energy, and J R McKinney, site supervisor, Arkansas Electric Co-op Corp. Communication among V users is facilitated by the organization’s forum, hosted at www.PowerUsers.org.

Dig deeper into the Siemens Energy presentations by accessing the slide decks posted on the OEM’s customer extranet portal at https://cep.siemens-energy.com (users only).

V Users Group 2022

1. Introduction and overview

2. OEM and users discuss product lines, common issues

3. SGT6-4000F Fleet Engineering Update

4. SGT6-2000E Fleet Engineering Update

5. On the minds of users

V Users Group 2022: OEM and users discuss product lines, common issues

By Team-CCJ | November 8, 2022 | 0 Comments

The first in-person meeting of V Users in three years began with a program characteristic of the Big Easy. The only event on the Monday calendar was a vendor-sponsored welcome reception in the early evening, allowing attendees to avoid weekend travel in the ever-crazy post-Covid world. Tuesday began with a social event—golf followed by a group luncheon—giving attendees the opportunity to reconnect face-to-face after about a thousand days of isolation. Product demonstrations, a favorite on this organization’s program, were conducted at the end of the day.

The program picked up steam Wednesday morning with a special session dedicated to the OEM’s progress in commercializing one of the industry’s most advanced gas turbines—the 9000HL. Attendees were told this machine is the world’s largest GT—both in simple-cycle (440 MW at 60 Hz) and combined-cycle (880 MW at 50 Hz) service, as confirmed at US and UK powerplants.

The 9000HL (Fig 1) borrows proven technology from Siemens Energy’s SGT-8000H, SGT5-4000F, and SGT6-5000F, validated over the course of hundreds of thousands of operating hours—including single tie-bolt, Hirth serration/steel rotor, air-cooled four-stage turbine section, and hydraulic clearance optimization.

Eighteen HL-class units reportedly had been ordered worldwide at the time of the meeting. Important features of the new gas turbine include its ability to ramp at up to 85 MW/min and burn gas with up to 50% hydrogen. Combined-cycle efficiency tops 64%.

A one-hour closed session for both 4000F and 2000E owner/operators followed, featuring a presentation by Héctor A Frare, plant manager of Argentina’s Genelba Thermal Power Plant, and by Curtiss Wright on its Readily Accessible Parts Information Directory (Rapid).

Frare shared details on how his team identified and corrected a combustion-chamber issue on Genelba’s SGT5-2000E gas turbines using a methodology developed in-house. That effort earned the plant, owned and operated by Pampa Energía SA, a CCJ Best of the Best Practices Award for 2022, which was presented at the meeting (Fig 2).

Rapid allows all plants subscribing to its service to see what parts are available through Curtiss Wright, updated daily. The virtual community is said to be used by more than 4500 supply-chain professionals to locate, buy, and sell parts for generation, transmission, and distribution assets. Prices are not included in the data. One participant said he heard that Siemens Energy would “support” the system if “multiple” users joined it.

Closed sessions for 4000F and 2000E users were conducted in parallel until lunch, closing out the morning program. Information shared is incorporated into the closed sessions for those engines on Thursday and is covered later in this article.

A general session for all users and Siemens Energy personnel was conducted in the afternoon, plus dinner offsite. Highlights of the technical program follow.

Field service. A broad-brush view of Siemens Energy’s goals regarding tooling, people, and processes to assure the availability of well-trained, capable engineers and technicians to meet customer expectations. Specific technician skills are identified, standardized outage reports explained.

Some recent process improvements include the following:

  • Blade-tip and tile grinders changed from 480 to 120 V.
  • Casing installation guide cones for V84.2 bolts eliminate manual guiding when setting the case.
  • Compressor-blade removal tool.
  • New tile overlays to support V84.3Ax minor inspections.

Compressor bearing damage, caused by an interruption in lube-oil flow, was presented next as a case study that explained how the OEM’s turbine services group corrected the issue. Accident details: dc lube-oil pump came on for nine seconds following a loss of power, turned off for a minute, and then resumed operation. What happened: Elevated active-side thrust-bearing temperatures were experienced.

A hardness check revealed off-spec measurements, suggesting the potential for cracks. The axial bearing surface on the front hollow shaft was machined in-situ to eliminate the hardness. Tooling developed to machine the rotor was a collaborative effort between Siemens Energy personnel in the US and Germany. Positive outcome: Off-the-shelf bearing pads still can be used, but in conjunction with shims to compensate for material loss.

A brief discussion of specific field-service capabilities for V engines—including blower blade tipping, coupling boring machine, collector-ring grinding/polishing, and compressor-seal disc mod for rows 3-5—followed the bearing case history.

Generator update. Recent outages showed a need for further evaluation into stator winding and stator core unplanned outages longer than 10 days to identify their causes. Outages attributed to stator winding/core issues have increased significantly from the January 2017 to June 2022 period compared to January 2021-June 2022.

Siemens Energy’s Global Vacuum Pressure Impregnation (GVPI) technology for generator stators has many advantages according to users sharing their opinions at user-group meetings. However, a big disadvantage of the technology can be the difficulty it causes when a stator rewind is necessary.

This presentation is valuable for the information it shares on the rewinding of generators onsite using Siemens Energy processes for coil removal, laser cleaning, and rewinding with Single Vacuum Pressure Impregnation (SVPI) coils.

Another discussion point during the session: The benefit of dynamic generator cooling control for flexible operation. Reduction of the temperature differential during short standstill durations enables higher load gradients on restarts. Plus, thermal-mechanical stresses on the insulation system are reduced.

The slides on FAST Gen™ generator robotics inspections using new high-resolution cameras should be of interest to plants wanting faster turns on maintenance outages.

Steam-turbine update. Presentation likely will be of value to staff (other than the plant engineer) for its review of the nomenclature/definitions affiliated with turbine performance calculations—including availability, reliability, starting reliability.

Several slides explain Siemens Energy’s TMS (Total Maintenance Services) process. It’s a structured outage planning, implementation, and lessons-learned methodology said to create a win-win partnership between the OEM and its customers. It covers budgeting, communications, planning, identification of resource issues during outages, supply-chain issues, shop machine-time planning, etc.

Two sidebars within the presentation address (1) part kits for fossil steam turbines (HE, KN) to help reduce outage time and (2) upgrade solutions for the SST-5000 to increase efficiency, reduce maintenance cost, and recover degradation.

Finally, the intended benefits of a barrel swap for H steamers are covered. They include outage optimization, efficiency improvement, ease of maintenance, etc.

Omnivise T3000 status update should pique the interest of anyone with controls and/or cybersecurity responsibilities. Migration from ET 200M to ET 200SP is a focus of this slide deck. Options and choices are detailed in the well-illustrated presentation.

A few slides on cybersecurity cover audit awareness and what to do in an audit situation. Primary takeaway: It’s important for Siemens Energy to know whom onsite is responsible for tracking changes for NERC CIP to avoid issues. Contacts in Alpharetta are provided to answer your questions, etc.

Plant flexibility for a changing market. Plant assessments, weatherization, hydrogen co-firing, the value of emerging technologies such as batteries, and solutions for grid stability are all profiled. Two examples of operational flexibility are provided to illustrate how plant owner/operators might reduce unit startup time and cost, increase starting reliability, and improve performance. A case study illustrates a plant upgrade capability assessment with the goal of determining equipment capabilities for proposed upgrades.

CEP and power diagnostics presentation stresses that the Customer Energy Portal is the single gateway for all a plant’s service needs and reinforces the message that Siemens Energy is the owner/operator’s most trusted partner and advisor. The slides walk users through the CEP registration process and illustrate by way of screen shots the unit dashboard, operations KPIs, etc.

Power Diagnostics® services are explained—basic and enhancements. A mobile app with live data feed and visualization connects to key operational indicators and notifies selected personnel of a plant trip. Other capabilities and bells and whistles round out the presentation.

V Users Group 2022

1. Introduction and overview

2. OEM and users discuss product lines, common issues

3. SGT6-4000F Fleet Engineering Update

4. SGT6-2000E Fleet Engineering Update

5. On the minds of users

V Users Group 2022: SGT6-4000F Fleet Engineering Update

By Team-CCJ | November 8, 2022 | 0 Comments

Thursday’s program was intense, with four 90-min sessions conducted in parallel tracks for 4000F and 2000E owner/operators. Each track featured one session on mods and upgrades (M&U), one on engineering, and two closed sessions for user-only discussions. A 30-min skull session allowing Siemens Energy engineers and users to sort out sticking points identified over the four-day conference completed the technical program. A closing reception offsite followed.

The mods and upgrades sessions are particularly valuable for those users experiencing operational constraints. It’s often possible to identify solutions to consider for increasing operating hours, reducing emissions, boosting efficiency and availability, etc, by listening to OEM engineers with relevant experience.

The M&U sessions in each track began with a fleet update, good for benchmarking and for seeing how your plant compares to others in terms of equipment capabilities.

Worldwide, Siemens Energy reported, the SGT-4000F fleet (50 plus 60 Hz) had a 12-month rolling average availability of 96.3%, reliability of 99.1%, and 96.6% starting reliability. At the end of 2021, 53 of the 342 operating 4000F engines were in 60-Hz service—more than half that number in the US. This segment had accumulated nearly 5-million equivalent operating hours (EOH) and more than 83,000 starts by year-end.

The SGT6-4000F began life in the US as the V84.3A frame as the 1990s drew to a close. Over the next several years, improvements extended the basic engine’s capability from about 165 MW to nearly 200 MW in 2013 with the introduction of Service Package 6 (a/k/a SP6)—featuring a thermal performance upgrade and improved hot-gas-path parts. SP6 benefits from earlier upgrades, such as 33MAC (33,000-EOH interval), introduced in 2009 with its improvements in coatings and airfoil geometry and cooling.

Business case for the SP6 includes the potential for a GT power increase of up to 16 MW and simple-cycle efficiency increase of up to 0.7%. A combined cycle could gain up to 21 MW, but with an efficiency increase of only 0.4%. The OEM’s CMF++ (compressor mass flow) upgrade, introduced in 2015, squeezed more power out of the machine at higher ambient temperatures than was possible with just the SP6 upgrade.

Next on the list of improvements was the burner upgrade introduced in 2018 to reduce NOx emissions. Designs of the pilot and premix burners were improved to reduce local flame temperatures; premix flames benefitted from improved stability as well. A reduction in cooling-air consumption in the combustion chamber also contributed to lower average flame temperatures.

Part-load optimization was an important part of the presentation and very practical because this analysis makes use of real site boundary conditions—including current load profile, emissions requirements, and gas-turbine, HRSG, and SCR upgrade capabilities.

There were several slides on fuel flexibility—including guidance on the possible addition of liquid-fuel capability to a unit burning only gas. Next came a look at requirements necessary to accommodate burning varying percentages of hydrogen mixed with pipeline gas.

Siemens Energy’s goal of continuous improvement suggested a progress report on the company’s Advanced Turbine Efficiency Package (ATEP), the development of which is currently focused on the SGT5-4000F engine. Its goal is to increase the efficiency of the current machine by up to 1.5% and boost power output by up to 40 MW. Advanced materials and ultra-efficient internal cooling and sealing of critical parts are among the improvements expected to deliver on the ATEP promise. Four ATEP units have been sold for EU deployment, two for Asia. First fire was planned for summer 2022 at the time of the V users meeting.

Update: In September 2022, the first-time application of ATEP at the Enecogen combined-cycle plant in Rotterdam, Netherlands, was completed as planned. Early performance indications show outstanding values, according to Siemens Energy. Data from the extensive measurement campaign are under evaluation. The OEM expects to present results of its analytical work to the 4000F community shortly.

Engineering. The first presentation in the engineering session described Siemens Energy’s efforts to review its global supply chain with the combined goals of identifying opportunities to improve the lead time for repairs, consolidate technologies, and reduce the strain on critical facilities.

Wet compression got attention for its ability to add up to about 12% power output on demand when ambient conditions are “right.” System was tested at one customer site in June 2021, producing a power gain of 25 MW with 101 gpm of wet-compression flow and a compressor inlet temperature of 90F.

aSMC. Next, experience with Siemens Energy’s Advanced Stability Margin Controller was reviewed. It is intended to boost unit reliability and availability while promoting more cost-effective operation. Seven installations at four customer sites (first in June 2015) are credited with preventing unit trips and unloading events associated with combustion stability issues.

Sliding fuel-gas pressure operation, discussed next, likely is of greatest interest to those users desiring more efficient fuel-gas compressor operation. Attendees were reminded that when gas pressure is too low, operators receive a warning before a gas-turbine trip is initiated. Also, that fuel-gas pressure is not required all the time because of varying operating conditions.

These three possible solutions are described in the presentation:

  • Probabilistic approach. Fuel-gas pressure set points (warning and protection) are established based on “real” ambient conditions.
  • I&C logic upgrade assures reliable operation by automatically adjusting the load set point according to actual fuel-gas pressure.
  • “Smart” fuel-gas compressor control based on gas-turbine load.

Experience with the M77 ceramic heat-shield material followed. It is more durable than the M100 material being replaced in some areas of the combustion chamber. The group was told that SiCerm M77 has a higher resistance to hot-gas erosion and subsequent material erosion during engine operation. It is recommended for the last rows in areas susceptible to erosion. Reduced scrap rates and maintenance effort are among the expected benefits. Less material loss in the combustion chamber also reduces wear and tear on turbine-section blades and vanes.

Rotor-Casing Inspection and Evaluation is always a topic of interest at V user meetings. The speaker stressed that RCIE is a customized approach based on unit operating history. Case studies were offered for baseload engines with up to 200,000 EOH and less than 3000 starts and for peakers with less than 6000 starts.

Presentation reviews components affected by long-term operation, the damage mechanisms expected (creep, etc), and fleet experience. Then current solutions for repair/replacement of affected components are identified along with a look at solutions under development.

One of the conclusions of Siemens Energy’s work: “Statistical results have shown lesser need for replacement of casing and rotor components for baseload engines while experience with peaking engines is still limited.” The speaker continued, saying that with changing markets and more demanding operating regimes, findings (and the need for component replacements), may change; also, that the OEM’s programs are updated based on experience and the latest analytical results.

Brownfield engine exchange (BEX) is on the Siemens Energy agenda at many user-group meetings. The idea is to increase powerplant efficiency and operational flexibility, and reduce emissions, by replacing an existing engine with a new one, perhaps performing selected upgrades on other equipment in parallel. The “carrot”: Less than the cost of a completely new plant.

The OEM’s global BEX program has been successful, with 40 units participating in 10 countries—21 of them in Taiwan. BEX is not specific to the SGT6-4000F. In fact, there are no upgrades of this frame on Siemens Energy’s reference list. However, four V94.3x machines have been replaced with 50-Hz 4000F engines.

Exchanges have been done on SGT6-5000F, W501FC, W501D5A, 501FD3, V64, V93, V84.2, and M701F gas turbines. Plus, general plans were presented by the speaker for SGT5-4000F replacements at plants with GE 9FA and Alstom GT26 machines.

In the US, three exchanges have been made—one a SGT6-2000E replacing a V84.2 engine (Figs 3 and 4) and two SGT6-5000Fs replaced with a later model of the same frame. The first enabled PowerSouth Energy Co-op’s McWilliams Power Plant in Covington County, Ala, to boost the output of its mid-1990s SGT6-2000E(2) from 102 to 114 MW by swapping it out with a new late-model SGT6-2000E(8).

Improvements in the engine’s gross simple-cycle efficiency from about 31% to 35% over the years made replacement more economically attractive than continuing to change parts and do regular maintenance upgrades. Plus, NOx emissions were reduced to 10 ppm from 13-16 ppm.

Major work on this project, the first-of-its-kind here for the OEM, included the design/manufacture/installation of a new intermediate shaft between the turbine and generator, and modifications to the air-inlet house and exhaust diffuser—in addition to replacing the gas turbine, of course. The original generator remained as it was.

Paint update. Final topic on the program was a repair paint, in validation at the time of the conference. Use of the two-component epoxy resin was to address leading-edge coating abrasion on the first few compressor stages. The coating can be applied during a minor inspection.

V Users Group 2022

1. Introduction and overview

2. OEM and users discuss product lines, common issues

3. SGT6-4000F Fleet Engineering Update

4. SGT6-2000E Fleet Engineering Update

5. On the minds of users

V Users Group 2022: SGT6-2000E Fleet Engineering Update

By Team-CCJ | November 8, 2022 | 0 Comments

The fleet update at the front end of the SGT6-2000E breakout sessions reported the following facts:

  • The 50-Hz units in the 2000E family outnumbered the 60-Hz units 223-105 based on end of 2021 data.
  • The 12-month rolling average availability for the 60-Hz fleet was 96.4% based on July 2021 data. Reliability was 98.8% at that time, starting reliability 98.7%.
  • The combined fleet (50 plus 60 Hz) had recorded nearly 36 million EOH and nearly 500,000 starts by midyear 2021.

A summary slide on inner-casing lifecycle improvements pointed to the value of field feedback data in helping to maximize maintenance intervals. Nearly a dozen and a half SGTx-2000E turbines were said to have been allowed to extend maintenance intervals because of this effort.

Turbine-blading update showed 180 units worldwide operating with Si3D™ blading. Experience of 50-Hz units with first- and second-stage airfoil improvements extended to nearly 4 million EOH and 50,000 starts. For 60-Hz machines, the numbers were 1.9 million EOH and nearly 14,000 starts.

Dual-fuel conversion was an M&U topic as it was in the 4000F session, with the same basic considerations applying to both frames. Additionally in this session, users with systems that have been inactive or not used for a long period of time were advised to review their liquid-fuel infrastructure to be sure it is operational and available if needed.

Secondary fuels reviewed included fuel oil, naphtha, condensates, kerosene/Jet A, biodiesel, and methanol. The requirements for any one may be slightly different than for the others so this should be taken into consideration during your asset evaluation.

Hydrogen was part of the alternative-fuels discussion for H2 concentrations in natural gas up to 30%. The speaker said a test site for a fuel mix of up to 15% H2 is in development. Hydrogen would be stored separately onsite and injected via a mixing skid upstream of the GT control valves. These are just first steps for Siemens Energy, which has committed to 100% hydrogen capability for its GT fleet.

Ultra-fast-start modules were the next topic with the goal a 5-min interval from turning gear to base load for a reserve GT in Europe. If integrated into a combined cycle, a bypass stack is necessary. Another case study looked at halving that interval to 2.5 minutes.

Final topic on the M&U program was a design review of Siemens Energy’s cooling-air reduced (CAR) combustion chamber, nine sets of which are in operation now, with 12 expected by year-end. CAR’s many features—including optimized flame-tube bottom design, optimized tile holder, enlarged ceramic heat shield, and optimized mixing casing—contribute to a 20% reduction in NOx emissions (8 ppm today). Early inspection feedback is excellent.

Engineering. First subject on the 2000E engineering agenda was on the OEM’s improvement to the fourth-stage divided seal ring, available for all engine configurations: 50 and 60 Hz standard and Si3D. The purpose: Reduce wear between the vanes and seal ring.

The upgrade had been implemented on 113 units (37 60 Hz) by the time of the meeting. Proper installation was stressed to prevent recurrence of wear. Positive result: No increased wear or forced outages attributed to seal-ring wear had been reported by owner/operators with the latest design.

RCIE was the next topic and some of the same material covered in the 4000F session above was repeated here. Specific recommendations for this frame are the following:

  • Field experience generally has presented no significant findings for most rotor and casing components between 100k and 150k EOH. Drivers for destacking include inner-casing maintenance, and replacement of the center hollow shaft.
  • Recommendation for NDE at 3000 starts remains for rotor components. Service time has been extended for some machines following detailed unit analysis. Guidance on when to replace specific components on peaking engines is provided in the presentation.

A few thoughts came next on improvements to the turbine exhaust liner and diffuser to mitigate the maintenance impacts of findings reported by the user community on some units. A sketch included in the presentation identified as areas of possible concern: cracks at the circumferential weld at the engine exit, wear at the casing liner cover, cracks in the two- and four-wave compensators.

BEX and other repeats from the 4000F program. As hinted earlier, Siemens Energy rarely misses an opportunity to talk about the advantages of its Brownfield Engine Exchange offers some owner/operators. So that topic was on the 2000E program as well. Same for the compressor repair paint, wet compression, and sliding fuel-gas pressure operation presentations.

Repairs for restoring GT, ST, and generator bearings of spherical saddle design was an important presentation for anyone so challenged. Repair techniques—including metal-spray and arc-spray restoration—are covered. Techniques for the rework of axial-thrust load surfaces are included. Meaningful illustrations are included.

Mixing casing. Repairs to correct contact and material loss at the interface between the mixing casing and lower flame tube were discussed next. Bear in mind that thinning of the mixing casing scallop may lead to liberation of thinned material. A trial fix using a repair coupon was reported on. Next steps include improving coupon geometry, development of a double-scallop coupon, and application of hard-facing.

CVC3. Some mature SGT6-2000E engines have Compressor Vane Carrier 3 configurations which include cover plates and anti-rotation pins. The latest word for units with cover plates: Forget the anti-rotation pins. This should facilitate maintenance and reduce outage duration. Instructions are available on how to plug the holes.

Lift-oil hose. Last on the agenda was a look at an improved lift-oil hose that uses industry standard hardware—complete with drawings. The potential benefit of this upgrade, applicable to all existing units and standard on new, includes longer hose life (10 years).

V Users Group 2022

1. Introduction and overview

2. OEM and users discuss product lines, common issues

3. SGT6-4000F Fleet Engineering Update

4. SGT6-2000E Fleet Engineering Update

5. On the minds of users

V Users Group 2022: On the minds of users

By Team-CCJ | November 8, 2022 | 0 Comments

The SGT6-4000F and SGT6-2000E owner/operators each met in private for about five hours on the third and final days of the conference to cover topics not addressed by the Siemens speakers and to compare notes on their experiences with the OEM and other vendors. Brief notes on subjects discussed, best practices, lessons learned, experiences both good and bad, etc, are presented below to provide a flavor of what others are thinking/doing.

User characterization. A recent poll of V User Group meeting attendees provided the following insights:

  • A typical meeting will have an audience with about 30% first-timers.
  • Most important topic on the minds of users is performance improvement (mentioned by 43% of attendees).
        • Next came parts availability (a concern of one-third of the attendees).
        • Operational flexibility (24%), outage interval extension (24%), and availability of technical support (22%) followed and were statistically equal in degree of importance.
        • Last was emissions improvement (3%).
  • HEPA filters are installed on gas turbines at 30% of the plants represented at the meeting.
  • As for age of electronics/controls for SES/SFC: 41% less than 10 years, 53% 10-20 years, and 6% more than 20 years. More than 60% of the users have been told their controls face obsolescence, but one-third are not satisfied with their options.

SGT6-4000F

Air inlet section. One user reported plugging of pre-filters in cold weather by hoar frost. Suggestion: Use leaf blowers as a stop-gap solution before the unit shuts itself down. Brief comments on pre-filters continued with some attendees touting disposable filters, others cleanable. Change-out of pre-filters was said to take two to three hours. The OEM reportedly told one plant not to install pre-filters in the winter.

Inlet-guide-vane fluctuations were said by one user to increase EOH, likely attributable to dynamic load. His site operates multiple units on crude oil and all are affected. Recommendation: Arrange for Siemens tuners to visit the site. A short discussion related to IGV performance improvement for load increase without fuel increase ensued.

With several upgrades ongoing at one site, staff wanted to be sure all drawings and manuals were updated. Suggestion was to put this in the contract and withhold 10% payment until updates were verified.

Wet compression discussion rambled a bit: filters failing prematurely, limitations on run time when compressor blades are uncoated, erosion not a concern but corrosion is, borescope annually to determine airfoil impacts if any.

Turning-gear talk among attendees revealed issues with the dog-bone seal on the turbine bearing at one plant, plus the need to check and adjust lift-oil pressure, and hose condition, periodically. Nothing lasts forever.

Unit trips (three times in one weekend) were traced to a 20-year-old transducer for a generator protection relay. Next, a vibration issue emerged. Siemens was said to have recommended a rotor de-stack. A user recommended that generator fan blades be checked tight.

Fire-suppression agents and systems piqued audience interest as they have at many other user-group meetings—in-person and virtual—over the last several years. Suppression agents harmful to health and the environment, as well as regulations governing their use (now and in the future), were reviewed. CO2 was touted as being an inexpensive upgrade for some, water-mist systems challenged for the inspections and hardware they require, etc. Discussion even touched on buyback programs for regulated gases. Likely a determining factor in your decision-making will be what your plant’s insurer is willing to cover.

User interest in turbine services capabilities was in evidence. There were brief discussions on blade tip grinding (allow two to three hours for one disk on person said), collector-ring grinding, and the capabilities of a coupling boring machine.

Supply-chain challenges and approaches filled air time as owner/operators shared ideas and experiences regarding the purchasing of castings in advance of need, improvements to forecasting process and tools, lead-time optimization, new-stock optimization, impediments to international business, etc.

Recent outage findings included the following:

  • Generator stator rewind will change from GVPI to SVPI unless performed at site.
  • Laser cleaning tool is used during an onsite stator rewind.
  • A dynamic cooling mod is available for generator cooling system.
  • One plant reported cracking on both generator retaining rings during a recent inspection.
  • FAST Gen does not include retaining-ring inspection and testing.
  • Hybrid rotating grid stabilizer conversion solution: integrate a SSS clutch.

T3000. Most current version is 8.2 SP4, which will be supported until 2028; Version 9.3 is scheduled for release in 2023.

Lifecycle of ET200M ends in 2023, although at least one user said Siemens would provide spare-part replacement modules for 10 years beginning in 2023. There was discussion of the benefits of making the ET200M modules obsolete, although some users were clearly frustrated for having to replace them with newer equipment and not sold on the benefits. This segment of the audience stressed the desire for Siemens to justify its position.

Lead times on control-system parts are becoming a concern, some participants said. The result: Plants are forced to have spare parts on hand for all control-system components—including Vibrometer.

SP6 was batted around in discussion, including burner upgrades, downstream SCR, fuel-gas preheat, etc, but the information provided was much the same as Siemens Energy had presented in its session on the 4000F.

A Vibrometer D3000 upgrade was discussed. It was said that communication is sometimes lost between the D3000 and controls and when that happens a proven fix is to disable dynamic monitoring, pull the card, and then reinsert. One user said he was looking at upgrading the plant’s BN3500 rack to Vibrometer’s, noting that the existing cables and probes can be retained.

Fuel-gas system issues generated vibrant discussion. Here are some of the points made:

  • Parts received from the gas-valve supplier were unsatisfactory. Specifically, cage not manufactured correctly, with holes too far down on the radius, causing the unit to trip on startup. Temporary solution was to reinstall the old cage.
  • Blowbacks were a problem at more than one plant. One user said they were occurring about every four starts. A fire blanket was cut up and tied to piping to mitigate effects.
  • A recommendation was made to test-fire ignitors. Suggestion was to turn off lights in the enclosure when doing this. Ignitor mods to consider: resistor and mounting. Parts challenges? Someone mentioned that spark-plug ignitors share some parts with snowmobile spark plugs.

Turbine section. Discussion focused on plant experiences with OEM alternatives for V84 outage and parts support. No one in the room could recall having full-service experience with any third-party supplier, suggesting that colleagues might want to discuss that possibility with MD&A, Sulzer, and EthosEnergy Group.

A general discussion touched on the following:

  • Tile inspection. Observation: Interesting how different inspectors fail different amounts of tiles.
  • Rotor de-stacks have been done at some plant sites. Normally, Siemens Energy does this work in its shops.
  • Missing studs in the exhaust diffuser promote insulation liberation. You certainly don’t want that material in the SCR. A temporary solution when insulation goes downstream might be pumpable insulation.
  • Other topics discussed included replacement expansion joints, windows for switchgear, leak-checking of TEWAC heat exchangers, generator flux-probe testing, transformer issues, failure to start, automatic-drain problems with knock-out drums in fuel-gas systems, benefits of performance heaters for fuel-gas systems, replacement of peckerhead-style exhaust thermocouples, and much more.

Insurance company requests. Add fire suppression capability to a hydrogen-cooled generator pit, install fire protection in the PCC sub floor, develop emergency operation procedures—such as for low lube-oil pressure, conduct a cybersecurity deep dive, and install FyreWrap® around dc lube-oil pump wiring.

SGT6-2000E

Fuel-gas control. Several users said they had, or were planning to, upgrade their fuel-gas controls with Rexa Inc equipment because the Argus® valves (Flowserve) installed were problematic.

CVC 1. Safety issues were reported with this generation of compressor vane carriers. Solutions identified: Install a safety bracket (viewed as a temporary fix) or replace.

Combustor issues were traced by some to changes in gas quality causing liquid carryover. Sulfur has been found plated-out in gas lines (hard, light-gray color); plus, there have been reports of heavy hydrocarbon buildup in those same lines. One reason is believed to be receipt of fracking gas instead of the traditional Gulf gas. Suggestion: Heat the incoming fuel to 165F.

Dual-fuel operation. Issue of greatest concern is fuel quality, with some users challenged during commissioning of fuel-oil systems after major outages. Most users reported having upgraded successfully to HR3 burners from H burners.

Emissions control. Issues with NOx steam injection line reported. Recommendation: Keep water in the line during light-off to reduce the risk of distorting/melting the line.

Turbine-section comments were generally positive, such as:

  • Blades robust. One user with 32k first-stage blades is at more than 50,000 hours and still running. Another is targeting 46k EOH; no concern with starts. Limiting factor is likely the transition rings, which can be patch-repaired to limit outage time.
  • Most users agree that blades can handle two repair cycles with the repair process the determining factor.

Inner-casing cracks. Some users just monitor condition; others weld-repair at outages.

Tiles. Horizontal cracks are not of concern to most users, but vertical cracks are examined closely. Some users reported using Sulzer for tile work; others their own techs with Sulzer support for condition evaluation.

Outage planning. Siemens Energy TMS (Total Maintenance Services) process used to start 18 months prior to the planned outage, now two years. Group experience regarding auxiliaries during a major: Change out all valves at third major; all shut-off valves sent to Millennium Power Services for overhaul, actuators to Paragon Technologies. Tip: Borescope three-way valves after maintenance to be sure they are installed correctly.

Second-major recommendations: Don’t replace flame tubes, repair tiles and tile holders, check F rings and bezel rings, refurbish thermal barrier coatings on hot plates and bezel rings.

V Users Group 2022

1. Introduction and overview

2. OEM and users discuss product lines, common issues

3. SGT6-4000F Fleet Engineering Update

4. SGT6-2000E Fleet Engineering Update

5. On the minds of users

Best of the Best 2022: Genelba identifies, corrects combustion-chamber issue using methodology created by plant personnel

By Team-CCJ | November 8, 2022 | 0 Comments

Genelba Thermal Power Plant, owned and operated by Pampa Energía SA, is a 1253-MW, gas-fired facility with two 2 × 1 SGT5-2000E-powered combined cycles, located in Marcos Paz (Buenos Aires), Argentina. Plant manager is Héctor A Frare.
The first combined cycle began operating in 1999. It was repowered in October 2020 and today the gas turbines are rated 223 MW each, the steam turbine 238 MW. The second combined cycle is comprised of a 182-MW gas turbine called Genelba Plus, installed in 2009 and repowered in June 2019, and a 188-MW gas turbine installed in 2019. The 199-MW steam turbine was commissioned in July 2020.

The plant’s challenge was to develop a means for monitoring critical equipment to maintain Genelba’s availability and reliability at the facility’s traditional high levels.

The solution required creating and implementing a methodology for gathering information from multiple online and offline sources, developing key performance indicators (KPIs), and analyzing them under different boundary conditions as illustrated in Fig 1.

After identifying the available information resources, a process was developed and executed to answer the following questions, which were then programmed in an automatic execution algorithm in PI:

  • Is the instrumentation proper and in good working order? Are additional sensors needed to monitor other equipment failure modes?
  • Baseline definition (normal behavior).
  • Does the signal change over time?
  • Are there alarm signals coming from that system?
  • What were the equivalent operating hours at the time of analysis?
  • Is there a correlation with other variables?
  • What consequences does the abnormality have?
  • How are the measurements on the other machines?
  • Is the system showing signs of failure—for example, is there an increase in the number of work orders?

Genelba’s Best Practices entry form offered the following example of how the plant’s program works using the KPI MBMHUM1.1. Four binary signals from the control system are activated when the humming exceeds 20 and 30 mbar. (Recall that the plant’s SGT5-2000E gas turbines each have two combustion chambers.) The indicator counts the total time that both cameras were exposed to humming greater than 20 mbar and greater than 30 mbar in the last 15 days.

Presenting the information in this manner allows staff to analyze, for example, whether the machine was exposed to higher levels of humming after an inspection (where pilot valve control could be intervened). It also affords a comparison between both combustion chambers.

Fig 2 shows the KPI dashboard developed in OSIsoft’s PI Vision for the continuous monitoring of the combustion chambers. Using the methodology illustrated, and keeping in mind equipment failure modes, the plant’s technical experts are able to determine if it’s necessary to add more instrumentation to detect important failures early.

Continuing with the combustion-chamber example, staff found that addition of accelerometers could possibly identify conditions conducive to impending burner malfunction—such as the possible loosening of burner hold-down bolts. Fig 3 shows one of the sensors attached to a base that had to be welded to each burner to dissipate heat so the sensor would work within specifications.

The accelerometer is wired to a high-frequency processor box that transmits the information via the plant’s industrial WiFi network to the processing server.

In sum, 18 accelerometers were installed on each engine. Information is sent to the PI system, from which a comparative dashboard was developed by sensor, camera, and gas turbine, with the goal of characterizing the cameras and determining abnormal behavior—because personnel did not have reference limits for these new measurements.

Fig 4 shows the board developed in Microsoft’s Power BI, an interactive data visualization software product, for tracking acceleration measurements. The graph at the upper left shows information from all the selected sensors discriminated by turbine; that at the upper right from selected sensors discriminated by turbine and sensor. The lower graphs show trend values, humming values, and vibrations per harmonic, respectively.

Here’s an example of how the development effort described above works: One of the indicators monitored—it infers thermal balance between combustion chambers—detected a deviation in GT22 of more than 15 deg C with respect to the allowed maximum. Staff analysis determined that fuel flows to one of the combustion chambers required correction.

Technical experts believed the anomaly might have been caused by a deformation in the right combustion chamber of GT22 that allows air to bypass the compressor, cooling it. Such a thermal imbalance over time can stress the first row of rotating blades, with the risk of fracture of some, and consequent damage in later stages.

The temporary fix implemented was to replace a gas orifice plate to redirect more flow to the combustion chamber experiencing deformation, thereby thermally compensating the effect. A permanent repair was planned for the next GT minor inspection.

The benefits of having the intel and implementing a temporary fix included the following:

  • Staff could detect wear on the camera and plan resources and work in advance of the next planned inspection. Without such preparation, personnel believed an outage of at least five days would have been required to correct the problem, at an estimated cost of about $250k/day.
  • Modifying the orifice plate in the gas pipe avoided progressive damage to GT22 airfoils and mitigated the risk of catastrophic failure.
  • The possibility of improving instrumentation to measure humming values associated with GT protection more precisely was identified based on another of the developed indicators.

 

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By Team-CCJ | November 6, 2022 | 0 Comments

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The growing importance of Frame 5 inspections

By Team-CCJ | November 3, 2022 | 0 Comments

Background: Legacy Turbine Users Group

The Legacy Turbine Users Group (LTUG), formed by Power Users earlier this year to facilitate the transfer of knowledge among members of the Frame 5, 6B, and 7EA Users Groups, greatly benefits owner/operators of these engines. With the number of experienced O&M personnel in decline because of staff reductions and retirements, it makes good sense to aggregate the talent on both the user and supplier sides for all to share—especially given that these GE engines have “common” elements.

LTUG’s first annual meeting was conducted as part of Power User’s Mega Event, Aug 29 – Sept 1, 2022, at the San Antonio Marriott Rivercenter, which attracted more than 350 owner/operators. Several reports on that conference are forthcoming. Here the editors review the backgrounds of the Frame 5 and Frame 6B organizations and salute BASF Geismar for its work in increasing the reliability of boiler drum-level controls. The 7EA Users Group, serving owner/operators of 7B-EA gas turbines, will be featured in the next issue of CCJ ONsite and include recent best practices from that fleet.

The GE Frame 5 is likely the most popular gas turbine ever produced for power and industrial applications. The first unit in this model series shipped 65 years ago from the OEM’s Schenectady (NY) shops and Frame 5s are still being built today—albeit by manufacturing associates abroad and at ratings about two and a half times those of the 12-MW models installed in the late 1950s and early 1960s.

Although more than 3000 of these machines have been sold over the years, the editors cannot find records of any formal user group meeting conducted since the millennium with the Frame 5 as its focus. Power Users believes this engine has value as a critical peaking asset and supported the launch of the Frame 5 Users Group as part of its 2022 Mega Event.

Frame 5 Users Group Steering committee, 2022

Josh Edlinger, Eastern Generation
Shannon Lau, Suncor Energy
Logan Quave, Indorama Ventures

Frame 5s are, in a manner of speaking, “beasts,” and many don’t run very often. But that doesn’t mean they are immune to the problems found in more advanced machines that operate regularly and at higher temperatures.

Mike Hoogsteden, director of field services for Advanced Turbine Support, an industry leader in the conduct of borescope inspections to determine the condition of gas turbines and other assets, told the editors that a large majority of Frame 5 operators don’t perform semi-annual inspections, as do the large gas turbines running regularly. Depending on the run profile, a full compressor/combustion/turbine borescope inspection every one to two years probably makes best sense for many of these units.

Also recommended, and depending on unit designation, is an eddy-current inspection of all IGVs (fixed and variable) and the stage S0 or S1 stator vanes (first row of vanes). The EC scan would identify any cracks in the vanes.

Another location for a careful inspection is at the ninth-stage hook-fit, where component separation can be an issue. Recall that the thin ligament at the 10th-stage extraction slot forms the hook that holds one side of the ninth-stage stator vanes in place. It is susceptible to cracking that could allow one or more vanes to work free and go downstream causing major compressor damage (Fig 1).

If you are unfamiliar with how best to prepare for a Frame 5 borescope/EC inspection, contact your service provider. A couple of things Hoogsteden recommends: (1) For the combustion section inspections, provide access to every other one of the 10 cans via removal of the fuel nozzles; (2) gain access to the second row of turbine blades by availing access into the stack.

Hoogsteden then provided a flavor of what might be found with a borescope by sharing findings from three recent Frame 5 inspections. Engine A was a Model M, B a Model P, and C a Model N.

Engine A. The inlet section was found in relatively good condition, but there was rust and debris on the inlet floor. Inspector’s recommendation was to prep the floor for a two-part epoxy coating capable of withstanding regular water immersion.

The compressor section, accessed through the inlet bellmouth initially and later through the removed upper case, revealed partial liberation of the IGV tip shroud, causing significant downstream damage (Figs 2 and 3). An engineering review was recommended before repairing and restarting the unit.

The combustion section was in good condition; water wash residue was visible on the hardware. Combustion liners were accessed through the fuel nozzles in cans 3 and 7.

The turbine section, accessed via the combustion liners, also was in good condition. The exhaust section was not inspected.

Engine B. Rust and debris was found on the inlet floor of this unit as it was in Engine A. Inspectors accessed the compressor section through the inlet bellmouth, finding two stage S0 stator vanes had liberated at the 6 o’clock position (Fig 4) along with one R9 rotor blade (Fig 5). Result: Extensive damage throughout the compressor.

Combustion liners were accessed through the fuel nozzles, the turbine section via the liners and exhaust section. The combustion section was found in good condition except for some debris found in the combustion-cap air slots (Fig 6). Impact damage and material loss was suffered by a majority of the first-stage turbine buckets (Fig 7). Condition of the exhaust section was “good.”

Engine C. Access (1) to the compressor section was through the inlet bellmouth and the ninth-stage air extraction, (2) to the combustion liners via fuel nozzles and crossfire tubes, and (3) to the turbine section by way of the combustion liners and exhaust section.

Impact damage was found at the leading edges of 13 R0 rotor blades (Fig 8), the debris causing minor damage throughout the compressor. Stator-vane hook-fit separation was evident in stage 9, where the gap between the case material and stator vanes ranged from 32 to 68 mils (Fig 9).

The combustion and turbine sections were in good condition; however, there was inner-barrel corrosion with material loss and cracking in the exhaust-section diffuser vanes (Fig 10).

Frame 6B users draw on over 40 years of operating experience

By Team-CCJ | November 3, 2022 | 0 Comments

Background: Legacy Turbine Users Group

The Legacy Turbine Users Group (LTUG), formed by Power Users earlier this year to facilitate the transfer of knowledge among members of the Frame 5, 6B, and 7EA Users Groups, greatly benefits owner/operators of these engines. With the number of experienced O&M personnel in decline because of staff reductions and retirements, it makes good sense to aggregate the talent on both the user and supplier sides for all to share—especially given that these GE engines have “common” elements.

LTUG’s first annual meeting was conducted as part of Power User’s Mega Event, Aug 29 – Sept 1, 2022, at the San Antonio Marriott Rivercenter, which attracted more than 350 owner/operators. Several reports on that conference are forthcoming. Here the editors review the backgrounds of the Frame 5 and Frame 6B organizations and salute BASF Geismar for its work in increasing the reliability of boiler drum-level controls. The 7EA Users Group, serving owner/operators of 7B-EA gas turbines, will be featured in the next issue of CCJ ONsite and include recent best practices from that fleet.

The 6B is a familiar GE gas turbine in cogeneration systems at process plants where staff typically is challenged to keep legacy assets operating on a low O&M budget, often without the support of a corporate engineering staff. The presentations and discussions at annual meetings of this users group provide know-how and proven solutions to help owner/operators achieve that goal.

These engines also are found in simple- and combined-cycle arrangements for electricity production only. In fact, the first Frame 6 (Model A, which preceded the 6B) was commissioned July 15, 1979 at Montana Dakota Utilities Co’s Glendive Power Plant. The 41-MW, dual-fuel-capable, simple-cycle unit was still in service about a year ago.

2021 conference in review. No formal user presentations were on the 2021 virtual conference agenda. Rather, owner/operators shared their experiences via four roundtable discussion forums: compressor, I&C, combustion, and turbine, each chaired by a member of the steering committee. Copies of the slide decks and an unedited recording of each discussion are available to registered users in the Frame 6B section of the Power Users website. Click on the “Conference Archives” tab. These are valuable training aids for O&M personnel, both experienced hands who might benefit from a refresher as well as newcomers.

Steering committee, 2022

Michael Adix, Motiva Enterprises
Kevin Campbell, Chevron
Robert Chapman, Chevron
Jonathan LaGrone, Formosa Plastics Corp USA
Doug Leonard, ExxonMobil Technology and Engineering
Mike Wenschlag, Chevron, El Segundo Refinery
Zahi Youwakim, Indorama Ventures, Port Neches Operations  

Steering committee advisers:

Jeff Gillis, ExxonMobil retired
John F D Peterson, BASF retired  

Highlights of the compressor roundtable include the value of hydrophobic HEPA filters to engine performance, the need know the nature of blade deposits and before you water-wash to avoid pitting corrosion, and when to/when not to fog.

A highlight of the I&C presentation was what to know before you consider upgrading from a Mark IV to Mark VIe control system. It’s a big undertaking, despite what you may have heard to the contrary. Space constraints may be a challenge difficult to overcome.

Support documentation focusing on O&M safety available from the OEM is highlighted in the sidebar.

Two vendor presentations also are available on the Power Users website in the Frame 6B section, both concerning generators:

  • “Generator cycling concerns,” W Howard Moudy, National Electric Coil. Presentation’s primary intent is to develop awareness of cycling-related concerns and affected components. It covers speed cycling, which involves taking the unit from standstill or turning-gear speed to full speed and back (one speed cycle), and load cycling, the fluctuating generator output required to follow demand. Also covered are the opportunities for monitoring, maintaining, and solving problems.
  • “When a robot won’t fit,” Jamie Clark, AGT Services Inc. Focus is on generator minor inspection techniques and their limitations.

The third leg of the Frame 6B conference stool, conducted by the OEM on the second day of the meeting, consisted of four sessions, each running about 30 minutes. The subjects: Covid experience, condition-based parts management, decarbonization, and compressor and hot-gas-path Q&A.

To dig deeper, access the presentations on the GE Power Customer Portal (formerly MyDashboard). The new user interface features enhanced navigation to keep users informed on the disposition of TILs, provide the ability to follow your outage from planning to closeout, track parts orders, and retain reports and other documentation of importance—such as O&M manuals—in one location. Register for access at https://Registration.gepower.com/registration. To log in, go to https://mydashboard.gepower.com/dashboard.

Safety TILs affecting 6B gas turbines

TIL-2101, Modification of manual lever hoist for safe rotor removal.

2044, Dry flame sensor false flame indication while turbine is offline.

2028, Control settings for GE Reuter Stokes flame sensors.

2025, GE Reuter Stokes FTD325 dry flame sensors, false flame indication.

1986, Braid-lined flexible metal-hose failures.

1918, 6B Riverhawk load-coupling hardware and tooling safety concern.

1838, Environmentally induced catalytic-bead gas-leak sensor degradation.

1793, Arsenic and heavy-metal material handling guidelines.

1713, 6B, 6FA, 6FA+E, and 9E false-start drain system recommendations.

1709, 6B load-coupling recommendations.

1707, Outer-crossfire-tube packing-ring upgrade.

1700, Potential gas-leak hazard during offline water washes.

1633, Load-coupling pressure during disassembly.

1628, E- and B-class gas-turbine shell inspection.

1612, Temperature degradation of turbine-compartment light fixtures.

1585-R1, Proper use and care of flexible metal hoses.

1577, Precautions for air-inlet filter-house ladder hatches.

1576-R1, Gas-turbine rotor inspections.

1574, 6B standard combustion fuel-nozzle body cracking.

1573, Fire-protection-system wiring verification.

1566-R2, Hazardous-gas detection system recommendations.

1565, Safety precautions to follow while working on VGVs.

1557, Temperature-regulation valves containing methylene chloride.

1556, Security measures against logic forcing.

1554, Signage requirements for enclosures protected by CO2 fire protection.

1537-1, High gas flow at startup—Lratiohy logic sequence.

1522-R1, Fire-protection-system upgrades for select gas turbines.

1520-1, High hydrogen purge recommendations.

1429-R1, Accessory and fuel-gas-module compression-fitting oil leaks.

1368-2, Recommended fire-prevention measures for air-inlet filter houses.

1275-1R2, Excessive fuel flow at startup.

1159-2, Precautions for working in or near the turbine compartment or fuel handling system of an operating gas turbine.

Frame 6B Best Practice: How BASF Geismar increased the reliability of boiler drum-level controls

By Team-CCJ | November 3, 2022 | 0 Comments

Most drum-level control systems employ 3-element logic, with feedback to the controller on drum level, steam outlet flow, and feedwater inlet flow. Data provided by pressure and temperature transmitters are used to enhance the accuracy of the steam-flow value. To illustrate: If the drum-level instrument is a dP-style level transmitter, a pressure transmitter is installed on the drum to provide the data necessary to make the density correction needed for accurate level calculations.

Thus, the term “3-element control” is somewhat misleading because it involves a minimum of six instruments—boiler feedwater (BFW) flow, steam flow, steam temperature, steam pressure, drum level, and drum pressure—for controlling the drum level.

And it is likely that more than one drum-level instrument is used. Many boilers have two drum-level instruments and control using the average value of the two. However, if one instrument goes bad the average value will be inaccurate. With two conflicting readings, how does one know which is the more accurate?

If any instrument fails, particularly one of the main instruments (steam flow, BFW flow, drum level), the control system will not work. If any one of the supporting instruments fails (drum pressure, steam pressure, steam temperature), the control system may still work but it will be compromised.

Occasionally, Geismar’s steam flowmeter would fail. If it failed high, the signal sent to the drum-level controller would result in too much BFW flow, leading to carryover. If it failed low, there was a risk of BFW flow being reduced to the point of tripping the boiler on low drum level.

Similarly, if the BFW flow transmitter failed high or low, this inevitably would lead to high drum level and carryover or a low-drum-level trip.

Depending on your specific programming logic, some instrument failure scenarios will default the drum-level controller to manual. Geismar boilers had two level transmitters. If they disagreed by more than 4 in., the level controller would default to manual. This usually would occur when the level control valve already was open or closed too much, leading either to a carryover event or trip because of low drum level. The operator then would have to control the drum level manually and not have the option of returning the control to automatic.

During an unusually cold period one recent winter, the drum pressure transmitter froze and its milliamp signal went so high it caused an instrument input/output (I/O) error; the level control system defaulted to manual. Even if the drum pressure transmitter were wildly inaccurate, it generally would result in a drum-level measurement error of only a few inches, which is preferred over a default to manual. When the system defaulted to manual the drum level likely would get out of control and the unit would trip.

Given the drum-level measurement challenges, a third independent level instrument was installed—one using guided-wave radar technology. Having three level measurements available, control was changed from using the average of two level-instrument values to using the median value of all three instruments. If one went bad, the control system would continue without a hiccup; only if two instruments failed simultaneously would the level reading be impacted.

Regarding steam-flow measurement, Geismar uses a verification system to check reading accuracy. By modeling steam flow versus other operating parameters, staff can predict accurately what the steam flow should be. If measured steam flow varies from the predicted value by too much, the drum-level control system alarms and the predicted steam-flow value is used in place of the measured value.

For the plant’s conventional fired boilers, steam flow can be predicted accurately using fuel flow (figure). For the cogen unit with the unfired HRSG, steam flow is predicted based on gas-turbine output (megawatts), and for the cogen unit with the fired HRSG, on a combination of gas-turbine output and fuel flow to the duct burner.

All of these calculations are made by the DCS. So, it makes no difference if the steam-flow measurement is the result of a problem with the flow, pressure, or temperature transmitter because the predicted steam-flow value is close enough for the system to continue accurately controlling drum level.

Regarding the BFW flowmeter, this instrument is the most critical in the drum-level control scheme because the drum-level control is actually feedwater control used to regulate drum level indirectly. Geismar installed logic that monitors the difference between the measured feedwater flow and the feedwater flow setpoint. This difference normally is very small. A large difference indicates a problem (either measurement error or feedwater valve issue) and the control scheme would transition from a 3-element arrangement to single-element (drum level), thereby removing the faulty feedwater reading from the control scheme altogether.

For the drum pressure transmitter, staff removed the “default-to-manual” logic that occurred when an I/O error was received, defaulting the drum-pressure reading to a constant value typically seen during normal operations.

Results. The site lost all six of its steam producers (two cogen units and four conventional boilers) during a very hard freeze in January 2018. Reason: Low drum levels caused by a combination of the failure scenarios described above—inaccurate steam-flow measurement, inaccurate BFW flow measurement, and controller default to manual attributed to failed instruments.

Following the freeze event, the changes noted above were made and deficiencies in the heat-trace system were corrected. Since that time, the boilers have successfully weathered instrument failures on the steam-flow reading, drum-pressure measurement, and drum-level measurement.

A few instruments were affected during the hard-freeze event in February 2021, but the improvements made were sufficiently robust to keep all steam producers in service.

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