Onsite – Page 59 – Combined Cycle Journal

2020 Best of the Best: River Road

By Team-CCJ | January 30, 2022 | 0 Comments

Non-chemical alternatives control algae in River Road’s cooling tower

Five years after COD, Clark Public Utilities’ River Road Generating Plant, operated by GE, was compelled by the Washington Dept of Ecology to eliminate the use of chlorine for biological control in its cooling tower. Instead, the plant was instructed to use bromine. Several years after the switch to bromine, River Road began to experience a resilient and chemically resistant form of filamentous blue-green algae. Its growth in spring and summer got out of control.

Expensive and toxic algaecide treatment was required to limit algae growth. The plant discharges tower blowdown to the Columbia River under a NPDES permit with strict discharge limits. One consequence: Blowdown was not permitted for up to 12 hours following this treatment process to assure dissipation of residual algaecide and to maintain permit compliance. That led to high cycles of silica.

During the peak of algae growth, accumulation at the forebay trash screens upstream of the circulating-water pump suction became so great the screens had to be pulled and manually cleaned every three days to prevent collapse. Removal of the trash screens required a crane and crane operator at a cost of $4500 per event (Fig 1).

These factors prompted staff to seek out new technologies to control algae. In 2013, plant personnel located a company that provided algae control using floating ultrasonic devices (Fig 2). They were procured and installed in various locations and orientations in the tower basin. Algae growth was reduced substantially, but not eliminated during the summer.

The search continued for an effective non-chemical technology; reverse osmosis, flocculation, ozone, UV treatment, and electrodeionization were among the technologies investigated.

Because sunlight is required for algae to grow, nursery shade screens were installed around the tower perimeter. They reduced the light required for photosynthesis and did help to reduce the algae more than the ultrasonic devices did on their own. However, the algae problem was not eliminated entirely during the summer.

During the search for a solution, staff located a company, Flow-Tech Industrial Water Treatment Systems, Milwaukee, Wis, that had developed a product used in small-to-medium size HVAC applications for many years, with well-documented success.

The vendor proposed creating and using its patented non-chemical devices on an industrial scale at River Road. The relatively small components are mounted on circulating- and service-water system pipe flanges in strategic locations (Figs 4, 5). Each unit transmits AM radio frequency into the water systems and cooling tower basin.

The theory of design is that the radio frequency disrupts the lifecycle of the algae in its single-cell haploidic form and kills it, before it forms viable colonies. Plant personnel worked with the vendor to develop and implement an industrial-scale test plan for the devices at River Road.

Use of the new devices has measurably reduced the plant’s biological and algae count within the cooling tower (Fig 6). Chemical treatment has been reduced to an algaecide injection once every three weeks rather than every other day. Plant Manager Robert Mash identified the following benefits of the new program:

    • A nearly complete elimination of algae in the cooling tower.
    • Lower micro-bio counts on weekly dip-slides.
    • A significant reduction in chemical consumption for biological control.
    • Elimination of crane costs for in-service screen cleaning.
    • Reduction in chemical discharges to the river.
    • Reduction in the handling of toxic chemicals by plant personnel.

Hydrogen-detection flange tape promotes safety, facilitates leak detection at River Road

Following each generator maintenance activity at Clark Public Utilities’ River Road Generating Plant, the system supplying the machine with hydrogen for cooling was restored and leak-checked using a soapy water product that bubbled or foamed if a leak existed.

A plant employee who attended the 2019 conference of the 7F Users Group saw a demonstration by Nitto Inc, Teaneck, NJ, promoting a pipe flange tape that changes color in the presence of hydrogen. Thus, it provides a visual indication of a leak because it will not return to its original color once hydrogen gas flow is stopped. Even though a soap test indicated no leaks, the staff thought it would be a good practice to use the color-changing tape.

The team member presented this idea as a proactive safety practice to the safety committee. The tape was purchased and installed on every hydrogen flange (Fig 6). Leaks were found, notes Plant Manager Robert Mash.

Thirty-eight flanges were taped. All had been soap-checked prior to using the tape. Once installed, four flanges changed color within two days. Where leaks were indicated, tape was removed from the flanges, and the joints were soap-checked again. Only one of the leaks was large enough to cause bubbling visible to the eye.

The hydrogen-detection flange tape worked well as a pre-emptive safety check and has stimulated proactive thinking about previously unrecognized problems. This fits in well with the long-established plant safety culture at this VPP Star site. Use of the tape is now part of the hydrogen-system restoration procedure.

Real-time monitoring of lube-oil condition at River Road

River Road Generating Plant, owned by Clark Public Utilities and operated by GE, relies on one lube-oil tank to supply the bearings of the single-shaft plant’s gas turbine, steam turbine, and generator. The original oil conditioning unit supplied by the OEM was grossly undersized for the 10,000-gal sump and was removed from service shortly after commissioning.

In 2000, the plant purchased a portable conditioning unit to filter the lube oil. It was functional and cleaned the oil fairly well. As that unit reached the end of its useful life, and the sophistication of the plant team grew, a replacement was sought.

Plant personnel worked with a small, local oil-filtration company to design, construct, and install a new conditioning system—one that would fit in the same physical space as the original unit, have a higher throughput, and include online particulate and moisture analyzers.

Following a water-intrusion experience, plant personnel learned the importance of obtaining oil-quality test results quickly. Relying on sample results from a third party to determine moisture content and particle count had put the staff in a reactive mode instead of a proactive one. The new conditioning system provides real-time monitoring of 4-, 6-, and 14-micron particles. The dew-point monitor and associated instrumentation assure instantaneous detection of moisture in the oil.

The new unit increased the oil conditioning rate from 13 to 38 gpm, reports Plant Manager Robert Mash. Third-party analysis for 4/6/14-micron particulates prior to installation of the new system was 22/20/16; two weeks after installation it was 18/16/12.

Moisture in oil was not tracked regularly before the new system was installed. The data available showed the Karl Fisher number for entrained water averaged around 600 ppm. That number has been reduced to 25 with the new system.

The new conditioning/monitoring system has dramatically improved lube-oil quality. The expected benefit is less bearing wear between maintenance outages.

Oil boom protects against leakage from River Road’s cooling-tower gearboxes

River Road Generating Plant’s cooling tower has five gearboxes, each containing about 20 gal of lube oil. The catastrophic failure of a gearbox poses the risk of releasing oil into the cooling-tower basin. From there it could migrate into the natural environment—more specifically, into the Columbia River—and result in a water-permit discharge violation.

Solution was to install a boom upstream of the cooling-tower circulating-water-pump trash screens to collect any oil that might be spilled, preventing it from reaching the effluent discharge piping. Oil collected can be removed by absorbent pads or skimming equipment, says Plant Manager Robert Mash.

The oil boom installed by owner Clark Public Utilities and operator GE continues to provide a reliable way of preemptively capturing any oil that might leak into the cooling-tower basin. The boom is easy to handle and is cleaned during annual outages.

River Road benefits from combining JSAs and operating procedures

At River Road Generating Plant, owned by Clark Public Utilities and operated by GE, work instructions historically included two separate documents—a job safety analysis (JSA) and an operating procedure. Personnel using the work instructions had to review these documents side-by-side to understand the risks associated with each step of the process.

Moreover, since the facility maintains work instructions for many its processes, reviewing documents and keeping them updated required a considerable time commitment for the onsite team on a regular basis.

Solution supported by Plant Manager Robert Mash was to incorporate the JSAs into the operating procedures, providing a job safety analysis for the task at the beginning of the document. New format also includes more pictures pertaining to the process steps.

Results:

    • Having the job safety analysis for the given task at the beginning of the document simplifies work instructions. Additional pictures are included for more clarity regarding steps involved.
    • Alleviates the need to review multiple documents while performing a task and increasing awareness of the hazards associated with the task.
    • Reduces number of documents to be reviewed and updated by half, reducing the time required to keep the documents current and updated.

Minimize growth of ‘non-cash crop’ in your cooling water system

By Team-CCJ | January 30, 2022 | 0 Comments

A combination of ultrasonic energy, AM radio-frequency waves, and sun shades managed to tame severe algae growth in the cooling tower at River Road Generating Station, according to Operations Manager Justin Hartsoch, GE Gas Power O&M. He told participants in the 2021 conference of the Combined Cycle Users Group (virtual) that algae blooms became a problem after the plant was compelled to shift from chloride to a bromine-based treatment to meet EPA NPDES regulations.

In a moment of levity, Hartsoch called the collected algae a “non-cash crop” (Fig 1), but also noted that the plant’s “unique algae bloom is seasonal.” Well water is the source for the plant.

The biocide formula that was being used also fed on silica, creating resistant algae which would coat the forebay trash screens, and require cleaning every two to three days. So, the plant undertook a campaign to identify a non-chemical approach to algae control. The solution to date (“the story is not over,” Hartsoch said) has proved to be the following:

    • Adding floating-head ultrasonic transducers at key locations throughout the cooling-tower basin.
    • Installing nursery sun shades on three faces of the tower to deprive algae of the sunlight necessary for growth.
    • Installing radio-frequency devices on each of the circulating- and service-water lines.

Details of this unique cooling water treatment approach, the theory of design, the circumstances which led to it, and the subsequent results and benefits were reported last year in CCJ. In the CCUG presentation, Hartsoch did note that the payback was a year and a half.

E.C.O. filming technology. Another “cash crop” tale emerged a few presentations later. Greg Boileau, Suez Water Technologies and Solutions SA, described a new proprietary, non-phosphate, circulating-water treatment based on E.C.O., an “engineered carboxylate oxide” filming technology (Fig 2). Phosphates are being phased out because of deposition challenges and formation of algae in receiving waters. Boileau said that one pound of phosphate can lead to 500 lb (wet) of algae.

Boileau reviewed the key drivers for reducing phosphates, sources of phosphates in the plant water balance, and several case studies. Much of the return on investment comes from avoiding the capital cost of a phosphorus removal system. Other Suez information online suggests the proprietary technology reduced phosphates by up to 80% in the pilot study at a large gas-fired plant while maintaining acceptable mild-steel corrosion rates.

Weld repair clinic particularly valuable to users with limited HRSG experience

By Team-CCJ | January 30, 2022 | 0 Comments

You’ll want to watch the video below from Bill Kitterman’s “Tube Repair Clinic: The Good, the Bad, and the Ugly,” even if just to see the pictures of the “uglier” and the “ugliest” tube-to-header welds (photos). In true photojournalism fashion, Kitterman, head of Bremco Inc, now part of SVI Industrial, described six different styles of such welds and the four methods for accessing leaking tubes, including the one fit for an action movie title, “cut your way in, weld your way out.”

Kitterman encouraged industry attendees of the HRSG Forum to “do more to determine the root causes of tube failures.” He also asked users in the audience to understand that, for repairs of creep-strength-enhanced ferritic tubes (such as P91), the downtime required to do quality work could be longer than they might expect. Welding is the fastest part of the procedure, he noted. Stress relief, code requirements (national, state, and local), official inspections, and insurance-company compliance factors take most of the time.

Example: “Bremco has modified its Alloy 91 weld procedure four times since initial qualification—for pre-heat and post-weld heat treatment and weld-wire requirements.” Proper wrapping to maintain the heat during heat-treat is critical.

Kitterman discussed Weld Method 6, a repair that avoids post-weld heat treatment (PWHT) but is only good for butt welds and on tubes with a wall thickness of less than 0.5 in. “This reduces downtime considerably since PWHT can take up to 14 hours,” he added. He also mentioned Supplement 8 for thicker pressure parts, which also avoids PWHT. It’s good for attemperator piping, although Kitterman conceded that Bremco isn’t yet comfortable with the procedure.

One attendee asked about tube plugging, but Kitterman cautioned that plugging a tube can change the flow patterns. It’s no longer being steam-cooled so the hotter gas can impinge on adjacent tubes, and failures could cascade. Another asked if Bremco undertakes turnkey scope; Kitterman answered yes, but prefers to add third-party specialist heat-treat and inspection companies to the team.

Other questions and responses addressed sonic leak detection methods—all captured in the video recording a couple of clicks away.

With pressure parts, so much depends on high-quality welds. Even if welding “isn’t your thing” at the plant you are responsible for, it’s worth watching this presentation to gain a cursory understanding of what’s involved.

Novel attemperator for HRSG reheater circuits eliminates legacy issues

By Team-CCJ | January 28, 2022 | 0 Comments

Since virtually everyone at a cycling plant faces issues with their attemperators (Fig 1), you’ll probably want to know about a unique design retrofitted to several Duke Energy combined cycles, one that uses the existing spray ring.

Key to the design is use of HP steam to provide the energy to atomize the spray water (Fig 2). This creates a much finer distribution of droplets, regardless of water flow, pressure drop, or steam velocity in the steam pipe, noted Justin Goodwin, director, Steam Conditioning Group, Emerson Automation Solutions.

Steam-atomized nozzles are not new, but are considered unsuitable for high temperature applications like HRSG attemperators. Emerson reached out to corporate colleagues at Fisher™ to design new steam-atomized nozzles that fit into the existing radial-spray, spring-loaded nozzle ring. 3-D printing the nozzles (patented method) of a hardened cobalt chrome alloy (similar to Alloy 6) eliminated the many weld joints, and failure points inside the nozzles of a conventional steam-atomized unit.

“There are no droplets [of water] falling because they are so fine, which avoids the common attemperator failure mode of water impingement leading to damage on internal pipe surfaces. Plus, the design is highly resistant to plugging and corrosion,” Goodwin stressed. A tap at the h-p drum serves as the source of steam.

Note that the design is not applicable to the HP attemperator, only the reheater units. But good news for designers of new HRSGs: Smaller droplets can lead to a 30-40% reduction in piping lengths.

Lessons learned during the field trial are that a 1 in. to 2 in. connection in the atomizing steam supply piping was a choke point, as was use of a Y-pattern valve instead of a full-bore ball valve (a pressure transmitter was added to troubleshoot these issues). Modified control logic design is critical to a successful retrofit. In response to a question, the presenters noted that they replaced the water temperature control valve, but not the block valve.

Eugene Eagle, HRSG engineer, Duke Energy, and Goodwin’s co-author, said that Duke was pleased enough with the initial field trial on one unit at the utility’s Buck Combined Cycle Plant that they installed the new design at Dan River Generating Station on four additional units. The attemperator with the longest service life had 18 months of operating experience at around 85-90% capacity factor at the time of the presentation.

Duke has eliminated several failure modes, as well as the two-year inspection and test schedule for the previous spring-loaded nozzles, and is in the process of determining the cycle life for the new design. Current thinking is that the nozzles could warrant replacement every three years and that the internal piping liner should be borescope-inspected every two years. Thermal fatigue is the expected nozzle failure mode.

Many of the other questions addressed aspects of the control system (such as the operation of the block valve with the control valve), leakage at the block valve (you need a good block valve and trust it to be tight), the potential need for a second block valve, and possible issues with wet steam in the atomizing steam piping.

Special technical presentations to steam-turbine users focus on maintenance, lubricants, insulation, D11 upgrades

By Team-CCJ | January 28, 2022 | 0 Comments

Presentations made by MD&A, Shell Lubricant Solutions, ARNOLD Group, and EthosEnergy Group to owner/operators participating in Weeks Three and Four of the virtual STUG2020 conference are summarized below. You can access the recordings and PowerPoints on the Power Users website.

MD&A: Using turbine performance to improve your maintenance strategy

This presentation by James G Miller, PE, manager of performance services for MD&A, is a valuable primer for plant personnel participating in their first steam-turbine outage and equally valuable as a refresher for more experienced engineers and technicians. Miller’s message: Use the results of (1) recent performance tests conducted with the unit in service, and (2) steam-path audits made in the early stages of the outage, to reduce both outage cost and duration.

Miller reminded attendees that performance losses are a sign of degrading conditions that adversely impact the plant’s bottom line. The outage affords the opportunity to use this information for pursuing repairs and upgrades of greatest economic value.

The speaker covered the basics of performance testing, and how to conduct the all-important steam-path audit, in his presentation, which is available on the Power Users website complete with formulas, calculation examples, a comparison of as-tested performance to reference data, etc.

Best practices in performance testing—such a making sure there’s at least 25 deg F of superheat when calculating turbine efficiency—are included in the PowerPoint, together with a list of diagnostic parameters or additional tests that can be used to further characterize the sources of loss—such as solid particle erosion (SPE), casing leakage, and valve leakage. Thermal scans are particularly valuable for identifying the locations of leakage (Fig 1).

Examples of typical sources of performance loss identified during the steam-path audit include the following:

    • Seal leakage (Fig 2).
    • Surface roughness.
    • Change in trailing-edge blade profile.
    • Deposits.

Case studies identifying the reasons for performance loss in a reheat turbine at a combined-cycle plant, in a reheat turbine for a conventional steam plant, and in an industrial double-extraction condensing turbine are highly informative. For the first unit, performance testing revealed gross output had decreased by 2.3%. Excessive surface roughness, worn end packing, rubbed tip spill strips, and leakage by startup vents and HRSG drains were among the primary contributors to the loss.

A checklist of information to review in overhaul planning concluded the presentation.

Shell Lubricants: Choosing your lubricant not a one-size-fits-all

Lubricant selection is one of those subjects you might not think about for years, but when necessary it’s good to have a backgrounder like this at your fingertips—or only a couple of mouse clicks away on the Power Users website.

Key discussion topics include these:

    • Base-stock evolution (Groups I through V).
    • Varnish.
    • Mitigation methods for varnish—including top-off fluids, filtration units, and fluid solutions (polyalkylene glycol, gas to liquid—lubricants made from natural gas).
    • Field experience.

Varnish elimination with polyalkylene glycol (PAG) was a focal point of the Shell Lubricant Solutions presentation, which included a review of experience since 2001 at two units that switched to PAG to eliminate servo valve issues caused by varnish. Since then there have been no servo failures or trips while on PAG.

Recall that the stress experienced by a turbine lubricant contributes significantly to the ageing of petroleum oil, causing the non-polar fluid to oxidize. However, the resulting byproducts of decomposition are polar and insoluble in the base oil; they come out of the solution as varnish. Polyalkylene glycol, by contrast, is a polar fluid and, while it too oxidizes, the byproducts of decomposition are polar and infinitely soluble in the base stock. No varnish is produced.

ARNOLD Group: Advanced steam-turbine warming for increased startup flexibility

Pierre Ansmann opened his presentation on “the most advanced turbine insulation combined with a high-performance heating system to improve startup flexibility,” by summarizing its value proposition thusly:

    • Increased in-market availability.
    • Lower startup costs.
    • Reduced thermal fatigue and longer mean time to repair for critical components.
    • Increased operating flexibility.

He reviewed alternative warming-system arrangements, rejecting those integrating the heating circuits in insulation blankets, installing the heater on a thin mattress below the blanket, and using glass-fiber-insulated heating cable. The optimal system for the upper casing, they said, is heater on metal mesh baffle, for the lower casing, permanent mounting of heating cable below the split line.

The ARNOLD system features interlocking high-performance blankets which conform perfectly to the turbine surface (Fig 3). High-quality materials and manufacturing, and long-term high-temperature resistance, allow the company to guarantee reuse of its insulation system for 15 outages without a decrease in efficiency.

Dozens of thermocouples, strategically located on the turbine, ensure proper heating. Each of the 18 or so heating zones has t/cs installed on the heating wires to double check if the zone is responding correctly and at the specified temperature. Below every heating zone, multiple t/cs are mounted on the casing to confirm even heating of the turbine.

Ansmann said a properly maintained ARNOLD insulation system can maintain your turbine in a hot-start condition for at least four or five days after shutdown. No preheating of the turbine is required prior to a start within this time period, reducing startup fuel consumption and auxiliary power.

Combining high-quality insulation and warming systems enables tight control of casing-to-casing and rotor-to-casing expansion during shutdowns. A goal for operations personnel to aim for, Ansmann said, is a homogeneous cooldown to maintain the temperature difference between the upper and lower casings to less than about 100 deg F. Access the recording and slides here.

EthosEnergy Group: Multiple upgrades improve D11 reliability

Owner/operators of the popular D11 steam turbine are sure to benefit from a review of this illustration-rich, 50+ slide presentation, easy to access the recording and hard copy in the Power Users archives. The presenters from EthosEnergy cover the repair of 40-in. L-0 blades, and upgrades of Smart seals and the N2 packing box, among other things. The subject plant was a 4 × 2, 1240-MW combined cycle. COD for the unit upgraded was 2011; first major inspection in 2020.

Two rows of the damage-prone L-0 blades were weld-repaired prior to the outage to correct excessive leading-edge erosion (Fig 4). Cracking in the blade pin-finger dovetail roots also was addressed. Presentation provides details likely of value to anyone facing the same issues. Photos illustrate key steps in the process, including re-blading of the L-0 row.

The Smart seal upgrade was done to address rotor vibration caused by seal rubs. Experienced users know the HP/IP rotor is very flexible and sensitive to mid-span rubs. Detailed measurements of packing and tip-seal wear (average horizontal, top, and bottom) are presented. Heaviest rubs are identified with the lower-half horizontal joint. The speaker noted that although clearances generally are larger on the bottom, wear is substantial at all locations.

A seal developed to upgrade OEM seals to avoid rubs and wear during startup and shutdown, by way of additional clearance, is illustrated. Reduced vibration during startup is one benefit. Another is increased revenue, said to be upwards of $17-million for a typical 300-MW steamer over an eight-year run time. Information on estimated savings in fuel and carbon emissions also are presented.

N2 packing heads, which contain shaft seals between the HP and IP steam paths, have a history of horizontal joint leakage. This impacts performance because HP inlet steam leaks into the IP section. Plus, steam cutting occurs across the horizontal joint. The presenter highlights what his company’s experts say are design issues that prevent maintaining a closed joint. Described modifications are said to mitigate the problem.

Owner/operators share experiences on repair of blade damage, casing cracks, etc, at final sessions of STUG2020

By Team-CCJ | January 28, 2022 | 0 Comments

If you have never attended a STUG event, the summaries of user presentations from Week Three and Four of the 2020 virtual meeting in this issue of CCJ ONsite will encourage your participation in future in-person, live events. The information shared at these forums, vital to your professional development and your plant’s success, is available only through Power Users.

Registered owner/operators also can access the user experiences and presentations made by third-party products/services providers during Week One of STUG2020 (November 11) on the Power Users website. For technical presentations made by the OEM during Week Two (November 18), visit GE’s MyDashboard website.

User presentations

Alstom MI with IP blade replacement and L-0 replacement

Reviews the planning and execution challenges associated with a recent steam-turbine major inspection, incorporating lessons learned. Background: The 282-MW Alstom steam turbine serving a 2 × 1 F-class combined cycle began commercial operation in 2003 and had a service history spanning 100k operating hours and nearly 600 starts. HP and IP steam conditions were 1050F/1975 psig and 1050F/483 psig, respectively.

Scope of work for the full-train (HP/IP/LP/Gen) major inspection included the following:

    • Inspect HP turbine stop/control valve inspections, replace Radax blade row, and provide new rotor and casing seals.
    • Inspect IP turbine intercept stop/control valves, replace Radax blade row and first- and second-stage rotating blades, install new rotor and casing seals.
    • Replace LP turbine L-0 blades and refurbish LP gland housing.

Speaker shares with colleagues IP rotor findings and the two blading replacement options considered: restore to original design or leave as is. For the LP section, L-0 blades were removed and replaced onsite with mix-tuned blades (Fig 1); no balancing was performed. Unit was returned to service with no vibration or operational issues.

GE D11 casing cracks and repairs (2013-2020)

This presentation affords the opportunity to learn about the casing cracks and repairs made to a D11 steam turbine over the unit’s life from COD in 2002 through its second major in 2020. The first major, conducted in 2013 after nearly 45,000 operating hours and nearly 1700 starts, was planned for 49 days but took 95. Operating hours at the start of the second major numbered about 98,000, but there were only about 120 starts in the second interval.

Inspection of the HP casing at the first major revealed cracks of significant length and depth in the inlet area (Fig 2). GE’s recommended welding procedure was reviewed by owner and plant personnel. It included a post-weld heat treatment of about 1200F for the entire HP/IP casing. However, during this process the casing was humped, requiring another repair. It involved removing about 200 mils of material from the horizontal joint in the HP inlet area to correct the distortion (Fig 3). Plus, machining of the diaphragm fits/steam seal faces and casing reliefs with a boring bar.

With the turbine gods smiling, the unit was reassembled and restarted with no vibration issues or rubs in January 2014. No issues were in evidence prior to the second major. But staff was apprehensive as the unit was opened for inspection. One crack was found on both the upper and lower halves that required attention. It was ground out and weld-repaired.

Creep and diaphragm dishing were in evidence and the experts conducting the investigation said they expected a casing replacement might be required at the next major. In sum, personnel believe that heavy cyclic duty prior to the first major contributed to the severe cracking corrected in 2013. Baseload service in the second interval mitigated the underlying issue. But the lingering question was the following: At what point does the plant quit trying to repair and evaluate retrofit options?

GE rotor indication recovery

This analysis and repair of the rotor for a 523-MW GE G2 turbine is based on experience gained at the gas-fired steam plant since COD in 1973. Steam conditions for the unit, designed for baseload operation: 2270 psig/950F/950F. The first clue something was amiss was vibration identified in 2019—especially on the T1 and T2 IP bearings on coast down.

The unit was operated in the partial-arc mode and vibration occurred at certain valve settings. Going to full-arc admission eliminated the vibration. The unit tripped on high vibration in summer 2019. Upon disassembly, a 360-deg circumferential crack was found on the discharge side of the first-stage wheel transition area.

The rotor was shipped to the shop for additional inspection and evaluation. Cracking was found in other areas as well. Excavation of the first-stage crack was initiated, experts believing it to be at least 3 in. deep; it was 8 in. (Fig 4). Some details of the effort are shared in the presentation.

Outage duration was approximately 230 days. Since returning to service for the summer 2020 run, the unit has behaved well. However, the extensive weld repair reduced the rotor’s remaining life. A new like-kind rotor, in manufacture, is planned for installation early in 2022.

Post mortem: A review of vibration data from 2010 revealed clues regarding rotor cracking. The unit had operated for years outside the service parameters for which it was designed. The fast-start/fast-ramp paradigm adopted, with 500-deg-F thermal ramps and a dispatchable load range of from 50 to 500 MW, took a toll. The replacement rotor in manufacture has design enhancements to better accommodate today’s challenging operation requirements.

Maintenance of D11 stop valves and lessons learned

Fleet-wide perspective on valve maintenance based on operating-hour intervals and managed by the utility’s program called Optim. Findings focused on are solid-particle erosion of valve stems (Fig 5) and seat erosion. Shearing of main stop/control valve strainer anti-rotation pin, LVDT nut looseness, and implementation of GE’s “Digital Valve” upgrade (Fig 6) were other discussion points—all well illustrated.

Three of the steam turbines addressed in the presentation rely on 32k operating-hour intervals for maintenance of their main stop/control, reheat stop/intercept, and LP admission stop/control valves. Another unit’s maintenance is based on 24k because it has experienced excessive scale buildup on the main and reheat valves. Findings and lessons learned are summarized in the slide deck available to registered users on the Power Users website.

Upgrading D11 valves

Presentation highlights valve findings and repairs, presents a historical perspective on valve indications, offers the owner’s perceived value of the OEM’s “Digital Valve” over in-kind replacements of damaged valves, identifies valve-replacement risks, how to plan for valve replacement, and operating experience to date with the digital valve.

Lessons learned in the transition to GE’s digital valve (Fig 7):

    • Obtain drawings early to resolve any discrepancies prior to the outage.
    • Ensure all parts and components associated with the new valve are onsite prior to the outage.
    • Order spare-parts kit along with the valve to assure availability of critical spares.
    • Ensure all specialty tooling for shell-arm load checks are available with spare parts.
    • Plan for new junction boxes and cable pulls to support below-seat drain relocations.
    • Contractor hired for electrohydraulic line mods must be trained on how to bend stainless-steel tubing.
    • Verify hardware on new valves is torqued and locking tabs are in place.

Benefits of the digital-valve package include daily online testing, ability to monitor performance, and the promise of extended maintenance intervals. Operations personnel verified the digital valves operate quietly and smoothly.

Valve O&M considerations for steam turbines and auxiliaries

Eric Prescott, EPRI’s program manager for valves, discussed maintenance strategies for valves—including condition-, fleet-, value-, and time-based programs. His slides on maintenance workflow, system maintenance approaches, and valve condition monitoring are excellent primers for personnel new to your O&M team.

Prescott digs into the details of valve damages and operational stressors. For example, on the all-important subject of solid-particle erosion he examines the sources of particles, plus the importance of particle incident angle, steam velocity, and erosion-resistant materials for minimizing damage.

Coverage also includes fasteners and sealing elements, the spindle-guide bushing interface, Stellite hardfacing, monitoring of valve castings for service fitness.

STUG steering committee for 2021

Chairman: Seth Story, Luminant

Eddie Argo, Southern Company
Jess Bills, Salt River Project
Jake English, Duke Energy
Jay Hoffman, Tenaska
John McQuerry, Calpine
Matt Radcliff, Dominion
Lonny Simon, OxyChem

Founding members of STUG who recently retired from the committee are Bert Norfleet (2019) and Gary Crisp (2020)

Eke out more performance from your old gas turbine

By Team-CCJ | January 28, 2022 | 0 Comments

It’s not often you get something for nothing, or in this case almost nothing. Pay for an expert review by a couple of top global gas-turbine consultants with man-decades of experience, have them tweak your controls, and you likely can squeeze out a few megawatts and/or efficiency gains from an older gas turbine. No capital costs involved.

According to Bob Johnston, president, Keck Group International, speaking at the 2021 MENA Combined Cycle Conference (virtual), May 25-27, the key is an integrated, system-wide evaluation of the components currently in your machine (Table 1). “Some replacement hot-gas-path (HGP) parts are actually upgraded parts which supersede their earlier versions, and could qualify for higher firing temperature,” Johnston stressed.

This so-named “non-capital-parts uprate program” has been successfully applied to “many dozens” of GE machines and also can be applied to other OEM machines. Johnston explained that OEMs often supply upgraded parts as in-kind replacements but don’t tell the customer that they’ve replaced enough parts to qualify for an uprate. In fact, this is the “likely” situation for older machines, typically those shipped before 2001. For example, most of the later-vintage HGP parts for the MS5002 and MS700EA are directly interchangeable with all prior vintages.

Tweaks identified by Johnston which can arise from the parts evaluation are:

    • Inlet guide vane (IGV) angle change.
    • Isotherm setting increase for power at higher ambient temperature.
    • Exhaust thermocouple (t/c) corrections.
    • Degradation correction to control curve.
    • Tilted control curve.

Exhaust t/cs were biased high on machines between 1980 and 1997, and a straight-forward controls setting change can net up to an 11-deg-F increase in turbine exhaust temperature. Results for 11 gas turbines in the Middle East (Table 2) show that not all the tweaks apply to every unit (Table 3). Output gains ranged from 2.4% to 10% for three separate groups of 56 engines without applying IGV angle-change tweaks.

Standard GE control curves maintain constant firing temperature at all ambient temperatures. A tilted control curve overfires the machine by 16 deg F on hot days, and underfires the machine by 25 deg F on cold days. This can give a 1.6% output boost on hot days, with no net impact on parts life or maintenance cycles. Again, only control setting changes are necessary. Most sites value an output boost during peak summer periods, and can sacrifice small decreases during cooler periods.

Control curves are based on a new machine, but as operating hours mount, non-recoverable performance degradation occurs, which reduces output, but also leads to under-firing the machine because the control curve hasn’t been adjusted. “By applying a suitable correction to the control curve, you can gain 0.8% output,” notes Johnston. This has been done for “hundreds of machines since the 1990s,” he added.

Users are cautioned that the higher turbine exhaust temperatures which lead to the output gains could raise the HRSG’s HP superheater temperature beyond its limit (figure). Two ideas here are to add desuperheater capacity or remove fins from the superheater tubes. Careful analysis could reveal other options as well.

Shock waves deep clean HRSGs

By Team-CCJ | January 28, 2022 | 0 Comments

Twenty years ago, few people probably thought that a tube cleaning technique for HRSGs attached to gas-fired turbines would be adapted from those used for solid-fuel boilers. Yet that’s where we are today. Carl Wise, Thompson Industrial Services, and Vince Barreto, PowerPlus Cleaning Systems, showed attendees at the HRSG Forum Supplier Workshop, Oct 7, 2021, that such a system can be elegantly designed and operated even if it’s dislodging and removing tons of material stuck on HRSG tubes.

The technology, originally called PowerWave+ when introduced by GE in 2006 as an online system for solid-fuel boilers, was converted from a sound-wave- to a shock-wave-based process, then acquired by PowerPlus in 2014 and adapted to offline cleaning. Simply, the acoustic driver attached to a sound horn, was replaced with a combustion tube to create a pulsed detonation cleaning device.

PowerPlus calls it Extraction Pressure Impulse Cleaning (EPIC). While the recording of the Forum presentation gives more details about the technology, what you really want to experience are the videos, which show how the device is engineered into a “navigation rig,” temporarily installed in the lanes between the tube bundles, and moved remotely from location to location while a technician monitors the cleaning on a 50-in. screen.

The rig is arranged for the HRSG being cleaned, which can be vertical or horizontal, and can accommodate baffles, which one astute attendee asked about. If sky-climber ports are not available for rig support, they must be added, although Barreto noted he’s only encountered one unit that was not so equipped. Another attendee wondered if the blasts would dislodge material on the ID side of the tube and the answer was “no”; the shock wave energy does not reflect through the tube wall.

Two of the key benefits of this technique over dry-ice blasting and open detonation, say Barreto and Wise, are avoiding scaffolding or sky-climbers and providing the capability to deep clean “every square foot of the heat-transfer surface.” Tube sections are subjected to the shock waves from the lanes on both the upstream and downstream sides.

Several case studies were presented with dramatic total tonnages of material removed, several inches of differential pressure restored, and 1-2 MW of output recovered.

Global suppliers tout upkeep, repair, upgrade solutions for GTs, HRSGs, BOP systems

By Team-CCJ | January 28, 2022 | 0 Comments

Unlike many user-group events, the 2021 Combined Cycle Conference for the Middle East/North Africa (MENA) region began with a primer on combined-cycle facility design, which set the stage for detailed presentations on gas-turbine, steam-cycle, and balance-of-plant upkeep, repair, and upgrade techniques and technologies. Perhaps the only major subsystem omitted was steam/water treatment for maintaining proper cycle chemistry.

Sponsors of the virtual meeting were GE, Allied Power Group, ARNOLD Group, CoreTech Industrial Corp, EMW filtertechnik GmbH, John Cockerill, Keck Group International, MD&A, and SPG Dry Cooling.

Joel Holt, operations manager at CoreTech’s Plant Systems Div, kicked off the conference with a presentation on combined-cycle plant basics. The editors consider this must viewing for folks new to the industry and a worthwhile refresher for veterans.

As one example, Holt compared a 2005-vintage combined cycle to a 2020 facility, and the contrast is stark if you haven’t thought about it for a while: A two-hour hot start versus less than 30 minutes today, around 50% efficient versus 62+%; steam turbines and HRSGs designed specifically for combined cycles (rather than designs lifted from other applications), and features like purge credit and system simulation not even available 15 years ago.

HRSG. Raphael Stevens, John Cockerill (formerly CMI), began with a review of his firm’s 200 years of industrial experience and an install base of 800 horizontal, vertical, and once-through HRSGs (amounting to 120 GW and 10% of the world HRSG market, he claimed).

Stevens gave examples of recent projects, including HRSG modifications to match the boost in output from a GT upgrade at Kings Lynn Power Station in the UK (Fig 1), and for one of the world’s largest desalination plants, a new low-pressure module added between the HRSG and stack (Fig 2) reduced stack temperature from 352F to 273F, thereby increasing water production and decreasing CO2 emissions.

Performance enhancements. Bob Johnston, Keck Group International (KGI, formerly GE Gas Turbine Upgrades), opened by saying “GTs may be ‘forever’ but customer needs change.” KGI’s services include engineering support to evaluate performance enhancements—including lifecycle evaluations, faster startups, efficiency improvements, controls upgrades, emissions support, and upgraded parts evaluation.

Johnston’s presentation is replete with nuggets of insight. For example, he stated that exhaust thermocouples on GE units were biased high between 1980 and 1997 and can be corrected to improve performance. And some replacement hot-gas-path (HGP) parts are actually upgraded (superseded) components which can qualify for higher firing temperatures.

He also discussed a “tilted control curve” which can allow you to overfire on hot days to boost output, and underfire on cold days. Normally, the GE control curve maintains constant firing temperature for all ambient conditions.

Steam turbine warming. Pierre Ansmann, global head of marketing for ARNOLD Group, presented on his firm’s advanced single-layer turbine warming system (Figs 3 and 4). This is must viewing if you’ve never thought that hard about steam-turbine insulation and their support and casing-attachment systems, differences between bottom and top insulation (25% thicker on the bottom, removable on the top side), casing heaters and attachments, and advanced controls which ensure every heating zone is controlled to within 1 deg C. Arnold guarantees that insulation surface temperatures do not exceed 15 deg C above ambient, and the unit is “hot-spot free.”

Dry cooling. Frederic Anthone, aftermarket manager, SPG Dry Cooling (a member of Paharpur Cooling Towers) opened with an overview of his firm’s 150,000 MW of air-cooled condenser (ACC) installations worldwide, and five basic designs—A-frame, Box Air, and Hexacool for plants less than 50 MW, and Module Air and W-style for large plants.

Because “performance always changes with plant cycling and ambient conditions,” Anthone dwelled on the need for regular testing (for example, vacuum leakage test), inspections (including drones) by specialists, and/or an ACC360 continuous monitoring and diagnostics (M&D) service program so cleaning and repairs can be properly planned, rather than forced.

“Data-driven analysis combined with thermal modeling can detect failures before they occur,” Anthone said, “which can increase reliability during adverse ambient conditions.” He offered brief case studies, one of an 800-MW plant that increased ACC thermal capacity to accept higher steam loads, in which all motors/gearboxes were replaced and upgraded without changing fan blade geometry.

GT repairs. Jason Brown, senior VP of business development, Allied Power Group, called his firm the “largest independent GT repair company in the world” as a result of “many acquisitions over the last few years.” He then noted the 3100 transition pieces sold for all GE frames through the 7FA.04, the 1900 combustion liners/CCP assemblies sold, and other components, some of which he said are better than the OEM’s for repairability. Repairs—including rotors—can be conducted on most GE and Siemens/Westinghouse machines.

Coatings are a “primary competitive advantage” of APG’s offerings, and are equivalent or superior to the OEM’s, he added. “We have 12 coating booths in operation and each of them can handle all necessary components.” The field services group can manage up to 10 outages at one time. One of the case studies presented involved the life extension of a crude-oil-fired GT, now expected to achieve a 12,000-hr inspection interval, whereas before the interval was far shorter.

GT filters. Andrew Thompson, project engineer, EMW Filtertechnik (family owned since 1954), reviewed the important standards his company can test to and meet—including EN779, ISO 16890, Ashrae 52.2, EN1822 (HEPA standard), and ISO 26463. Thompson underscored the importance of high-quality filters kept clean by showing photos of compressors after only 5000 hr of operation after online and offline cleaning. Spoiler alert: The photos aren’t pretty.

High-end filter media are also easier to clean, too. No compressor washing is necessary and the machines remain “completely clean” after 5000 hours. “Washing really only cleans the first-stage blades,” he said. Changing from an F8 type filter to an E11 or E12 can “dramatically increase performance and reduce outage work,” Thompson concluded.

Mechanical Dynamics & Analysis (MD&A, a Mitsubishi company) then delivered a series of presentations on gas and steam turbines, generators, turbine valves, and control and excitation systems. Jose Quinones covered GT component repair experience with 6FA, 7FA, 9FA, 7FA.03, and many other GE machines, totaling close to 1250 sets of F-class components.

Neil Jones spoke on steam-turbine inspections and repairs for what he termed “almost all OEM- manufactured equipment.” He included a case study from 2020 in which a bowed rotor was straightened from 16 mils to 4.

If you didn’t realize that an inspection and recommendations report for steam-turbine valves could run 60-120 pages, listen to Jason Wheeler’s presentation to find out why. One of Wheeler’s stats: 75% of overspeed events are caused by improper valve operation. Depending on the aggressiveness of service, these valves must be inspected every three to five years.

James Joyce covered generator stator and rotor repairs, and began with a primer on generator components. Much of his material addressed the question: “Should I re-wedge or not?” When the answer is “yes,” MD&A can handle in-kind wedging or upgrades, he said, “which can be beneficial but very labor intensive.” Several options and tradeoffs must be considered, which is why you may need to call in specialists. Re-wedging takes 8-10 days and does increase outage costs. Core tightness checks and frequency bump tests should be included the project.

Michael Broggi addressed dealing with obsolescence of, and adding selective upgrades to, generator controls and excitation systems. Modern systems can include high-speed data capture and storage for troubleshooting. “This goes beyond PI data because faults are often in the milliseconds range,” he stressed.

Through an acquisition, MD&A now offers the IBECS® “fully integrated” control platform in which all HMI is encrypted and the system is “set up to be cyber-secure, with native drives and open-source protocols and features such as advanced alarming, pattern recognition, time synchronization, sequence-of-events recording, high-speed trending, and remote access and monitoring.”

GE Day

The underlying messages from GE Day at the MENA Combined Cycle Power Plant Users Symposium was that, regardless of which region of the world you operate in, (1) mission and operating changes are coming to your plant, and (2) GE Gas Power specialists can help you analyze the impact of those changes on your equipment, recommend solutions, and implement them.

Jeff Chann, business intelligence leader, took the highest-altitude perspective and presented on the global industry transformation. The push to decarbonize a global economy essentially built on fossil fuels over a hundred year or more period will impact all gas-fired facilities.

As renewables grow, combined cycles not originally designed or built for cycling will have to be modified to do so. And unlike other regions, MENA’s electricity demand is still growing at a rapid pace. “One-billion people on this planet still need electricity,” Chann reminded his audience, and that need has to square with decarbonization.

John Sholes, principal engineer, then introduced Ahmed Gaber, application engineering leader, MEA Region (Middle East and Africa), who reviewed some of the mission outcomes that may be necessary as this transformation unfolds: higher peak load, more fuel flexibility, turndown to lower loads, faster starts, and higher cold-day or hot-day output.

Sholes noted that addressing the limitations on the balance of plant from a gas-turbine uprate will likely cost only a fraction of the GT uprate. He said GE specialists can analyze your plant’s performance and goals and recommend upgrade options. One example: If your attemperator valves are topping out, analyzing the operating data could reveal that relatively minor modifications can address this and eliminate water hammer during load transitions.

Akram Ismail, senior solution architect, and Mohamed Hamdy, lead customer application engineer, presented a case study for a 9F.03 combined cycle, where the gas turbines had been upgraded with the OEM’s Advanced Hot Gas Path, the steam turbine upgraded with GE’s Advanced SteamPath, and the HRSGs upgraded to improve overall plant performance.

Akram and Hamdy showed the evaluations used by GE to identify potential impacts on plant systems and discussed solutions to fix identified equipment limitations and scope offered for implementing concluded resolutions.

The following presentations then drilled down to the generators, HRSG, and steam turbine. They are available on the OEM’s MyDashboard website. 

Generators. Karim Bakir, lead customer service engineer, EMEA Region (Europe/Middle East/Africa), reviewed generator maintenance practices and lifecycle issues, especially after the onset of cycling. Generally, he said, users need to consider a rewind for the rotor after 15 to 20 years, and for the stator after 25 to 30 years. However, cycling duty may accelerate those schedules.

Bimpe Olubode, lead customer service engineer, EMEA Region, reviewed new developments in collector rings and brush systems. Janusz Bialik, principal customer service engineer, EMEA Region, spoke about generator health monitoring and recommendations. Benjamin Kreyssig, lead customer service engineer, EMEA Region, presented a forced-outage case study on a 7FH2 generator field.

The speaker explained how the field defect (ground fault) was ascertained based on GE diagnostic experience and fleet know-how. Detailed review of the observed findings identified what caused the ground-fault event. Plus, the presentation highlighted how GE was able to provide the field owner the best service option, including a spare field, to minimize generator downtime.

The HRSG presentation, led by Vasileios Kalos and delivered by Mohamed Hamdy, lead customer application engineer and Salim Kassis, senior sales manager, reviewed the replacement of pressure parts to extend life and reduce O&M costs—with an emphasis on upgrading from carbon steel to Gr11 alloy. Details were also given on GE’s pressure wave plus technology to address HRSG tube fouling.

Recall that pressure wave is an offline cleaning technique which uses controlled acoustic shock waves, or “bangs,” to knock debris off the tubes. A total cleaning on an HRSG serving an F-class unit takes about four to six shifts. For every inch water column of backpressure increase, the plant typically loses 0.2 MW of output and 0.1% heat rate. GE recommends that tubes be cleaned when backpressure reaches 3-in. H2O above specification.

Steam turbines. Matt Foreman, combined-cycle steam-turbine fleet leader, and Salim Kassis, delivered observations and findings from the product service team on impacts when units shift to low load and cycling service. Sites need to understand what these impacts can be, monitor for them, and engage in long-term mitigation planning.  A few examples cited:

    • Erosion of valve components can increase when the valve is throttled to achieve lower loads.
    • Highly loaded components, such as rotors and last-stage blades, will accumulate more LCF damage with an increase in annual starts.
    • Leading-edge erosion of turbine blades is accelerated by low-load operation.

GE spoke to solutions that range from upgraded replacement components like NextGen Valves and Advanced SteamPath to basic repairs to mitigate impacts of low-load and cyclic operation, but monitoring, diagnostics, and planning are critical.

The last presentation reviewed how analyzing operating data can help diagnose and identify emerging steam-turbine issues, flag minor problems before they become big ones, and inform maintenance planning. For example, when tracking the difference between the upper and lower turbine-shell metal temperatures, a delta T trending high from shell top to bottom indicates a higher risk for rubs. This can be addressed by checking for quality of insulation and ensuring proper installation of insulation. Changes in transient vibration over the unit’s operating life may help diagnose rotor bowing, as another example.

Such changes can be very gradual over time but nevertheless meaningful for diagnostics. The speaker suggested that users lacking the necessary expertise consider subscribing to GE’s OSM monitoring service.

OPC’s Doyle Energy Center converts generator coolant from hydrogen to helium

By Team-CCJ | January 28, 2022 | 0 Comments

Doyle Unit 1 is a legacy GE 7B gas turbine with a 64-MVA/14.4-kV, 30-psig hydrogen-cooled generator. A thorough investigation of the engine by Oglethorpe Power Corp engineers revealed degradation of its asphalt insulation and estimated remaining life at less than two years. Several equipment condition and operational performance gaps with the hydrogen cooling system also were identified during unit inspection and testing. Bringing the cooling system up to industry standards would have required an investment of $400,000 to $500,000 (est), according to Fleet Manager Michelle Crane.

The plant’s goal was to find a safe alternative to hydrogen coolant for the predicted remaining life of the generator. Staff researched the practicability of using helium as the cooling medium in a hydrogen-cooled generator and in April 2018 the idea was tested and implemented on Unit 1.

A hydrogen-to-helium conversion was considered primarily because of condition issues with both the hydrogen cooling system and generator stator. Regarding the former, the original OEM control panel was 50 years old, the hydrogen scavenge system was in poor condition, there was no haz-gas detection for hydrogen and no emergency auto-purge functionality, etc.

Regarding the stator, a rewind was recommended because of its deteriorating condition, polarization index was less than 2 megohms, debris from the degrading asphalt insulation was accumulating at both ends of the stator, glass tape was unraveling on series loops at the collector end, stator end basket was in a weakened condition, etc.

Doyle 1 was tested successfully using helium as the cooling medium on Apr 13, 2018. For verification purposes the machine was operated from a minimum load of 52 to 60 MW while varying reactive power from +30 to -10 MVAr. Helium and field- and stator-winding temperatures were monitored and captured throughout the trial run, along with gas pressure.

Generator temperatures were 20-25-deg-F warmer with helium as the cooling medium than with hydrogen. But the average gas temperature of 166F was well within the Class B insulation maximum temperature requirement of 266F. Helium purity, monitored with in-place calibrated instrumentation, was maintained without need for scavenging; no windage loss was observed. Testing proved the unit could operate with sufficient cooling to the generator, and without operating limitations, while using helium.

During the 2018 summer season, the machine was dispatched 12 times for peaking purposes, operating 57.2 hours. As predicted, a generator fault caused by age and insulation deterioration did occur as the summer was winding down; however, an inspection found not connection between helium cooling and the failure. The bottom line: Testing and operation of Doyle 1 verified the viability of helium as a possible alternative to hydrogen for generator cooling.

Wireless camera keeps extra set of eyes on Mulberry Cogen’s equipment

In any fast-paced O&M environment, there are times when certain pieces of equipment require additional, temporary, periodic observation—such as valves, exposed tank levels, pumps and motors, or even areas of the plant grounds.

Generally, this function is performed by roving operators who must break away from their rounds to travel to the area requiring observation. This can be a challenge, especially if the item requiring enhanced monitoring is located on top of the HRSG or in some other hard-to-access location. Plus, this approach permits critical observation for only as long as the operator can remain at the scene.

Simple solution. Most sites now have comprehensive security-camera systems and a wireless camera for equipment monitoring can be plugged into one of its unused channels, says Plant Manager Allen Czerkiewicz. Mulberry’s wireless camera is moved to wherever needed, allowing the CRO a live look at the area of concern while he or she remains in the control room. The display is viewed like any other camera on the system.

An added benefit is that the camera also records, enabling staff to look back at any event that occurred. After the temporary monitoring assignment is completed, the camera is picked up and brought inside or moved to another location.

The camera has been used extensively since it was purchased, and has been improved by affixing a magnet to the camera base (photo) and by purchasing attachments that allow the it to be installed practically anywhere—from round railings to flat metal surfaces. The camera and receiver are powered from 110-Vac outlets, although a battery-powered inverter can be used in remote locations.

Platform facilitates borescope access, improves safety at Lincoln

The gas turbines installed at Lincoln Generating Facility were not equipped with platforms for accessing the power-turbine sections of the units (photo left). For example, reaching the borescope ports on the lower portion of the turbine required staff to place two planks across the open space as a temporary work platform.

Plant Manager Brad Keaton said that during monthly VPP safety committee meetings this maintenance practice was discussed and participants agreed a change was required. Site personnel developed a work scope and solicited quotes from qualified contractors to install OSHA-approved platforms (photo right).

The safer work area created allows disassembly, inspection, and reassembly of the turbine during borescope inspections. Temporary scaffolding during outages is no longer required. The project has a three-year return on investment.

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