2018 BEST OF THE BEST PRACTICES: Effingham County Power

Recognized for Best Practices in O&M, Safety, Workforce Development, Outage Management

Foam inserts prevent air flow through offline gas turbines

When gas turbines (GT) are shut down for extended periods in Georgia, the high humidity and natural draft through the HRSGs creates problematic condensation on tube fins. Rusting occurs, especially when water is still present in the tubes. Ultimately, excessive tube fin rust creates a resistance to exhaust flow through the HRSG and GT back pressure increases, reducing turbine output.

The staff at Effingham County Power, a 2 × 1 F-class combined cycle managed by Nick Bohl, investigated adding stack dampers, duct balloons, and compressor inlet foam inserts to minimize air flow through the HRSGs. The most effective option would have been stack dampers, but their upfront and ongoing maintenance costs were significantly higher than those for the alternatives. The duct balloon was an interesting and feasible option; however, the time and manpower required for balloon deployment and removal militated against its selection here.

The most economical and effective solution for Effingham, which is owned by The Carlyle Group and operated by Cogentrix: High-density, custom-fitted foam inserts (photo), which prevent air flow through the compressors and HRSGs. Cost of the inserts for both turbines was under $9000; no maintenance is associated with this application.

The inserts were labelled for each unit for inventory purposes. A LOTO is placed on the unit when the inserts are installed to ensure accountability. Once the inserts are removed and counted, a shift supervisor performs a close-out inspection of the GT inlet.

Results from using the inserts are impressive: GT wheel-space temperatures remain above 150F 90% longer using the inserts versus not installing them for a weekend shutdown. Also, HRSG internal temperatures remain above 100F 40% longer with the inserts.

The trapped heat helps minimize condensation on HRSG piping and components. Once the HRSG temperatures are low enough and a dispatch is not expected, the HRSGs are drained. This practice is expected to help reduce corrosion and minimize performance issues.

Installing inserts on Friday following a shutdown saves fuel and increases revenue by allowing faster ramping when the units are restarted on Monday. This is based on less time needed to warm components and quicker steam formation because HRSG drums and piping retain heat longer.

Streamlining I&C learning

Effingham’s web-based I&C training program is supported both by a training bench with various plant instruments for hands-on experience and a supervising subject-matter expert. The plant SME is responsible for training technicians on the software and the test and monitoring equipment they will use on a daily basis.

The existing web-based training program was considered inadequate because it included outdated monitoring and test equipment which was not plant-specific, delaying the qualification process because of a lack of reference material and available training lessons.

Without reading the actual O&M manuals there was nothing in place to prepare technicians for hands-on training or instrumentation calibrations. And without actual test equipment and monitoring-device training there was limited reference material. Once the technicians were qualified they had to rely on their notes and read the O&M manuals to complete the required proficiency training.

Aiming at a solution, the I&C SME developed a list of things technicians need to know to become proficient in calibrating Effingham’s instrumentation. This information in hand, the web-based training courses were evaluated for their applicability to the plant’s mission. The most pertinent courses were grouped into eight modules.

Fourteen PowerPoint presentations then were created to train individuals on plant-specific instrumentation, calibration equipment, calibration software, and proper calibration techniques. These presentations were reviewed by qualified I&C techs for content and effectiveness and then added to the eight web-based training modules to form a structured plant-specific I&C fundamentals training program.

Exams were created to help reinforce the knowledge learned. Job performance measures (JPM) also were developed to evaluate the technician’s ability to perform calibrations on various monitoring devices. Since the SME uses these JPMs to certify the technician’s abilities, each individual is evaluated using the same standard.

The streamlined, updated program is highly regarded for the following reasons:

    • Covers more areas of I&C than previously, producing better-trained technicians.

    • Provides self-guided reference materials, which allow the technician to build confidence and education to ask the right questions. This helps both the SME and the qualifying technician.

    • Has a training bench that allows technicians to practice calibration techniques online or offline rather than in the plant, minimizing the possibility of lost generation.

Finally, as new test equipment is purchased, training presentations and exams are developed and implemented. The training program is continually evaluated for its content and ability to train plant personnel. Since Effingham owns the training program it can be revised as needed at minimal cost.

Outage management improves with delegation of job leads

In the past, contractors interacted only with the maintenance supervisor and/or shift supervisor when onsite for outages. This created bottlenecks because each contractor needed to meet with the same one or two individuals to receive plant support—such as having LOTOs in place, preparing hot-work permits, inspecting work areas, retrieving parts and materials for the job, etc.

Significant man-hours were wasted while each contractor waited its turn to speak with the one or two management personnel conducting the outage. Since Effingham’s outages are necessarily brief, staff discussed ways to streamline the process and maximize contractor productivity.

Once the maintenance supervisor has awarded the job to the contractor, a technician is assigned as the contractor’s job lead. The technician typically is selected based on his or her subject-matter expertise. It is important for this individual to adequately support the contractor and to understand the basic job scope.

The expectation is for the two parties to communicate by phone or email prior to the outage to discuss the job and how it will be completed. Once the job lead understands the scope of the job, the plant can prepare for the contractor’s arrival.

Onsite, the job lead and contractors meet and the job lead ensures the safety orientation has been completed. The job lead is responsible for ensuring the LOTO is walked down with the contractor and if there are any discrepancies, they are resolved prior to the workers signing onto the LOTO. If any confined-space or hot-work permits are required, the job lead makes sure they are in place each day the contractor is onsite.

The contractor and job lead meet daily onsite to discuss the day’s plan and job status. If the contractor needs any parts or materials, the job lead is contacted and those items are delivered to the appropriate location. The contractor doesn’t lose man-hours searching for help, it just contacts the job lead to get the needed support to complete the job on schedule.

This process proved valuable while conducting a major outage in 2016, in which Effingham had over 350 contractors onsite. When the contractors arrived, they exchanged phone numbers with their job leads (if they had not done so already), and when assistance was needed, it was necessary to make only one call and never leave the worksite.

Proper greasing protects bearings, reduces maintenance cost

To reduce motor repair costs and avoid possible lost generation, plant had to improve its method for greasing large frame motors. Effingham’s local motor repair shop reported that several motors sent for repair had little to no grease in their bearings. Typically, all bearings were receiving the same amount of lubricant; however, lubrication should be based on bearing size and the manufacturer’s recommendations. A system of greasing bearings that took into account these differences was necessary.

The proper amount of grease for any given motor or bearing was found by using the motor and bearing manufacturers’ data sheets, in addition to information available on the motor data plate. Nameplate data on most motors include bearing identification numbers which can be cross-referenced to reveal bearing size, configuration, and lubrication requirements.   

Personnel also measured the output of the plant’s grease guns by weighing the grams per pump to determine how many pumps per gun it would take to achieve the recommended amount of grease per application. Once they knew how much grease the gun applied per pump, staff calculated how many pumps it would take to provide the required amount of grease in a given application. Labels then were affixed to the grease guns to provide the information required by technicians performing the lubrication PMs.

Next, technicians stamped stainless-steel tags—they resemble dog tags—with the lubrication information and attached them to the motors with stainless-steel chains. Having this information right on the equipment saves time and ensures the proper type and amount of grease is used.

Proof of success: When performing operator rounds, a technician discovered that a cooling-tower fan motor had some bearing noise. He added grease based on the old method of one to two pumps from a grease gun. Several technicians then researched the amount of grease recommended by the bearing manufacturer. As a result of their investigation, more grease was applied and the problem was resolved. Since program implementation, technicians have performed several successful greasing PMs.

Standardizing data on fire extinguishers benefits recordkeeping, compliance  

The date of manufacture is required on fire extinguishers, but there is no standard format or location on the bottle for this information. Some extinguishers are labeled on the bottom, some have the information mixed with other data in code on the bottle, and some have the date on the printed label, which fades and peels in outdoor applications. The manufacture date is required to establish requirements for six-year inspections and periodic hydro testing mandated in NFPA regulations.

Personnel contacted various manufacturers to identify the location and format of the manufacture date on their extinguishers. Embossed metal tags were added to each fire extinguisher on the hose or neck, identifying the later of the date of manufacture, date of last six-year inspection, or date of last hydro test. Date information also was added to the fire-extinguisher inspection checklist for annual inspections, to aid in identifying periodic maintenance requirements.

Benefits are ease of inspection and recordkeeping, simplified maintenance procedure, and assured compliance with applicable NFPA requirements. Labor cost also is reduced because it’s now easy to find this information when performing monthly and annual fire-extinguisher inspections. Plus, budgeting is more accurate knowing when the fire extinguishers will be serviced.

Color coding helps identify proper oil for a given piece of equipment

Plant was having difficulty maintaining labels on secondary oil containers. The markings were fading or the labels would come loose and fall off because of contact with the oil. Proper fluid identification is important to avoid contaminating oil used in other equipment. Cross-contamination can lead to premature wear or even catastrophic failure.

Because several different oils are used in the plant, a procedure was needed to ensure the correct oil was added to each piece of equipment. In the past, the auxiliary operator would look up which oil was required when finding a low oil level during rounds. Plant needed a way to ensure the correct oil was added; also, to expedite the process to ensure bearings were lubricated properly.

The optimal solution was to assign each type of oil a specific color code. This color then was painted on the storage container used by operators to replenish oil lost during operation as well as on the fill ports of the equipment requiring that particular oil. Since these containers were used for only one type of oil, a durable laminated tag was attached to the handles so the oil could be stored and used as needed.

Today technicians do not have to clean containers prior to use because the labels are securely attached, and the contents properly identified, minimizing waste. Cross-contamination of oils is avoided by verifying that oil is added to the proper secondary containers by reviewing the labels.

Technicians use the preventive-maintenance work order and lubrication chart to verify the proper oil needed for a given piece of equipment. Having the ability to verify the same color on the container and the fill port is a good back-up check.

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2018 BEST OF THE BEST PRACTICES: Green Country Energy

Recognized for Best Practices in Environmental Management and Safety

Design hazardous-spill response plan for worst-case scenario

Nearly all plants have a plan for addressing hazardous spills. Many, like 801-MW Green Country Energy (GCE), owned by J-Power USA and operated by NAES Corp, have a comprehensive spill-prevention control and countermeasures plan that identifies areas where spills could happen, as well as appropriate responses to them. The challenge is to develop a plan which takes into account the location, weather, and staffing conditions that would be present at the time of a spill event.

A successful plan is one that can easily and quickly be executed by anyone at the facility. It should require very few steps to complete and ensure the safety of those involved. Plus, it should deal effectively with any spill—small or large.

At GCE, personnel have worked to improve the plant’s plan so it meets all the criteria mentioned above. In the process, however, staff began to identify obstacles fundamental to the success of other engineering necessities.

To illustrate: A modern, well-designed facility typically would engage with civil engineers to design flow paths and drainage channels that direct rainwater quickly to storm-water drains to prevent site flooding during heavy-rain events. But many facility drainage systems take rainwater quickly to underground piping systems, never to be seen again onsite.  These well-designed and engineered systems actively work against the ability to properly manage a spill. Site spill plans must take this into account.

At GCE, any spilled material would enter the storm-water system swiftly, leaving very little time to contain the spill. During a major rain event, that time would be reduced even more. Staff, led by Plant Manager Danny Parish, assumed that storm water would be present during a spill and incorporated that into the plant’s control plan.

Another thing considered in creating a sound spill plan was the design of containments and containment drains. At GCE, transformer containments all have administratively controlled drain valves. Following a rain event, operations personnel visually inspect the water in the containments to ensure there is no oil or other contaminants. They then open the drain valve, which allows rainwater to flow to the oily water separator.

Some sites—not GCE—have position-indicating valves (PIVs) for these drains that visually indicate whether the valve is closed or not. It is critical to keep containment drains closed during normal operations so that, in the event of a spill, the containment can do its job. The lack of position indicators on underground containment drain valves at GCE created an opportunity for an administrative error. Thus, the plant’s plan required continuously visible indication on these valves so the operations team could ensure that they stayed closed at all times.

Another major consideration for GTC was that, during evenings and weekends, only three employees man the entire 20-acre site, home to three 1 × 1 F-class combined cycles. One stays in the control room, and the other two split their time between equipment rounds, readings, small maintenance projects, and other operations duties. This dictated that the plant’s spill plan be easily and safely executable by no more than two employees.

Spill containment solution: GCE has a back-flow preventer at the Arkansas River discharge location that provides an isolation point for all of the water flowing from the plant (Fig 1). The challenge was to find a simple, cost-effective means of installing a positive closing device at this point. Staff decided on an I-beam strongback with a modified handwheel designed to put positive closure pressure on the back-flow flap. Technicians designed and engineered this device using scrap material and parts from an old valve.

The largest expense was the rubber sealing material placed between the cast-iron flap and the 48-in. pipe lip. To ensure that any employee could close this valve, a platform with a slip-resistant grating and handrails were installed to allow safe access in any weather (Fig 2).

The drain-valve indicator issue was addressed by replacing all gate valves with one-quarter-turn butterfly valves. Extension handles then were fabricated to assure quick, easy valve operation. The handles are retractable to eliminate any trip hazard (Fig 3). The positions of the valves now can be seen at all times, allowing the operations group to ensure all drains are opened only during rainwater draining events.

Plant continues to use floor-drain covers, absorbents, dikes, dams, and diversions to mitigate small spills—but only after the back-flow flap has been closed.

How to excavate safely in high-risk areas

Safety is a core value at Green Country Energy (GCE) and identifying opportunities for safety improvement projects is a big part of what staff does on a daily basis. Many of these are simple to execute. Some take a little more time and planning; occasionally personnel face a safety-improvement opportunity that seems impossible to implement. Such was the case with installing protective bollards around the plant’s natural-gas supply.

Staff identified the need for bollards early on because the gas line is located at the plant entrance. Delivery trucks pass within 10 to 15 ft of it, and vendors, contractors, and other visitors pull into the administrative parking areas and then back up next to the line. The odds of someone hitting it are not great, but if they did, it could be catastrophic.

Plant personnel collaborated on a design. The bollards would consist of 8-ft lengths of 6-in.-diam steel pipe set vertically in the ground to a depth of 3 ft, then filled with concrete and painted bright yellow. If a truck or other vehicle were to make a navigational error near the gas line, the bollards would both protect it and minimize negative consequences to personnel and equipment.

The plant has many similar bollards to protect other equipment—such as the bulk hydrogen storage tank and fire hydrants. Most of these were installed during construction, some were added later.

Locating the bollards was complicated. A review of underground drawings showed the gas line came out of the ground right next to the plant’s gas chromatograph. Also, a storm-water drain was located just east of the line and a series of conduit runs were just to the north for conveying gas flow-meter and chromatograph data to the control room.

In addition, the bulk hydrogen line to the generators was routed through that area. Then there was the plant ring road alongside the gas line. If the bollards were moved far enough away from the gas line to clear all of these obstacles, they could pose more of a hazard to plant mobile equipment and personnel than the gas line itself.

The risks associated with any sort of conventional excavation appeared to outweigh the safety value of the bollards. Hand-digging in this area looked all but impossible because of the hard clay and rock. Result: The project was considered too risky to undertake and was put on hold for several years.

In 2017, plant management recommitted to installing the safety bollards around the gas line. After researching possible workarounds, a hydrovac services company was engaged to excavate the foundation holes. It relies on high-pressure water to loosen the soil, rock, and clay while simultaneously using a vacuum pipe to pull the loosened material out of the hole. This approach was effective and did not damage any underground cable, conduit, concrete, piping, or other critical equipment encountered (Fig 4). Excavation was fast, safe, and cost-effective, and GCE now has a fully protected gas line (Fig 5).

But unexpected things have a way of turning up when excavating in an industrial setting. This project was no exception. When digging the final bollard hole in a location that had no known obstacles, a buried pipe was found. It turned out to be the control-room sewage lift station line and was not on any of the drawings. Hydrovac spared the plant a messy and expensive outcome, reinforcing staff awareness that all excavations involve risk.

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2018 BEST OF THE BEST PRACTICES: Hermiston Generating Plant

Recognized for its Best Practice in Outage Management

Self-performing combustion inspections strengthens plant’s bottom line

The days of having long-term service agreements (LTSAs) that coexist with power purchase agreements (PPAs) are vanishing. Many of these contracts in older facilities have expired or are approaching expiration. Private-equity firms with stakes in these plants are looking at maximizing their returns on the assets.

Strategic independent power producers (IPPs), such as Hermiston Generating Plant (HGP)—a 2 × 1 F-class combined cycle owned by Perennial Power Holdings and PacifiCorp—want to strike a balance between short-term return and long-term sustainability, while keeping critical infrastructure in a healthy condition. Given parent company support, the greatest impact on returns managed at the plant level is major maintenance. Developing a major maintenance strategy that positively impacted fixed costs was the challenge at HGP.

Shortly after the plant’s LTSA expired with the OEM in 2016, the plant experienced a combustion issue in one of its two gas turbines. A borescope inspection revealed damaged diffusers on several fuel nozzles. The plant management team, led by PM Brad Knight contracted a third-party technical advisor (TA) to assess the issue. Because of time constraints, management decided to “self-perform” the outage. Nine fuel-nozzle assemblies were replaced in three shifts using four O&M technicians under the guidance of a TA.

The cost saving was significant and prompted HGP to contemplate performing all future combustion inspections with in-house labor. But before implementing an in-house outage program, the following considerations had to be evaluated:

    • Safety.

    • Training.

    • Cost.

    • Schedule.

    • Experience.

    • Tooling.

    • Parts availability and sourcing.

    • Reliability.

Here’s what the plant staff learned:

Safety. By using plant personnel, many safety issues were avoided. Staff already had a solid working knowledge of “site specific” safety procedures, policies, and issues. Addressing job-specific hazards was HGP’s primary objective. Job hazards included, but were not limited to, rigging and fall protection, already a focus in pre-outage classroom training. These outage operations are monitored closely by a third-party TA and HGP management during disassembly/reassembly. HGP’s safety approach resulted in zero accidents and zero near misses during both CIs.

Training. Prior to the 2017 outage season, HGP engaged a third-party to conduct a 40-hr training program on combustion inspections with the outage team. Operators were instructed gas-turbine theory, rigging, IGV calibrations, torqueing, parts function and familiarity, specialty tool usage, inspection and maintenance guidelines from GEK 107535, and quality control and assurance.

Cost. Combustion-inspection costs vary among vendors—ranging from about $140k to $170k each (not including the cost of hardware, consumables, or parts refurbishment). Note that no crane costs are incurred at HGP because the plant was constructed with overhead cranes. HGP performed two CIs with four O&M technicians, one third-party millwright, and a third-party TA in seven shifts at a cost of $51k per CI (Fig 1). Plant realized a median cost saving of $114k per CI.

Schedule. Self-performing outages allows more schedule flexibility. Plant management is able to shift the outage schedule without costly contractor penalties or contractor unavailability. Outages may be moved slightly depending on real-time market opportunities. The facility is also able to immediately address forced-outage situations rather than waiting for contractors to mobilize.

Experience. HGP has a tenured staff with very little turnover. Combustion inspections are performed every 8000 to 8800 operating hours. During outages, all O&M technicians are assigned to the maintenance department (with the exception of two control room operators). A select group of O&M techs were permanently assigned to the outage team, which meets regularly to discuss ways to mitigate risk and improve overall outage performance (Fig 2).

Morale. Staff’s ability to successfully perform planned and unplanned outages has fostered a higher level of confidence, knowledge, and self-reliability among plant personnel.

Tooling. HGP constructed a portable crib for the tools recommended in GEK 107535 . The trailer, designed by and for the O&M techs on the outage team, is equipped with tooling, consumable parts, office space, and break amenities (Fig 3). It is staged adjacent to the turbine compartment during outages.

Parts availability and sourcing. By self-performing, HGP is not restricted to using specific vendors. Purchasing is able to negotiate more reasonable costs and decreased lead times. HGP also carries a large inventory of spare parts. With the familiarization of turbine maintenance, each member of the team is able to quickly identify and procure parts as needed.

Reliability. Strict QC policies and second checks were implemented to prevent oversight. Since implementing the self-performed CIs, the facility has achieved an EFOR of less than 1% and a starting reliability greater than 98% (201 successful starts in 204 attempts) through the end of 2017.

To sum up, every aspect of the self-perform CIs had a positive impact. All future combustion inspections at HGP will be performed by plant personnel. Looking ahead, management is evaluating the need for TA services during the next CI.

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2018 BEST OF THE BEST PRACTICES: Minnesota River Station

Recognized for its Best Practice pertaining to Electrical Systems

Upgrades to non-segregated bus duct help prevent faults

Two electrical faults occurred on a 13.8-kV bus within five years at Minnesota Municipal Power Agency’s Minnesota River Station, operated by NAES Corp. In both incidents, the solid copper bus and ductwork sustained extensive damage, resulting in lengthy forced outages. Figs 1 and 2 show the burned red insulator boots and damaged metal duct covers at the fault location.

During the first incident, the plant team, directed by PM Bob Burchfield, coordinated with the OEM and determined that the section of bus where the fault occurred had insufficient heating. Two new heaters were installed and inspections were scheduled more frequently.

Five years later, a fault at a different location required a more extensive investigation and more robust defense. Both events had occurred during conditions of extreme humidity with heavy rainfall and dew points above 73F.

A third-party engineering firm determined that the bus was designed for relative humidity of 95%. However, relative-humidity levels routinely exceed 95% during the spring and summer months in the region. Ductwork is vented to atmosphere through small screened holes, exposing the bus to ambient weather conditions.

While making repairs after the second incident, staff noticed that the OEM had modified the replacement parts. The red insulating boots now had the tie-wraps at the sides rather than on top. Previously, they had allowed moisture accumulating on the upper cover to drip into the seams and onto exposed copper bus. The OEM had also modified the metal duct covers to create more overlap, particularly on the corners.

After the plant had completed repairs with improved OEM parts and added another space heater, the insulation readings still remained below acceptable values. Infrared imagery revealed that the heaters added negligible heat to the actual duct. Staff also noted that the new heaters purchased from the OEM were installed inside the duct with minimal clearances from the bus, apparently to make them more effective.

After heating the bus for a prolonged period following repairs, technicians found that phase-to-ground resistance readings remained below acceptable limits. They injected dry air overnight using a makeshift regulator and hose, which significantly improved insulation and permitted the bus to be energized safely.

Given the success with this arrangement, technicians designed a dry-air supply system for permanent installation and wrote an operating narrative explaining multiple safeguards and interlocks to prevent over-pressure and use of a permanent dry-air injection system to prevent moisture entry. The slight positive pressure created by injecting air, they noted, is an added benefit of the injection system.

Staff learned from the repair contractor that many sites in the region had experienced similar failures, and in some cases, simply doubled the number of space heaters as a corrective action. However, Minnesota River ruled out the “additional heaters” option because the OEM’s new locations for space heaters inside the bus provided less than 4 in. of clearance between the bus and ground. The IR images showed the heaters were less than effective at increasing the temperature inside the duct, even at that proximity.

To be on the safe side, the technicians’ proposed air injection system was reviewed by a qualified third-party engineering firm and by management. Injection of dry air typically is reserved for isophase bus ducts, so there were concerns about applying this solution to a non-segregated bus duct—especially since non-seg bus covers are fastened with screws and not necessarily designed for positive pressure.

Recall that isophase bus duct generally is constructed of welded tube with only one conductor per duct.

In their narrative, the technicians explained how they would provide equal flow to each injection point using instrument throttling valves and a flow meter to measure the incremental air-flow increase at each injection point. At the same time, they confirmed low pressure with sufficient air flow by observing a small amount of the air exiting the duct from each vent/drain hole.

The following three-pronged approach was taken to prevent water from entering via the supplied-air system:

    • The team recognized that any malfunction of a regenerating dryer tower could allow water to enter the instrument air piping from the air compressors. Technicians didn’t completely trust the installed plant dryer tower, so they proposed adding a tap to the top of the instrument-air receiver tank plus another dryer tower dedicated solely to the non-seg bus duct (Fig 3).

    • Staff also procured and installed a dedicated dew-point analyzer and programmed it to shut off the air-supply solenoid at a predetermined set point. The normal dew-point temperature downstream of two dryer towers is very low, so a conservative shutoff set point of 0F was selected. Part of the logic in being this conservative was that the dew point remains relatively constant in the new system, so a change of any appreciable amount could indicate a problem.

    • Air is injected at each space heater box located below the bottom bus cover; dry air enters the bus duct through perforated holes above the heater. If water reaches this box from the air supply, it has a last chance of removal through the bottom screened hole (Fig 4).

The sheer size of this particular bus factored into the solution. The duct measures approximately 200 ft long and consists of three different sections. It is heated by 25 space heaters powered by two separate 120-V circuits; each heater draws slightly more than 1 amp.

The team procured and installed a current monitoring device. If any heater open-circuits, the current draw will drop by 1 amp. If an entire heater circuit trips, the new panel will display a loss of current. An alarm was not provided because a thermostat periodically will shut off heaters at 95F and this would cause nuisance alarms.

The dry-air injection system has been in place for two years. During a series of severe storms in 2017 that brought heavy rains, 80- to 100- mph winds, and many days of high relative humidity there was no arc-tracking and no evidence of moisture intrusion. Phase-to-phase and phase-to-ground insulation resistance readings remain much higher than pre-installation values. Staff needs more time to fully determine the new system’s effectiveness, but if it had not been in operation during last year’s extreme weather, another electrical fault likely would have occurred.

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2018 BEST OF THE BEST PRACTICES: Ontelaunee Energy Facility

Recognized for its Best Practice in Performance Improvement

Water-wash program gives year-round benefit

A new powerplant with no leaking valves and latest-technology equipment generally doesn’t have to be concerned with losing a few points in its heat rate. Add 15 years of operation and that measurement of plant efficiency takes on a whole new meaning. One of the best ways to keep efficiency as high as possible is to maintain the equipment in the best possible operating condition. For gas turbines, that includes a clean compressor.

Like many other plants powered by gas turbines, Ontelaunee Energy Facility, a 2 × 1 F-class combined cycle owned/operated by Dynegy Inc and managed by PM John Goodman, relies on springtime offline water washes to regain compressor efficiency losses. Offline water washes would show remarkable improvement, but as the turbine ran, the compressor would foul and efficiency would slowly creep downward. Determined to find a way to maximize efficiency longer, Ontelaunee began an online water-wash program.

Initially, the program focused on performing water-only rinses three times a week. Result: Efficiency did not decrease as quickly as before. However, once temperatures began to drop in the fall, the water-wash skid was winterized and remained out of service unit the annual offline wash in spring.

In 2017, Ontelaunee decided to make the online water wash program more robust. This included performing online water rinses daily and online soap washes weekly. Both the rinses and washes were conducted in accordance with OEM recommendations. This compressor cleaning program gave good results, efficiency remaining close to what is was immediately after an offline water wash.

However, staff was concerned about the wintertime, when ambient temperatures would drop below the suggested minimum washing temperature. The OEM’s water-wash procedure has a recommendation for using anti-freeze—either ethylene glycol or propylene glycol. But past experience with glycol-based anti-freeze was that it had a negative effect on gas-turbine emissions. Not wanting to risk an emissions exceedance, the plant sought a different solution.

Ontelaunee planned to install an inlet bleed heat (IBH) system to combat air-filter clogging which could occur during snow events. With the PJM implementing a “capacity performance” segment, penalties for forced outages and derates attributed to filter clogging became a major financial concern. In 2016-2017, the IBH system, designed by PSM, was installed. The immediate benefit of preventing filter clogging was realized, but staff saw a possible additional opportunity for performance improvement.

Staff reasoned that if the IBH system could raise inlet scroll temperatures to prevent bellmouth and Row 2 compressor-blade icing, it might increase the air temperature enough to continue online water rinses in cold weather. It did. Today, anytime the ambient temperature is above 35F, IBH can raise the inlet temperature enough to permit an online water rinse. This allows the water-wash program to continue year-round, enabling the plant to maintain a competitive heat rate.

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2018 BEST OF THE BEST PRACTICES: River Road Generating Plant

Recognized for its Best Practice in O&M and Safety

Retrofit air-inlet filter house for emergency egress

River Road Generating Plant (RRGP), 1 × 1 F-class combined cycle operated by GE for Clark Public Utilities and managed by PM Todd Gatewood, was built in 1996-1997. The legacy four-level air-inlet filter house was installed with no emergency egress. During outages, personnel occupy the filter-house space during filter removal and replacement. Fleet experience has demonstrated that filter media and the dust collected by the filters can be highly combustible.

Had a fire started, the only escape path was via internal ladders from one platform level to another, then through a 2 × 3-ft manway exit on the lowest level. This represented a significant safety issue for anyone involved in the filter replacement process, the control room personnel directly adjacent to the filter house, and the personnel in the office space below.

The challenge was to determine the best method of egress, taking into consideration the limitations presented by the existing structure—including office space directly below the filter house. The entire RRGP team was involved in brainstorming sessions. Some ideas were rejected outright because of code or practicality considerations—including emergency zip lines and doorways on each platform with access to a “fire pole”.

The decision was made to proceed with a project that included cutting doorways at each level, plus an external platform and ladder arrangement in combination with an intumescent coating on the interior wall and doors of the filter house. The challenge was designing and building a structure to suit the plant’s safety needs while designing around existing structures below the filter house (Figs 1 and 2).

Following an extensive fire safety code and structural engineering analysis, a custom emergency egress was designed, pre-fabricated, assembled, and installed (Fig 3). This reduced the personnel concern regarding rapid egress. The retrofit external platform and ladder assembly eliminated the safety hazard of the internal “trap door and ladder” access system supplied with the original filter house.

A process failure-modes effects analysis (FMEA) was completed. Prior to the retrofit, the total risk priority number (RPN) was 784. Following completion of the retrofit, the RPN was 150.

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2018 BEST OF THE BEST PRACTICES: Terry Bundy Generating Station

Recognized for its Best Practice in Performance Improvement

Steam-turbine rotor/case upgrades and heating system extend outage intervals

Lincoln Electric System’s Terry Bundy Generating Station is dispatched primarily to address peaks in the SPP market, resulting in daily on/off cycling. In 2016, the steam-turbine OEM significantly increased the equivalent operating-hour (EOH) factor for cold starts on the plant’s 2 × 1 combined cycle. The new cold-start EOH factor would have required major inspection/maintenance cycles for the steamer every seven years, costing more than $7.6 million over the next 25 years.

Staff evaluated the benefits of reducing the number of “cold” starts and associated maintenance cycles by upgrading turbine components and installing a turbine case/rotor heating system. 

Project scope covered the evaluation of mechanical modifications to the turbine rotor and installing a turbine rotor/case heating system to allow the unit to remain in hot standby mode for multiple days after coming offline. The overall goal was to improve unit operating economics and reduce the equivalent operating hours associated with cold starts, thereby cutting maintenance costs by extending the interval between major inspections. Rotor mods reduced the original cold-start EOH penalty from 530 to 235 EOH.

The turbine modifications included machining the rotor ends to increase case clearance, modifying the blade root configuration, changing the geometry of the thermal relief groove, and installing upgraded blades. The heating system maintains the steam-chest temperature at 650F, further reducing the EOH penalty for a start to 36 EOH.

A key requirement of the project was designing a monitoring system to estimate rotor temperature. The main challenge here was that the dual-case design of the turbine made it difficult to accurately measure turbine temperature. Working with the turbine OEM, seven additional thermocouples were installed in the turbine-case HP and IP sections, including one which extended into an HP inner-case structure.

This allowed the system to assign the correct EOH factor for hot (644F and above), warm (266F to 644F), and cold starts (less than 266F) based on actual rotor condition. The original EOH factor system used the amount of time since shutdown to determine which factor to apply to the next start.

The heating system, designed to bring the turbine from a cold condition to 260F using approximately 2067 kWh of energy, consists of 19 heating-blanket zones that are sequenced on and off depending on measured case/rotor temperature and time since the unit was taken offline.

The zones are sequenced to maintain the turbine at 675F from the time the steam turbine is taken offline until 96 hours have passed. It then lowers the maintenance temperature to 575F for the next 72 hours. Finally, the system holds the turbine at 375F for 48 hours before allowing the temperature to decay to ambient.

In addition to extending the interval between maintenance periods, the heating system reduced the steam-turbine dispatch time by 45 minutes. The shorter dispatch time improved unit economics and will potentially lead to better market utilization of the generating resource.

Economic analysis of the benefits of this system indicate over $5.5 million in total savings from extending the maintenance intervals. The economic benefits of the shorter dispatch time have not yet been quantified. Plant Manager Jim Dutton and his team are still evaluating the amount of energy, and associated cost, for heating-system operation.

Project cost breakdown

    • Heating system design, installation and commissioning: $1,263,764

    • Estimated net present value of maintenance-cost reduction: $5,538,000

    • Peak heating electrical demand: 150 kW

First hold temperature, trip to 96 hours.

    • HP end section, 650F.

    • Steam chest, 675F.

    • IP end section, 375F.

Second hold temperature, 97 to 168 hours.

    • HP End section, 550F.

    • Steam chest, 575F.

    • IP end section, 275F.

Third hold temperature, 169 to 216 hours.

    • HP end section, 375F.

    • Steam chest, 375F.

    • IP end section, 200F.

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2018 BEST OF THE BEST PRACTICES: Tuxpan II and V

Recognized for its Best Practices in Safety and O&M

Outage safety benefits from community outreach program

People living in the communities near the Tuxpan F-class 2 × 1 combined cycles in Veracruz, Mexico, are a critical resource for the company. Management is concerned that local residents know what to do in an emergency and how to deal with safety-related issues encountered in their daily lives.

Plant owners Electricidad Aguila de Tuxpan and Electricidad Sol de Tuxpan sponsored safety training programs for area residents and for so-called “safety watchers” to assist plant personnel during outages. NAES Corp, the Tuxpan II and V operator, implemented the core safety training program for 80 residents. It was conducted by personnel with extensive experience in industrial safety; participants completing the program received a certificate.

Lessons were presented on what to do in an emergency, firefighting, CPR, types of fires and fire extinguishers, hazard and risk identification, differences between hazardous and urban wastes, etc.

Four groups of about 20 participants each were trained in one month. Goal was to increase knowledge of safety issues and to ensure a good relationship with stakeholders. The top performers in the community training program were invited to be part of a group of safety observers who would participate in the Tuxpan II fall outage by supporting NAES management in the supervision of contractor personnel.

Prior to the outage, the safety observers were trained to monitor specific issues. When the outage began, the safety watchers, supervised by the NAES HSSE team and training personnel, were divided into groups—first in day and night shifts, then in key areas.

Watchers had the task of giving safety recommendations for each unsafe act or condition detected, first addressing the worker to correct it, then the contractor´s safety supervisor to prevent it from happening again, and finally the NAES supervisor to integrate the incident into the safety statistics to improve or control it.

Excellent results were obtained with the safety watchers, said Plant Manager Jorge Gamel Esparza Cárdenas, PE. They helped the HSSE team prevent a lost-time incident during the 35-day outage. Here are the stats:

    • Good practices cited, 115.

    • Drug and alcohol tests, 6796. There were 10 positive results for alcohol, three for drugs.

    • Unsafe acts and conditions reported, 233.

    • Near misses, 6.

    • Safety inspections conducted, 192.

    • Minor first aid (health issues, headaches, flu, etc), 139.

    • First aid (safety issues), 2.

    • Medical treatments, 1.

    • Lost-time incidents, 0.

    • Incidents closed, 232.

    • Average number of persons onsite during the daytime, about 360.

    • Average number of persons onsite during at night, about 100.

Backwash plate-and-frame heat exchanger to boost performance

The OEM’s operating procedures provide NAES a safe way to isolate Tuxpan’s closed-cycle plate-and-frame heat exchangers for cleaning when heat-transfer surfaces are fouled and cooling duty cannot be maintained. However, these procedures require mechanical disassembly of the exchanger and washing each plate in turn because the backwash procedure provided was not effective.  

The new procedure implemented by NAES allows washing of the heat exchanger without disassembly. Benefit of backwashing is that it extends the interval between manual cleanings, thereby reducing the cost of maintenance by about $30,000 annually. Procedure details are available in the 2Q/2018 issue of CCJ’s print edition, now in production.

Note that the wind and currents at the plant’s coastal location affect the amount of dirt carried by seawater into the heat exchangers. In a typical year, cleaning would be required 10 to 15 times. Today, backwashing is initiated only when the temperature of the closed-cycle cooling water rises to the point where cooling becomes inefficient.

Rigorous test regimen for valves assures reliable GT starts

“Tests of Safe Start with Gas Fuel in the Gas Turbines” are conducted to assure reliable starting and to avoid delays in commissioning by verifying both proper physical operation and logical response of the main valves involved in starting and operating the engines

Safe-start tests are conducted on valves such as the following:

    • Fuel gas system.

    • Main flow control.

    • Fuel gas vent.

    • Turbine fuel-gas shutoff for protection against gas-turbine overspeed; plus confirmation of overspeed trip reset.

    • High-pressure bleed.

Testing has contributed to the detection and correction of abnormal variations in response of the valves to control logic, physical abnormalities of movement, and other situations in a timely manner for correction before turbine start. Dead times have been reduced, failed starts avoided, and turbine damage prevented.

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